british columbia transmission corporation application to · pdf filebritish columbia...

DM_VAN/260254-00040/6782723.2

BRITISH COLUMBIA TRANSMISSION CORPORATION APPLICATION TO AMEND THE OPEN ACCESS TRANSMISSION TARIFF

AND

TRANSCANADA COMPLAINT

BOOK OF AUTHORITIES OF BRITISH COLUMBIA TRANSMISSION CORPORATION

May 29, 2009

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DM_VAN/260254-00040/6782723.2

INDEX TO AUTHORITIES

TAB

Statues:

1. Utilities Commission Act, R.S.B.C. 1996, Chap. 473, sections 59-61

Cases:

2. An Applicaton by British Columbia Hydro and Power Authority for Approval of its Wholesale Transmission Services (April 23, 1998) Order Number G-43-98 (BCUC)

3. British Columbia Power Exchange Corporation, 78 FERC 61,024 (1997)

4. Commonwealth Edison Company, 96 FERC 61,158 (2001)(Order Denying Rehearing)

5. ConocoPhillips Company v. Entergy Services Inc., 124 FERC 61,085 (2008)

6. Constellation Power Source, Inc., 102 FERC 61,142 (2003)

7. Consumers Energy Company v. FERC, No. 03-1162 (D.C. Cir. May 2004)

8. El Paso Electric Company 84 FERC P 63,008 (Administrative Law Judge Decision, 25 August 1998), affirmed in part, vacated in part, reversed in part by 87 FERC P 61,202 (1999)

9. Exelon Generation Company, LLC v. Southwest Power Pool, Inc., 101 FERC 61,226 (2002)(Order Denying Rehearing)

10. H.Q. Energy Services Inc., 125 FERC 61,140 (2008)

11. H.Q. Energy Services (U.S. Inc.), 79 FERC 61,152 (1997)

12. Mandatory Reliability Standards for the Calculation of Available Transfer Capability, 126 FERC 61,249 (19 March 2009) (Notice of Proposed Rulemaking)

13. Oklahoma Gas and Electric Company and NRG McClain LLC 115 FERC 61,350 (2006), paras. 29, 30

14. Ontario Energy Trading Int'l Corp., 99 FERC 61,039 (initial order), on reh'g, 100 FERC 61,345 (2002), on reh'g, 103 FERC 61,044 (2003)

15. Ontario Hydro Interconnected Markets Inc., 83 FERC 61,348 (1998)

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TAB

16. Promoting Wholesale Through Open Access Non-Discriminatory Transmission Services by Public Utilities Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 79 FERC 61,367 (1997)(Order Denying Motion for Stay)

17. TransAlta Enterprises Corporation, 75 FERC 61,268 (1996)

Large Cases Available Online:

OASIS: Open Access Same-Time Information System (formerly Real-Time Information Networks) and Standards of Conduct, (1996) 75 FERC 61,078 (Order No. 889)

Available online at: http://www.ferc.gov/legal/maj-ord-reg/land-docs/order889.asp

Preventing Undue Discrimination and Preference in Transmission Service, FERC Stats & Regs. ¶ 31,241 (Feb. 16, 2007) (Order No. 890), order on reh’g, 121 FERC ¶ 61297 (Jan. 16, 2008) (Order No. 890-A), order on reh'g, 123 FERC ¶ 61,299 (June 23, 2008) (Order 890-B); order on reh’g, 126 FERC ¶ 61,228 (March 19, 2009)

Exhibits B1-5-1, B1-5-2, B1-5-3 and B1-12.

Available online at: http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp

Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 75 FERC ¶ 61,080 (1996) (Order No. 888), order on reh’g, 78 FERC ¶ 61220 (March 14, 1997) (Order No. 888-A), order on reh’g, 81 FERC 61,248 (1997) (Order No. 888-B), order on reh’g, 82 FERC ¶ 61,046 (1998) (Order No. 888-C)

Available online at: http://www.ferc.gov/legal/maj-ord-reg/land-docs/order888.asp

Regional Transmission Organizations, 89 FERC 61,258, Order No. 2000, (20 December 1999), pages 3-4 Available online at: http://www.ferc.gov/legal/maj-ord-reg/land-docs/RM99-2A.pdf

1 95 FERC ¶ 61,252 (2001).

96 FERC ¶ 61, 158 UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Curt Hébert, Jr., Chairman; William L. Massey, Linda Breathitt, Pat Wood, III and Nora Mead Brownell.

Commonwealth Edison Company Docket No. ER01-1209-001

ORDER DENYING REHEARING

(Issued July 30, 2001)

On June 18, 2001, Commonwealth Edison Company (ComEd) filed a request forrehearing of the Commission's May 18, 2001 order (May 18 Order), which rejected certaintransmission service agreements between ComEd and Wisconsin Public Service Company(WPS).1 For the reasons discussed below, the Commission denies rehearing.

Background

On February 10, 2000, Wisconsin Public Service (WPS) submitted to ComEd tworequests for long-term firm point-to-point transmission service. The first request was for 50MW of service from Ameren Corporation to WPS and the second was for 50 MW of servicefrom American Electric Power Company to WPS. The service under both contracts was tobegin on January 1, 2002, and end on December 31, 2002. ComEd accepted the requestsand WPS confirmed and executed the service agreements (2002 Service Agreements).

Subsequently, on December 22, 2000, WPS submitted requests to roll over each ofthe 2002 Service Agreements for a two-year period, covering the years 2003 and 2004.ComEd refused these rollover requests and told WPS that the rollover term for a one-yearagreement was limited to one year. WPS then submitted requests to ComEd to roll over thetwo 2002 Service Agreements for one year, and to roll over the ensuing 2003 ServiceAgreements for one year. This would result in a reservation of service through the end of2004.

Docket No. ER01-1209-001 -2-

2 ComEd Request for Rehearing at 3-4.

ComEd accepted the 2003 Service Agreements subject to the condition that therewould be no rollover rights for service in 2004, and rejected the 2004 Service Agreements.ComEd stated that it could not accommodate the 2004 Service Agreements because its openaccess transmission tariff (OATT) required it to consider the effect upon neighboringnetworks of reservations on its system. It stated that it could not accept the 2004 ServiceAgreement because of a lack of capacity on the Arpin-Eau Claire line of Northern StatesPower Company (Northern States). WPS asked ComEd to file the 2003 Service Agreementsunexecuted because Section 2.2 of ComEd's OATT required it to grant rollover servicethrough 2004 notwithstanding the lack of available transmission capacity on Northern States'system.

The Commission found that WPS was entitled to a rollover of service through 2004,and accordingly rejected the 2003 Service Agreements in the May 18 Order. TheCommission found no limitation in Order No. 888 on the length of a rollover service term,and held that a transmission provider may not condition the right to roll over transmissionservice on the availability of transmission capacity on a third party's transmission system.It held that the only limitations upon the right to roll over service are: (1) that the underlyingcontract must have been for a term of one year or more; (2) that the existing transmissioncustomer must agree to match the rate offered by another potential transmission customer;and (3) that the existing transmission customer must agree to accept a contract term at leastas long as that offered by the potential new transmission customer.

ComEd's Request for Rehearing

ComEd filed a timely request for rehearing of the May 18 Order. It argued that theCommission incorrectly concluded that a transmission provider may not condition atransmission customer's right to roll over service on the transmission provider's system basedon whether there is enough transmission capacity available on a third-party system. ComEdstates that it rejected the 2004 Service Agreements because there was no availabletransmission capacity on the Arpin-Eau Claire line on Northern States' transmission system,and challenges the Commission's "implicit finding" that the anticipated congestion wouldnot occur.2 It requests a hearing or a technical conference to determine whether thetransmission service in question would, in fact, overload the Arpin-Eau Claire line. ComEddescribes the procedures that it used to verify the anticipated congestion, and argues that itdoes not appear that the congestion can be relieved prior to 2004. It argues that pursuant tothe Commission's decision in Idaho Power Company, 94 FERC ¶ 61,311 (2001), reh'g

Docket No. ER01-1209-001 -3-

3 ComEd Request for Rehearing at 11 (citation omitted).

4 ComEd Request for Rehearing at 15.

denied in relevant part 95 FERC ¶ 61,224 (2001) (Idaho Power), it is not required to allowWPS to roll over service if there is no available transmission capacity.

Additionally, ComEd questions the Commission's decision that, because Order No.888 does not restrict the length of a rollover term, existing service agreements may be rolledover indefinitely. ComEd argues that this holding, read together with the Commission'sdecision in Entergy Power Marketing Corporation, 91 FERC ¶ 61,276 (2000), means that:

a long-term firm customer has the right of first refusal withrespect to existing transmission capacity for an unlimited termand does not have to commit to the use of that capacity until 60days before the end of its existing term. The customer thus hasa perpetual option on existing capacity at no cost.[3]

ComEd argues that the Commission's conclusion is not supported by any reasoning and thatit will not support orderly planning by transmission providers and transmission customers.It contends that the process will cause significant uncertainty in the process of state approvalof new transmission facilities, because it will never be clear whether or not the new facilitiesare necessary. It also contends that existing transmission customers will have an incentiveto withhold transmission capacity from the market.

ComEd requests clarification that the Commission's allegedly new policy was notretroactively effective. It argues that because it assumed that the capacity associated withan existing one-year reservation had to be sold now for the period after the one-year rolloverterm, it also assumed that the rollover term had to be granted subject to the condition thatno further rollovers would be granted because of lack of capacity. As such, it complains thatit and "many other transmission providers have granted firm service outside of such termsto other customers that use[] capacity that, under the Order, should have been set aside forpotential rollovers of infinite duration or occurring in an indefinite series."4

Discussion

Docket No. ER01-1209-001 -4-

5 See Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costsby Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, 62Fed. Reg. 12,274 (March 14, 1997), FERC Stats. & Regs. ¶ 31,048 at 30,527 (1997)(Section 21.1 of the pro forma tariff), order on reh'g, Order No. 888-B, 81 FERC ¶61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd inrelevant part, remanded in part on other grounds sub nom.,, Transmission Access PolicyStudy Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), cert. granted, 69 U.S.L.W.3574 (Nos. 00-568 (in part) and 00-809) and cert. denied, id. (No. 00-800)(U.S. Feb. 26,2001).

6 See 95 FERC at 61,875 n.7.

7 Pursuant to Section No. 21.1 of its OATT, ComEd is not responsible foradditions to third-party transmission systems. See 95 FERC at 61,875 n.7.

8 ComEd Request for Rehearing at 12.

With respect to ComEd's arguments that third-party system impacts prevent it fromproviding service to WPS in 2004, ComEd is not authorized by the pro forma tariff5 or byits own OATT6 to condition a transmission customer's right to transmission service onwhether there is transmission capacity on a third party's transmission system; indeed, thesedocuments suggest to the contrary. ComEd submits, however, that Idaho Power grants it theauthority to impose such a condition on a transmission customer. We disagree. IdahoPower dealt with a very different situation, in which the transmission provider knew, at thetime the transmission customer's first service agreement was initiated, that constraints on itsown system prevented it from providing service in increments of more than eighteen months.This is not the case here, where there is no constraint on ComEd's system. We also note thatwhile ComEd may not limit the rollover term, as noted in the May 18 Order, it is notresponsible for additions to third-party systems.7

All long-term firm transmission customers have the right to roll over their service, butthe potential that a transmission customer will choose to do so does not require ComEd to"remove[] the associated capacity from its OASIS forever, restoring it only if the customerdeclines to exercise its option at some future period."8 ComEd may post the associatedcapacity on its OASIS and accept competing reservations until the time that the existingcustomer chooses to roll over its contract by exercising its right of first refusal. If theexisting customer does so, it then takes priority over the competing reservation. If the

Docket No. ER01-1209-001 -5-

9 See Order No. 888-A at 30,511.

10 See Order No. 888 at 31,665; Order No. 888-A at 30,195, 30,197-98.

11 ComEd Request for Rehearing at 10-11.

12 See Ameren Services Company, 96 FERC ¶ 61,001 (2001) (rejecting Ameren'sproposal to require an existing transmission customer to exercise its right of refusalwithin 30 days of the time Ameren received a competing request for service). Seealso Entergy Marketing Corporation v. Southwest Power Pool, 91 FERC ¶ 61,276(2000).

existing customer declines to exercise its right of first refusal, the transmission provider mayaccept the next competing reservation.

With regard to the impact on system planning of allowing rollovers, we reiterate ourfinding in the May 18 Order that rollover rights facilitate orderly planning. As we explainedin that order, rollover of the existing transmission service agreements, as contemplated byWPS, should facilitate ComEd's planning and operations since ComEd has already evaluatedthe impacts on its system of providing transmission service to WPS from the stated receiptpoints to the stated delivery point. Moreover, Com Ed may still accept competing servicerequests, from which it may determine whether there is additional demand for service andthus a need for new or additional facilities. In any event, WPS has not been granted servicein perpetuity; competing service requests may (1) replace service to WPS absent a rolloverof its request or (2) supplant such service if WPS declines to match a competing request witha longer term.

We deny ComEd's request for clarification that the policy is not retroactivelyeffective. The Commission has consistently found that Section 2.2 of the pro forma tariff9

requires a transmission provider to allow a customer with a one-year firm reservation to rollover that service for a longer period of time, subject to matching competing requests forservice. Order No. 888 contemplated such an arrangement10 and, as ComEd acknowledges,does not prohibit it.11 The policy took effect at the time Order No. 888 was issued. Wehave specifically declined to permit tariff changes that would require existing customers tomake their commitments earlier.12 We see no reason to, and so we decline to, change ourpolicy.

The Commission orders:

ComEd's request for rehearing is hereby denied.

By the Commission.

( S E A L )

David P. Boergers, Secretary.

LEXSEE

ConocoPhillips Company v. Entergy Services, Inc.

Docket No. EL08-59-000

FEDERAL ENERGY REGULATORY COMMISSION - COMMISSION

124 F.E.R.C. P61,085; 2008 FERC LEXIS 1489

July 24, 2008 ACTION: [**1] ORDER ON COMPLAINT JUDGES: Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff OPINION: [*61466] 1. On April 24, 2008, ConocoPhillips Company (ConocoPhillips) filed a complaint and request for fast track processing against Entergy Services, Inc. (Entergy). ConocoPhillips alleges that Entergy unlawfully terminated two firm [*61467] point-to-point transmission service agreements in violation of Entergy's Open Access Transmission Tariff (OATT). In this order, we find that termination of ConocoPhillips' confirmed, firm transmission service was improper. I. Background 2. On March 12, 2007, ConocoPhillips requested 52 megawatts (MW) of short-term firm point-to-point transmission service on Entergy's system from June 1, 2007 to August 31, 2007 (June Transaction). On March 14, 2007, ConocoPhil-lips requested an additional 51 MW of short-term firm point-to-point transmission service on Entergy's system from July 1, 2007 to August 31, 2007 (July Transaction). Both requests were approved on March 14, 2007 and confirmed the next day. 3. In late May of 2007, a customer of Entergy's, NRG Power Marketing, LLC (NRG PML), became [**2] concerned that, based on public information available on Entergy's Open Access Same-Time Information System (OASIS), the total amount of confirmed reservations at the Entergy-Ameren interface exceeded the posted available transfer capabil-ity for that interface. n1 On or about May 30, 2007, NRG PML notified Entergy's Independent Coordinator of Trans-mission (ICT) of its concern. n2 On June 15, 2007, Entergy notified the Commission, in the Commission's docket re-garding approval of the ICT, n3 that it oversold service at the Entergy-Ameren interface because it miscalculated the Available Flowgate Capability (AFC), due to a software error. n4

n1 See NRG Companies at 3.

n2 See id.; see also ICT at 6.

n3 See Entergy June 15, 2007 Report of OASIS Software Error, Docket No. ER05-1065-000 (June 15 Re-port).

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

n4 Entergy is required to inform the Commission of any error related to software and AFC data, within 15 days of discovering the error. See Entergy Services Inc., 115 FERC P 61,095, at P 110 (2006), errata notice May 4, 2006, order on reh'g, 116 FERC P 61,275 (2006) (Order Approving the ICT). Entergy has had numerous AFC software-related issues, which have affected Entergy's ability to accurately grant short-term transmission services. AFC values are calculated by software applications that use a model of the physical transmission sys-tem to simulate forecasted system conditions based on various data inputs.

[**3] 4. On June 26, 2007, the ICT posted a notice on Entergy's OASIS, which stated that there was an overselling of the En-tergy-Ameren interface. The notice also warned that, if no transmission customer voluntarily terminated its transmission service on the interface, then the ICT would resolve the oversell by recalling (i.e., terminating) transmission service in reverse queue order. The notice did not state which customers' requests were in the queue or the order of their requests. No voluntary terminations were forthcoming. On June 29, 2007, at 5:51 p.m., after the close of business on a Friday, the ICT informed ConocoPhillips that its June and July Transactions were terminated, effective July 1, 2007. II. Complaint 5. ConocoPhillips contends that Entergy violated its OATT by terminating the June and July Transactions. It argues that Entergy's OATT excuses Entergy from providing firm transmission service under a confirmed reservation only for force majeure, n5 and that Entergy has not claimed force majeure. Instead, ConocoPhillips contends that Entergy simply states that it oversold its transmission system because of errors in its own AFC software.

n5 Section 10.1 of Entergy's OATT states that a force majeure includes "any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machin-ery or equipment, any Curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party's control. A Force Majeure event does not in-clude an act of negligence or intentional wrongdoing."

[**4] 6. ConocoPhillips argues that, if Entergy believed that it had oversold its capacity, Entergy was obligated under its OATT to: (1) have in place facilities sufficient to satisfy all firm transmission reservations; (2) curtail such reservations, including Entergy's native load, on a pro rata basis if it lacked sufficient capacity; or (3) offer to redispatch resources on a least-cost basis, without undue discrimination towards any particular customer, with the economic burden of any such procedures borne on a pro rata basis by all system users. n6 ConocoPhillips notes that, just as with the treatment of firm transmission service reservations with rollover rights where the system has become constrained, the obligation is on the transmission provider to either curtail service pursuant to the provisions of its OATT or to build more capacity to relieve the constraint. n7

n6 Complaint (citing Entergy OATT §§ 13.5, 13.6).

n7 Id. at 12 (citing Exelon Gen. Co., Inc. v. Southwest Power Pool, Inc., 101 FERC P 61,226, at P 9 (2002)).

[**5] 7. ConocoPhillips further argues that other longer-term requests could not have preempted the June and July Transac-tions. While it acknowledges that, under the OATT, longer-term service requests can preempt shorter-term service re-quests during the conditional period, it states that the conditional period had long expired, and that its transmission res-ervations were fully firm at the time of termination. 8. ConocoPhillips also distinguishes this case from those in which the Commission allowed transmission providers to terminate confirmed reservations when their systems were oversold. n8 ConocoPhillips contends that, in those cases, the

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

Commission considered whether the transmission operators had offered alternatives to the customer before terminating service, or whether they had considered the customers' proposed remedies. n9

n8 See Williams Energy v. Southern Company Services, Inc., 101 FERC P 61,144 (2002) (Williams); Pow-erex Corp. v. United States DOE, 95 FERC P 61,241 (2001) (Powerex).

n9 Complaint at 14 (citing Powerex, 95 FERC P 61,241 at 61,827; Williams).

[**6] 9. As a result of the termination, ConocoPhillips states that it was denied the transmission it needed -- and had duly re-served -- to move the electrical output that ConocoPhillips purchases from SRW Cogeneration Limited Partnership (SRW), an indirect, wholly-owned subsidiary. Instead, [*61468] SRW was required to sell its surplus energy to En-tergy, at Entergy's avoided-cost rate, at prices lower than the Midwest ISO market rates that would have been available to ConocoPhillips at the Entergy-Ameren interface. ConocoPhillips calculates its damages to be approximately $ 438,000. n10

n10 Id. at 3, 9-10, and Appendix C.

10. ConocoPhillips does not want Entergy to reinstate its transmission reservations, but requests that the Commission: (1) find that Entergy violated Commission policy and the OATT when it unilaterally terminated ConocoPhillips' reser-vations; (2) enjoin Entergy from delaying in discovering such errors in the future; (3) direct Entergy to provide immedi-ate, meaningful corrective relief should [**7] such errors occur in the future; and (4) "take such other action and grant such other relief as may be consistent with these requests." n11 ConocoPhillips also requests fast track processing of its complaint.

n11 Id. at 21; see also at 19.

III. Notice of Complaint and Responses 11. Notice of ConocoPhillips's complaint was published in the Federal Register, 73 Fed. Reg. 24,966 (2008) with inter-ventions and answers due on or before May 14, 2008. Motions to intervene and comments were filed by NRG PML, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, Louisiana Generating LLC, and NRG Sterlington Power LLC (collectively, NRG Companies), and Southwest Power Pool, Inc. (SPP), in its capacity as the ICT. South Mississippi Electric Power Association filed a motion to intervene. Entergy filed an answer to the original complaint on May 14, 2008. ConocoPhillips filed a reply to Entergy's answer and the ICT's comments on May 22, 2008. Entergy filed an answer to ConocoPhillips's [**8] answer on May 29, 2008, and the ICT filed an answer on June 2, 2008. A. Entergy's Answer 12. Entergy states that it was the ICT that terminated ConocoPhillips' transmission service, not Entergy. It argues that the ICT independently and reasonably determined that no alternatives were available to address the specific reliability concerns that were presented by the oversubscription. 13. More specifically, Entergy explains that, when it became aware of the problem, its and the ICT's representatives discussed and analyzed viable alternatives for addressing the possible real-time effects of the oversell. n12 Entergy states that its view was that, in absence of any countervailing considerations, service should be allowed to flow in real-time and, to the extent an overload arose, it should be resolved by relying on real-time curtailments on a pro rata basis. However, Entergy states, the ICT had reliability concerns with this approach, and made an independent decision that, in

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

the absence of sufficient voluntary termination by customers, "the improperly granted transmission services would be terminated in reverse queue order prior to real-time operation." n13

n12 Entergy also states that its and the ICT's attorneys also attempted to determine Commission policies and case law to offer guidance as to the appropriate action that should be taken under the circumstances.

[**9]

n13 Answer at 9.

14. Entergy argues that the transmission service at issue was granted to ConocoPhillips improperly because of an error in the software used to calculate AFC values. It argues that, even without a force majeure, improperly granted service can be terminated under Commission precedent. 15. In addition, Entergy argues that the ICT's method of termination (in reverse queue order), was consistent with the Commission's determinations in Williams and Powerex. It further argues that its OATT requires it to defer to the ICT's decision to terminate service, and that these circumstances are precisely the type that the ICT had been developed to address. n14 Entergy concludes that it acted within the Commission's guidelines, which state that Entergy must unambi-guously give the ICT authority to grant or deny requests for transmission service. n15

n14 See Entergy OATT, Attachment S (outlining responsibilities of ICT to manage Entergy's transmission scheduling).

n15 Answer at 12 (citing Entergy Services, Inc., 116 FERC P 61,275, at P 3 (2006)).

[**10]

B. ICT's Comments 16. The ICT states that, on May 30, 2007, an Entergy customer (presumably NRG PML) notified the ICT that data on Entergy's OASIS showed that the Entergy-Ameren interface was oversold by 206 MW. On June 1, 2007, the ICT dis-covered the error in the software that calculates AFC on the Entergy transmission system, resulting in the overselling. n16 After it discovered the software error, the ICT began analyzing whether all confirmed service reservations across the interface could be accommodated without a negative impact on other transmission customers or the reliability of Entergy's transmission system. The ICT concluded that, due to reliability concerns, it was required to resolve the over-sell prior to real-time operations.

n16 Consistent with the Order Approving the ICT, Entergy submitted a report with the Commission on June 15, 2007 informing it of the AFC software error. See June 15, 2007 Report. The ICT and Entergy also state that they actively investigated the error and developed mechanisms to resolve the software problem on an ongoing basis.

[**11] 17. When no customer agreed to voluntarily terminate service in response to the ICT's June 26, 2007 notice of potential involuntary termination, the ICT terminated 206 MW of transmission service transactions in reverse queue order, in-cluding [*61469] ConocoPhillips' June and July Transactions (totaling 104 MW). n17

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

n17 On July 7, 2007, as amended on July 20, 2007, the ICT filed information in Docket No. ER05-1065-000, identifying ConocoPhillips, NRG Companies, and Cargill Power Markets, LLC, as the customers whose reservations were terminated.

18. The ICT contends that ConocoPhillips should have known that the June and July Transactions could be terminated because its reservations were near the back of the queue. Moreover, the June and July Transactions were on the service list in the docket in which Entergy notified the Commission of the software error and resulting oversell at the Entergy-Ameren interface. The ICT notes that, on June 29, 2007, it emailed ConocoPhillips at the email address listed on the transmission [**12] service reservation that the June and July Transactions had been terminated, effective July 1, 2007. 19. The ICT states that sections 13.5 and 13.6 of Entergy's OATT do not specifically address transmission system con-straints that are due to erroneously accepted transmission requests. The ICT asserts that, in the absence of any clear tar-iff direction, it chose to terminate reservations in reverse queue order to recognize the priority status of earlier, properly accepted reservations. The ICT states that Williams and Powerex supported its decision to terminate in reverse queue order.

C. NRG Companies' Comments 20. NRG Companies state that, like ConocoPhillips, a portion of one of their confirmed firm service reservations was terminated on June 29, 2007 by the ICT due to the oversell at the Entergy-Ameren interface. NRG Companies request that any determination the Commission makes as to ConocoPhillips' complaint apply also to NRG Companies and any other customer whose reservations were terminated due to the oversell at the Entergy-Ameren interface. NRG Compa-nies also request that the Commission investigate the cause of the software error, and alleged continued [**13] over-selling and increased curtailments at the interface. IV. Discussion

A. Procedural Matters 21. Pursuant to Rule 214 of the Commission's Rules of Practice and Procedure, 18 C.F.R. § 385.214 (2008), the timely, unopposed motions to intervene serve to make the entities that filed them parties to this proceeding. 22. Rule 213(a)(2) of the Commission's Rules of Practice and Procedure, 18 C.F.R. § 385.213(a)(2) (2008), prohibits an answer to an answer unless otherwise ordered by the decisional authority. We are not persuaded to accept the answers to answers filed by ConocoPhillips, Entergy, and the ICT and will, therefore, reject them.

B. Analysis 23. We will grant the complaint in part. The termination of ConocoPhillips' June and July Transactions was not consis-tent with Entergy's OATT, specifically the procedures established in Entergy's OATT for relieving a system constraint. On March 14, 2007, the ICT notified ConocoPhillips that short-term firm point-to-point service was available. Effective March 15, 2007, the date ConocoPhillips confirmed its requests, ConocoPhillips had a confirmed firm reservation for service on Entergy's system, [**14] subject to the provisions of Entergy's OATT. n18

n18 See Open Access Same-Time Information System and Standards of Conduct, Final Rule, Order No. 638, FERC Stats. & Regs. P 31,093, at 31,417 (2000) ("Once a request has been 'CONFIRMED,' a transmission ser-vice reservation exists."). Thus, the ICT is correct that section 13.5 of the OATT, which deals with constraints prior to confirmation, is not relevant here because ConocoPhillips confirmed the June and July Transactions.

24. Although Entergy's OATT did not have a specific provision for terminating transactions due to software errors, sec-tion 13.6 (Curtailment of Firm Transmission Service) sets forth a procedure for making curtailments for system reliabil-

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

ity. n19 Absent a specific provision addressing software errors, section 13.6 is the appropriate OATT provision to which Entergy and the ICT should have looked for addressing the constraint.

n19 We also note that, had Entergy and the ICT been uncertain as to how to proceed, they could have sought guidance from the Commission's Enforcement Hotline. See 18 C.F.R. § 1b.21 (2008).

[**15] 25. At the time the June and July Transactions were terminated, section 13.6 stated in relevant part:

In the event that a Curtailment on the Transmission Provider's Transmission System, or a portion thereof, is required to maintain reliable operation of such system and the system directly and indirectly intercon-nected with Transmission Provider's Transmission System, Curtailments will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint.

26. Relieving the system constraints through termination of reservations in the reverse order that the requests were ac-cepted did not comply with section 13.6, and placed the entire burden of relieving the constraint on ConocoPhillips and the other last-in-queue firm-service customers. This unduly discriminated between customers even though they were similarly situated, each having confirmed firm service, and such action was unsupported by Entergy's OATT. 27. Entergy's argument that ConocoPhillips' requests would not have been accepted absent the software error has no bearing on our decision that Entergy and the ICT were obligated to follow [*61470] Entergy's OATT once Conoco-Phillips' [**16] request for service was confirmed. Once a constraint is identified, the OATT calls for curtailing all existing relevant reservations pro rata, pursuant to section 13.6. n20 As we stated above, nothing in Entergy's OATT allowed termination of firm point-to-point service in reverse queue order.

n20 See, e.g., Louisville Gas and Electric Co., 114 FERC P 61,282, at P 125 (2006) ("The pro forma OATT provides access to firm transmission service, subject to the availability of transmission capacity, for all transac-tions, regardless of receipt or delivery point, and provides equal curtailment priority for all firm service, includ-ing network and native load"); Village of Freeport, NY v. Consolidated Edison Co. of NY, 101 FERC P 61,225, at P 14 (2002) (finding section 13.6 of a comparable OATT to be satisfied where the transmission provider in-terrupted all transmission services over the constrained area simultaneously and pro rata).

28. In addition, Entergy's and the ICT's [**17] reliance on Williams and Powerex is misplaced. In Williams and Pow-erex, the Commission approved transmission providers' terminations of improperly-accepted service reservations only after finding that the transmission providers offered the affected customers alternative ways to keep their service. In Williams, for example, the transmission provider restored the customer's terminated request to its original queue posi-tion. Similarly, the transmission provider in Powerex reopened the "conditional" period for short-term service on the oversubscribed transmission path, giving the customer the opportunity to submit a competing bid. In contrast, neither the ICT nor Entergy gave ConocoPhillips any alternatives to termination. n21

N21 We note that, according to Entergy, all holders of transmission rights across the interface were offered an opportunity to voluntarily give up their service. This was not an alternative to termination, but simply a re-quest for voluntary termination.

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **

29. Additionally, [**18] in both cases, the Commission noted that the transmission providers took action to correct the errors within a reasonable amount of time after the errors were discovered and the termination took place shortly after the service was confirmed and well before the service was to start. Williams' three-year redirect was terminated 21 days after confirmation, and nearly three years before commencement; Powerex's six-month reservation was cancelled four days after confirmation, and 16 days before commencement. By contrast, ConocoPhillips' service was terminated nearly a month after the software error was discovered and 106 days after the service reservations were confirmed. Moreover, the terminations took place 28 days after service on one reservation had begun and two days before service on the other reservation was to begin -- much later in time than in Williams and Powerex. Therefore, we find that Williams and Pow-erex do not support termination of ConocoPhillips' service reservations. n22

n22 Similarly, in an order not cited by the parties, the Commission ordered the transmission provider to terminate improperly-accepted service, but the Commission emphasized that the customer's terminated service should be reinstated into the queue and provided in part if possible. Idaho Power Co. v. Pacificorp., 95 FERC P 61,148, at 61,277 (2001).

[**19] 30. Thus, for the reasons stated above, we will grant ConocoPhillips' complaint in part, and find that termination of ConocoPhillips' June and July Transactions was improper. We will deny ConocoPhillips' remaining requests for relief as unnecessary. Specifically, the Commission will not enjoin Entergy from delaying in discovering such errors in the future because Entergy, as the transmission provider, is already required to correct any errors in its system that it dis-covers, and to report such errors within 15 days of discovery to the Commission and stakeholders under the Order Ap-proving the ICT. n23 Similarly, the Commission will not direct Entergy to provide immediate, meaningful corrective relief should such errors occur in the future, because Entergy is already subject to such a requirement under its OATT. n24

n23 Entergy Services, Inc., 115 FERC P 61,095, at P 110 (2006), order on reh'g, 116 FERC P 61,275, or-der on clarification, 119 FERC P 61,013 (2007), order on reh'g and compliance, 119 FERC P 61,187, order on reh'g and clarification, 122 FERC P 61,216 (2008).

[**20]

n24 See, e.g., Section 15.2, Determination of Available Transmission Capacity (in effect at the time), and Attachment C, Methodology to Assess Available Transmission Capability (in effect at the time).

31. Finally, with respect to NRG Companies' request that any determination that the Commission makes as to Conoco-Phillips' complaint also apply to NRG Companies and to any other customer whose reservations were terminated due to the oversell at the Entergy-Ameren interface, we conclude that it is inappropriate for us to address NRG Companies' request in this proceeding. Effectively, NRG Companies are requesting that they and any other such customer be joined with ConocoPhillips' complaint. That is improper; allowing a third party to join in a complaint by filing comments would circumvent our public notice requirements and deprive the "respondent" of the opportunity to address the asser-tions of that third party. n25 If NRG Companies or other customers seek Commission action for a perceived violation against them, they are free to file their own complaint alleging each violation, presenting [**21] facts in support, and requesting specific relief, either here or in another forum. We will deny NRG Companies' request that the Commission investigate the cause of Entergy's software error and the alleged continued overselling and [*61471] increased curtail-ments at the Entergy-Ameren interface. That request is beyond the scope of ConocoPhillips' complaint.

n25 See 18 C.F.R. § 385.206 (2008).

124 F.E.R.C. P61,085, *; 2008 FERC LEXIS 1489, **


(A) The relief requested in the ConocoPhillips' complaint is hereby granted, in part, as discussed in the body of this order.

(B) NRG Companies' requests that the Commission investigate the cause of Entergy's software error and the al-leged continued overselling and increased curtailments at the Entergy-Ameren interface are hereby denied, as discussed in the body of this order. By the Commission. Legal Topics: For related research and practice materials, see the following legal topics: Energy & Utilities LawAdministrative ProceedingsU.S. Federal Energy Regulatory CommissionGeneral OverviewEn-ergy & Utilities LawCogeneration & Independent Power CompaniesIndependent System OperatorsEnergy & Utilities LawTransportation & PipelinesElectricity Transmission

1Constellation Power Source, Inc. v. American Electric Power ServiceCorporation and Southwest Power Pool, Inc., 100 FERC ¶ 61,157 (2002) (AugustOrder).

2In Opinion No. 442, the Commission conditioned its approval of a mergerbetween AEP and Central and South West Corporation (CSW) on, among other things,the merged companies' contracting out their OASIS responsibilities to an independententity. In compliance with Opinion No. 442, AEP and CSW entered into an agreementwith SPP pursuant to which SPP would, among other things, independently calculateand post Available Transmission Capacity (ATC) and perform the OASIS function ofprocessing transmission service requests for customers seeking service over the AEP

(continued...)

102 FERC ¶ 61,142UNITED STATES OF AMERICA


Before Commissioners: Pat Wood, III, Chairman; William L. Massey, and Nora Mead Brownell.

Constellation Power Source, Inc. ) Docket No. EL02-95-001Complainant )

v. )American Electric Power Service Corporation )

and )Southwest Power Pool, Inc., )

Respondents )

American Electric Power Service Corporation ) Docket No. ER02-2028-001


(Issued February 5, 2003)

1. In an order issued on August 5, 2002,1 the Commission granted the complaintfiled by Constellation Power Source, Inc. (Constellation) against American ElectricPower Service Corporation (AEP) and Southwest Power Pool, Inc. (SPP), asadministrator for AEP's OASIS,2 alleging that SPP had refused to honor Constellation's

20030205-3042 Issued by FERC OSEC 02/05/2003 in Docket#: EL02-95-001

Docket Nos. EL02-95-001 and ER02-2028-001 - 2 -

2(...continued)transmission system. (See American Electric Power Company and Central and SouthWest Corporation, Opinion No. 442, 90 FERC ¶ 61,242 at 61,788-89, order on reh'g, 91FERC ¶ 61,129 (2000), aff'd sub nom. Wabash Valley Power Ass 'n v. FERC, 268 F. 3d1105 (D.C. Cir., 2001); Order Accepting Compliance Filings, as Modified, 91 FERC ¶ 61,208 at 61,747-48 (2000); Order Accepting Compliance Filing, 93 FERC ¶ 62,065 (2000).

3Section 2.2 provides in relevant part:Reservation Priority For Existing Firm Service Customers: Existingfirm service customers (wholesale requirements and transmission-only,with a contract term of one-year or more, and retail) . . . have the right tocontinue to take transmission service from the Transmission Provider whenthe contract expires, rolls over, or is renewed . . . This transmissionreservation priority for existing firm service customers is an ongoing rightthat may be exercised . . . at the end of all firm contract terms of one year

(continued...)

rollover rights related to its existing long-term firm point-to-point transmission serviceagreement in violation of Section 2.2 of the AEP open access transmission tariff (OATT)and the Commission's policy. The order also accepted, subject to conditions, serviceagreements filed by AEP in Docket No. ER02-2028-000. This order denies rehearing ofthe August Order.

BACKGROUND


2. On May 31, 2002, Constellation filed a complaint against AEP and SPP allegingthat SPP, as administrator for AEP's OASIS, refused to roll over Constellation's one-yearservice agreement for 50 MW of firm point-to-point transmission service from a point ofreceipt on the AEP system to a point of receipt on the TVA system for another one-yearterm beginning on June 1, 2002. Constellation stated that it was informed by SPP thatthe transmission request was refused due to network load growth and loopflow problemson AEP's transmission system.

3. In the August Order, the Commission granted Constellation's complaint and statedthat Constellation has the right to request a rollover of its existing firm point-to-pointtransmission service. The August Order explained that SPP is obligated, under Section2.2 of AEP's OATT (which adopts the language of the Commission's pro forma OATT),3



3(...continued)or longer . . . If competing existing firm service requirements customersapply for service that cannot be fully provided, the priority rights will beranked in accordance with first-come, first-served principles. If firmservice customers tie, then the capacity for which they receive priorityrights under this Tariff shall be apportioned on a pro rata basis.

4August Order at P 26.

5The unexecuted Agreements contained the following language in Article 1:

Due to delays in constructing certain transmission facilities, the AEPOASIS Administrator (Southwest Power Pool) expects there to belimited system capacity to allow renewal of this reservation. Renewal, in whole or in part, may be possible if conditions change. Further, depending on the final determination of the Federal EnergyRegulatory Commission in Docket No. EL02-86-000, this limitedrenewal right could be invalidated and this agreement terminatedbefore the specified termination date.

to maintain available transmission capacity for existing long-term transmission customerswith rollover rights, such as Constellation, until the time expires for those customers toexercise their rollover rights.4

Docket No. ER02-2028-001

4. On June 4, 2002, AEP, as agent for the operating utility subsidiaries of AmericanElectric Power Company, Inc., submitted two unexecuted transmission serviceagreements, at SPP's request, for long-term firm point-to-point transmission serviceunder its OATT with its marketing affiliate, AEP Wholesale Power MerchantOrganization (AEP Power Merchant) and Constellation. The unexecuted agreementscontained language advising the customer that SPP, as administrator of AEP's OASIS,expects there to be limited system capacity to allow renewal of the reservations.5

5. In the August Order, the Commission accepted the agreements for filing butdirected AEP to remove the language proposed in Article 1 of the unexecuted



6The service agreements were accepted in Docket No. ER02-2028-002 on October 8, 2002.

7Remedying Undue Discrimination Through Open Access Transmission Serviceand Standard Electricity Market Design, Notice of Proposed Rulemaking, 100 FERC¶ 61,138 (2002) (SMD NOPR).

agreements because the language improperly limited the transmission customers' rolloverrights under Section 2.2 of the AEP OATT.6

REQUESTS FOR REHEARING

6. On September 4, 2002, SPP filed a request for rehearing arguing that theCommission erred by determining that a transmission customer has an automatic right torenew its service even if studies regarding the transmission request show that insufficienttransmission capacity is available and that providing such service would adversely affectreliability. SPP contends that the Commission's determination will have an adverseeffect on reliability by causing greater curtailments and Transmission Loading Relief(TLRs) of existing firm load and outages. In addition, SPP argues that the Commissionerred by determining that a transmission provider may only recall capacity to serve nativeload and only if the need for this limitation is forecasted and is set forth in the initialservice agreement, even if capacity is no longer available due to events or circumstancesthat arose after the initial service was entered into. SPP claims that the Commissionerred by announcing a new policy without providing adequate notice and opportunity foraffected parties to comment or participate. SPP further asserts that the Commission'sdecision represents an unexplained reversal of the Commission's prior orders on Section2.2 and the language of the pro forma OATT and AEP's OATT. SPP also states that theAugust Order fails to consider the fact that AEP has posted notifications on its OASISthat constituted sufficient notice of potential lack of capacity in the future. Furthermore,SPP contends that the Commission's recent policy as announced in the Notice ofProposed Rulemaking on Standard Market Design7 supports SPP's position by settingforth the principle that customers who are willing to pay more should get the service. SPP asks that we reverse the decision in the August Order or, at the very least, apply thedecision prospectively.

7. On September 4, 2002, AEP also filed a request for rehearing, as amended, inwhich it raises similar arguments to SPP's. AEP states that in granting Constellation'scomplaint and directing AEP to remove any limitation on the renewal of the rollover, theCommission erred in a number of respects. Specifically, AEP states that the



8See Exelon Generation Company, LLC v. Southwest Power Pool, Inc., 99 FERC¶ 61,235, reh'g denied, 101 FERC ¶ 61,226 (2002) (Exelon); Tenaska Power ServicesCo. v. Southwest Power Pool, Inc., 99 FERC ¶ 61,344 (2002), reh'g denied, 102 FERC¶ 61,140 (2003).

9See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs byPublic Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs.¶ 31,036at 31,694 (1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, orderon reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C,82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access PolicyStudy Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New Yorkv. FERC, 122 S. Ct. 1012 (2002). See also Commonwealth Edison Co., 95 FERC¶ 61,252 at 61,874, reh'g denied, 96 FERC ¶ 61,158 at 61,690 (2001).

10Order No. 888 at 31,665; Order No. 888-A at 30,195.

Commission's recent decisions on rollover rights,8 including the August Order, constitutea change in policy on rollover rights without providing adequate notice to affectedparties. AEP contends that the Commission has departed from its previous precedentswithout justification or explanation and this does not constitute reasoned decision-making. AEP further argues that this alleged new policy contravenes the pro formaOATT. In addition, AEP asserts that the Commission, in rejecting the proposedlimitation on renewal as not sufficiently specific, ignored postings on its OASIS whichprovided the necessary specificity to affected transmission customers.

DISCUSSION


8. As discussed in greater detail below, SPP's request for rehearing of the AugustOrder is basically a collateral attack of the Commission's rollover rights policy asestablished in Order No. 888.9 In that order, the Commission concluded that all firmtransmission customers with contracts for a term of one-year or more should have theright to continue to take transmission service from their existing transmission providerupon the expiration of their contracts or at the time their contracts become subject torenewal or rollover.10 Once a transmission provider evaluates the impacts on its systemof providing transmission service to a customer and decides to grant such a request, therollover rights policy obligates the transmission provider to plan and operate its systemwith the expectation that it will continue to provide service to that customer should the



customer request rollover of its contract term. In other words, the transmission provideris expected to plan its system to accommodate transmission customers' rollover rights. Ifthe transmission system becomes constrained such that the transmission provider cannotsatisfy existing customers, then the obligation is on the transmission provider to eithercurtail service pursuant to the provisions of the AEP OATT or to build more capacity torelieve the constraint.

9. Many of the issues raised by SPP on rehearing (e.g, the one-year minimum term;the impact of rollover on reliability of the transmission system) go to the heart of theCommission's rollover rights policy established in Order No. 888. On this basis, they areissues that should have been raised on rehearing of Order No. 888. The Commission willnot revisit in this order its prior determinations in Order No. 888, which have beenaffirmed by U.S. Court of Appeals for the District of Columbia Circuit and the U.S.Supreme Court.

A. IMPACT ON RELIABILITY

i. Ability to Predict all Factors that Could Limit Capacity

10. SPP argues that the Commission's determination in the August Order will have adetrimental impact on reliability in the region. SPP contends that a transmission providercannot predict at the outset of entering into a service agreement all of the factors thatcould potentially limit the amount of available transmission capacity because thesefactors vary over time due to conditions that may not be predictable or may be outside ofthe transmission provider's control. SPP states that its denial of Constellation'srequested rollover service was due to circumstances beyond its control or ability topredict. SPP explains that the amount of capacity available on the AEP transmissionsystem has become increasingly limited, especially along the north-to-south transmissionpaths that were the subject of the renewal request service, and SPP could not provideConstellation's requested rollover service without potentially harming reliability or othercustomers.

11. SPP contends that if a transmission provider with limited available transmissioncapacity is compelled to provide service, the result will be more firm demand on thetransmission system than can be accommodated, which will adversely affect native loadcustomers and long-term customers, as well as potential new customers. SPP adds that,as a policy matter, it is neither fair nor appropriate for customers who only committed toa one-year term of service to cause curtailments of firm customers who have been payingfor the costs of the system for a much longer period of time and who are obligated tocontinue to pay for those system costs for a far longer period. Furthermore, SPP states



11We note that SPP has not provided any evidence in support of its assertion thatthe TLRs it has called are the direct result of the Commission's policy on rollover rights.

12See Commonwealth Edison Co., 96 FERC ¶ 61,158 at 61,690 (2001).

that the August Order has forced it to reject new service requests because of uncertaintyas to whether existing customers will roll over their requests.

Commission Response

12. SPP's argument that the Commission's approach has affected reliability and hasbeen shown to exacerbate the need to call TLRs and to increase the severity of theseTLRs is disingenuous. To the extent that SPP's assertion is true, SPP's need to call TLRsmay be due to its failure to follow the requirements of Order No. 888 and not the resultof any change in Commission policy.11 Moreover, SPP's arguments do not diminishConstellation's rollover rights under Section 2.2 of the AEP OATT. Under Section 2.2of AEP's OATT, SPP is responsible for maintaining available transmission capacity forexisting long-term transmission customers with rollover rights, such as Constellation,until the time expires for those customers to exercise their rollover rights. In providingfor Constellation's rollover rights in Section 2.2, SPP is responsible for evaluating theimpact of the exercise of these rights on the AEP transmission system.

13. Notwithstanding SPP's attempt to portray rollover rights as detrimental toreliability, rollover rights are intended to promote system planning and reliability, not toundermine it. Rollover rights should facilitate a transmission provider's orderly planningand operation, i.e., provide for available capacity, which is essential to SPP's obligationof preserving system reliability.12 A transmission provider is expected to include alllong-term transmission customers (i.e., those with rollover rights) in its long-termplanning. While it may be the case, as SPP suggests, that subsequent circumstances maynegatively impact a transmission provider's available transmission capacity, the presenceof such constraints does not give a transmission provider the right to deny a rolloverrequest. Under Section 2.2 of AEP's OATT, SPP is responsible for maintaining availabletransmission capacity for existing long-term transmission customers with rollover rights,such as Constellation, until the time expires for those customers to exercise their rolloverrights. Thus, the constraints that SPP cites are not sufficient to override Constellation'srollover rights. If constraints arise after a transmission provider enters into a long-termagreement with a transmission customer (and that agreement contains no restrictions onthe transmission customer's rollover rights), the obligation is on the transmissionprovider to either build additional transmission facilities to relieve the constraint or toimplement the curtailment procedures set forth in AEP's OATT.



13SPP Rehearing at 12.

14Pursuant to Section 21.1 of its OATT, SPP is not responsible for additions tothird-party systems.

15Commonwealth Edison Co., 96 FERC ¶ 61,158 at 61,690 (2001).

16Commonwealth Edison Co., 95 FERC ¶ 61,252 at 61,875 (2001), reh'g denied,Commonwealth Edison Co., 96 FERC ¶ 61,158 (2001).

14. In its rehearing request, SPP states that "[t]he Commission's orders will force SPPand other transmission providers to presume that all long-term customers will renew theirservice, and evaluate the impact of the service for years beyond the requested term of theproposed service agreement."13 SPP is correct in this regard. Indeed, it was the intent ofthe Commission in establishing the rollover policy that long-term customers have theright to continue to take service and, accordingly, that the transmission provider be in theposition of continuing to provide it. Again, to the extent that SPP disagrees with theCommission's policy call in this regard, it should have sought rehearing and/orclarification at the time that the Commission established the rollover rights policy.

15. With respect to SPP's arguments that third-party system impacts prevent it fromproviding service to Constellation, SPP is not authorized by the pro forma OATT or byAEP's OATT14 to condition a transmission customer's right to transmission service onwhether there is transmission capacity on a third party's transmission system.15 Atransmission provider may not condition a transmission customer's right to roll overtransmission service on the transmission provider's system at the end of an existingservice agreement based on whether there is enough transmission capacity available on athird-party transmission system.16

ii. Absolute Right to Capacity

16. SPP and AEP (collectively, Respondents) argue that the August Order grantstransmission customers an absolute right to capacity based on a one-year long-termcontract. Consequently, the Respondents claim, the order requires transmissionproviders to accept transactions regardless of whether sufficient capacity exists. As aresult, according to the Respondents, transmission providers could overload their systemsand have to curtail reserved service as well as transmission service to other customers orrisk severe and possibly cascading system outages.



17Citing Idaho Power Co., 95 FERC ¶ 61,224 at 61,759 (2001) (Idaho PowerRehearing Order), aff'g, 94 FERC ¶ 61,311 (2001) (Idaho Power), remanded on othergrounds, Idaho Power Company v. FERC, 312 F. 3d 454 (D.C. Cir., 2002).

18Citing Northeast Utils. Serv. Co., 56 FERC ¶ 61,269 at 62,030 (1991), reh'gdenied, 59 FERC ¶ 61,042 (1992), aff'd in relevant part, 993 F.2d 937, 954-55 (1st Cir.199); New England Power Pool, 83 FERC ¶ 61,045 at 61,235 (1998); Duke Elec.Transmission, 96 FERC ¶ 61,145 at 61,626-27 (2001).

19Commonwealth Edison Co., 96 FERC at 61,690.

20Id.

17. SPP further contends that because construction times are usually longer than the60-day renewal period provided to customers, the Commission's policy could forcetransmission providers to build new capacity based on the possibility that a customer willroll over its service. SPP states that this is contrary to the Commission's prior statementsthat transmission owners are not obligated to build new capacity to serve a rolloverrequest.17 SPP states that this is also contrary to Section 13.5 (dealing with atransmission customer's obligations for facility additions or redispatch costs) of the proforma tariff and the Commission's cost-causation and "but for" pricing principles.18 SPPfurther notes that this may be difficult given the number of problems that transmissionowners have experienced when attempting to upgrade their transmission systems.

Commission Response

18. All long-term firm transmission customers have the right to roll over their service,but the potential that a transmission customer will choose to do so does not require SPPto remove the associated capacity from AEP's OASIS forever and restore it only if thecustomer declines to exercise its option at some future period. As the Commission hasexplained, SPP may post the associated capacity on AEP's OASIS and accept competingreservations until the time that the existing customer chooses to roll over its contract byexercising its right of first refusal.19 If the existing customer does so, it then takespriority over the competing reservation. If the existing customer declines to exercise itsright of first refusal, the transmission provider may accept the next competingreservation.20 In any event, Constellation has not been granted service in perpetuity tothe extent that competing service requests may: (1) replace service to Constellationabsent a rollover of its request or (2) supplant such service if Constellation declines tomatch a competing request with a longer term.



21Idaho Power Rehearing Order, 95 FERC at 61,759.

19. Furthermore, SPP has misconstrued our statement that "the right of first refusalprovision applies to existing capacity and does not require a transmission provider tobuild additional capacity in response to a request to rollover a transmission service."21 By this statement, the Commission did not intend, as SPP seems to suggest, that atransmission provider could deny a customer's rollover request to the extent that thetransmission provider did not have sufficient available capacity to meet the request andcould only grant the request if it were to build additional capacity. Implicit in thisstatement was the expectation that the transmission provider had already studied theimpacts on its existing system of providing the transmission service and determined thatit could provide that service (including any rollover if requested) using its existingsystem. Because a determination to grant the initial service request carried with it theobligation to assume that the customer would continue to take service, the Commissionexpected that the transmission provider would have sufficient existing capacity to serve arollover request and not then need to build additional capacity to serve that rolloverrequest.

20. In evaluating Constellation's original request for long-term firm transmissionservice, AEP was obligated to determine whether or not there was available existingcapacity to serve Constellation, taking into account Constellation's right to renew or rollover its transmission service. As we have indicated above, if constraints arise after atransmission provider enters into a long-term agreement with a transmission customer(and that agreement contains no restrictions on the transmission customer's rolloverrights), the obligation is on the transmission provider to determine whether or not tobuild additional facilities to accommodate new transmission customers. If thetransmission system is constrained to the extent that the transmission provider cannotsatisfy its existing transmission customer's contracts, then the transmission provider hasthe choice of either implementing the curtailment procedures set forth in its OATT orbuilding additional transmission facilities to relieve the constraint.

iii. Gaming the System

21. SPP further contends that the August Order removes any incentives for customersto request service for more than a year, which will inhibit the ability of transmissionproviders and transmission owners to engage in long-term planning, further harmingreliability. SPP argues that the August Order encourages gaming because customers whoare aware that a system is becoming increasingly constrained can simply requesttransmission service for a one-year period even if they intend to use the service for a



22See Order No. 888 at 31,655. See also Order No. 888-A at 30,195, 30,197-98.

23 SPP also argues that our recent SMD NOPR supports its position. According toSPP, the SMD NOPR sets forth the principle that customers who are willing to pay morefor capacity should receive the service, and SPP argues that this is precisely what itsinterpretation of Section 2.2 would do. SPP contends that a customer who is willing toagree to a ten-year term of service, and pay for the system upgrades necessary to supportits service, would have greater certainty of service than a customer who chooses to enterinto only a one-year contract. We find that SPP's arguments in this regard are unclear. Nevertheless, with respect to SPP's argument that a customer who is willing to agree to aten-year contract, and pay for the system upgrades necessary to support its service, wouldhave greater certainty of service than a customer who chooses to enter into only a one-year contract we refer to our comments in footnote 24 below in which we point out that transmission customers have incentives to request service for more than one year.

much longer period of time. SPP argues that by choosing a one-year service term,customers can avoid paying for upgrades necessary to support their service which theywould have to pay for if they had requested a multi-year service term. SPP claims thatthis is inconsistent with the Commission's "or" pricing and cost causation principles.

Commission Response

22. The Commission has consistently found that Section 2.2 of the pro forma OATTrequires a transmission provider to allow a customer with a one-year firm reservation toroll over that service for a longer period of time, subject to matching competing requestsfor that service. Order No. 888 contemplated such an arrangement,22 and the policy tookeffect at the time Order No. 888 was issued. On this basis, we will not reexamine ourdecision that the rollover rights provisions of Section 2.2 apply to contracts with terms ofone year or more.

23. Further, a long-term firm transmission service customer cannot game the systemand avoid paying for upgrades simply by choosing a contract with a one-year term.23 Regardless of the length of the contract term, a transmission provider will grant a requestfor long-term firm transmission service only if it determines that it has sufficientavailable transmission capacity to provide the service. In making this determination, thetransmission provider is obligated to plan its system to meet all of its firm loads,including any prospective rollovers of the transmission services used to meet those loads. Thus, if, a transmission customer requests transmission service for only one year, but thetransmission provider determines that it has native load growth or another contractobligation that commences in the future, it can reflect those obligations in the requested



24We also note that transmission customers do have incentives to request servicefor more than one year. If, for example, a transmission customer enters into a ten-yearcontract instead of a one-year contract, it does not face having to exercise its rolloverrights every year, with the risk that a competing customer seeks its transmission capacity,and the attendant risk that it must match any longer-term request in order to retain itstransmission service. The transmission customer with the ten-year contract has muchmore certainty than the customer with the one-year contract.

25Citing Nevada Power Co., 97 FERC ¶ 61,324 (2001) (Nevada Power) andPublic Service Co. of New Mexico v. Arizona Public Service Co., 99 FERC ¶ 61,162(2002) (PSNM).

long-term contract and thereby limit the prospective transmission customer's rolloverrights. If the transmission customer seeks service beyond the period when the nativeload growth or future contractual obligation becomes effective, it must pay for thefacility upgrades necessary to support its service request. Likewise, if a customerrequests transmission service for ten years, but the transmission provider indicates that ithas available capacity to provide the service for only three years, the customer must payfor facility upgrades if it wants service beyond the initial three-year period. Thus, if thetransmission provider properly reflects its planning in the initial transmission contract asdiscussed above, there will be no opportunity for a firm transmission service customer togame the system by requesting a shorter-term contract.24

B. APPLICATION OF ROLLOVER RIGHTS POLICY

i. Reservation in Initial Service Agreement

24. The Respondents state that the Commission's determination in the August Orderthat a transmission provider may only recall capacity to serve native load and only if thislimitation is forecasted and set forth in the initial service agreement is a change in policyannounced in orders issued after the service agreement with Constellation was enteredinto, and could not have provided notice to the Respondents of the Commission'schanged policy.25 The Respondents argue that the Commission has changed its policyand has failed to provide adequate notice to all affected parties that the initial serviceagreements must include specific provisions reserving capacity for native load growth. The Respondents state that the one case cited by the Commission that was adopted priorto the execution of the Constellation service agreement, Public Service Co. of New



2685 FERC ¶ 61,240 at 62,006 (1998) (1998 PSNM Order).

27Further, we find the Respondents' attempt to distinguish the 1998 PSNM Orderto be misplaced. The 1998 PSNM Order was an order on rehearing addressing, amongother things, the requirement that "[t]he only way a transmission provider can reclaimcapacity is if it explicitly includes in future transmission agreements language that theright of first refusal does not apply due to a need for the capacity that is reasonablyforecasted at the time of the agreement's execution." 85 FERC at 62,006. See alsoPublic Service Company of New Mexico, 82 FERC ¶ 61,127 at 61,457 (1998). What isrelevant for purposes of the instant rehearing is that both of these cases confirm andapply the Commission's policy that limitations to rollover rights must be included in theservice agreement when it is first executed, thereby refuting the Respondents' argumentthat the Commission's action constitutes a change in policy.

Mexico,26 did not involve a situation such as the one they face, where a specifictransmission service agreement had expired and the capacity was simply not available. The Respondents argue that the 1998 PSNM Order involved attempts by a singletransmission provider to modify its tariff to place restrictions on its customers' rolloverrights in undefined situations. Therefore, the Respondents contend, the 1998 PSNMOrder was inadequate to put the industry or them on notice as to the Commission'schanged interpretation of Section 2.2. and should not be applied here.

25. SPP adds that, if the Commission does not grant rehearing, it should state that theAugust Order applies prospectively only to service agreements entered into after the dateof the Commission's rehearing order in this proceeding or at least as of the date of theCommission's decision in Exelon. SPP also requests that the Commission state that theneed to satisfy native load growth is not the only reason why a rollover request can bedenied, and that factors other than native load growth can justify rejection of a rolloverrequest, if specified in the service agreement. SPP contends that the Commission shouldstate that any such limitation can be specified in both the initial service agreement andany agreement for a renewal term, not just in the initial service agreement.

Commission Response

26. We disagree with the Respondent's argument that the Commission's action in the1998 PSNM Order, the August Order, and in other orders issued after the serviceagreement with Constellation was executed constitutes a change in its policy with regardto rollover rights.27 To the contrary, our action in the August Order and the other casescited by the Respondents is fully consistent with the rollover rights policy that weestablished in Order No. 888. In announcing the rollover rights policy in Order No. 888,



28Order No. 888 at 31, 694.

29Order No. 888-A at 30,198.

30See, e.g.,1998 PSNM Order, 85 FERC at 62,066 (discussing requirement to stateexpressly in future transmission contracts (as distinguished from existing (i.e., pre-OrderNo. 888) contracts) if the right of first refusal does not apply due to a need for thecapacity that is reasonably forecasted at the time of the contract's execution; PSNM, 99FERC at 61,667; Nevada Power, 97 FERC at 62,493.


we explained that there are circumstances under which a transmission provider canrestrict a transmission customer's rollover rights under Section 2.2. For example, theCommission determined that public utilities may reserve existing transmission capacityneeded for native load growth reasonably forecasted within the public utility's currentplanning horizon.28 In Order No. 888-A, the Commission stated that "if a utility providesfirm transmission service to a third party for a time until native load needs the capacity, itshould specify in the contract that the right of first refusal does not apply to that firmservice due to a reasonably forecasted need at the time the contract is executed."29

27. Since the issuance of Order Nos. 888 and 888-A, the Commission has consistentlyreaffirmed this policy, stating that a transmission provider can deny a customer the abilityto roll over its long-term firm service contract if the transmission provider includes in theoriginal service agreement a specific limitation based on reasonably forecasted nativeload needs for the transmission capacity provided under the contract at the end of the contract term.30

28. The industry was on adequate notice with the issuance of Order Nos. 888 and888-A of the Commission's policy regarding restrictions on rollover rights. To theextent that, after the issuance of those orders, the Respondents were uncertain as to theCommission's policy in this regard, they could have sought clarification at that time. Inany event, because the 1998 PSNM Order, the August Order, and the other orders citedby the Respondents were fully consistent with the Commission's rollover rights policy asestablished in the rulemaking proceeding, none of those orders provided a "changedinterpretation of Section 2.2", as the Respondents contend.31 On this basis, we also willreject SPP's request that the Commission apply its policy prospectively only to serviceagreements entered into after the date of the Commission's rehearing order in thisproceeding or at least as of the date of the Exelon Order. We further will reject therequest that limitations on rollover rights can be specified in both the initial service



32See, e.g., Southwest Power Pool, Inc., 100 FERC ¶ 61,358 at P 12; SouthernCompany Services, Inc., 100 FERC ¶ 61,237 at P 17 (2002), reh'g pending.

33See Section 19.7 of the Order No. 888 pro forma tariff (concerning partialinterim service); see also Morgan Stanley Capital Group v. Illinois Power Company, 93FERC ¶ 61,081 at 61,220 (2000) ("[H]ad Morgan Stanley requested, for example, long-term service for a two-year period, but only one year was available, Illinois Power wouldhave been obligated to offer service for that one available year").

agreement and any agreement for a renewal term, not just in the initial service agreement. Commission precedent is clear that such limitations must be clearly stated in thecustomer's original service agreement.

29. SPP also requests that the Commission state that the need to satisfy native loadgrowth is not the only reason why a rollover request can be denied, and that factors otherthan native load growth can justify rejection of a rollover request, if specified in theservice agreement. In a number of recent orders, the Commission has addressed thisissue and specifically rejected requests by a transmission provider to reduce the capacityavailable for a renewal of transmission service by a transmission customer "due to factorssuch as changes in transmission system topology, loop flow impacts due to changes intransactions on other transmission systems, redispatch of designated networkresources."32

30. However, it may be reasonable for a transmission provider to limit the terms underwhich a new long-term agreement may be rolled over based on a pre-existing contractobligation that commences in the future. For example, to the extent that a SIS completedprior to the execution of the original service agreement indicates that available transfercapability to serve the customer will only be available for a particular time period, afterwhich time it is already committed to another transmission customer under a previously-confirmed transmission request (i.e., an agreement under which service would commenceat some time in the future), the transmission provider can reflect those obligations in thelong-term contract and thereby limit the prospective transmission customer's rolloverrights.33

ii. Tie-Breaker Provision

31. The Respondents argue that Order No. 888-A, the pro forma OATT, and priorCommission orders describe Section 2.2 as a tie-breaker provision to be used when there



34Citing Order No. 888-A at 30,198; Idaho Power, 94 FERC at 62,144-45;Entergy Power Marketing Co. v. Southwest Power Pool, 91 FERC ¶ 61,276 at 61,936(2000); Wisconsin Public Power Inc. Sys. v. Wisconsin Public Service Corp., 84 FERC ¶61,120 at 61,655 (1998).

are competing firm service requests.34 The Respondents further argue that theCommission's August Order directly contradicts the Commission's prior determinationsthat Section 2.2 is intended to provide certain existing customers with a reservationpriority when there is a competing request for long term firm point-to-point transmissionservice, and is not an absolute right to service.

Commission Response

32. Once again, the Respondents have misconstrued our previous orders. While it istrue, as SPP suggests, that Section 2.2 can serve a tie-breaking mechanism, that provisionis not intended to function only as a tie-breaker. In other words, the rollover rights policyis not intended to apply only when there are competing firm service requests. As wehave explained in previous orders, Section 2.2 provides a tie-breaking mechanism whena transmission provider has insufficient transmission capacity and there are competingrequests for that available capacity, including an existing long-term firm transmissioncustomer whose transmission service agreement is up for renewal or rollover. If thetransmission provider has insufficient capacity, then Section 2.2 provides a tie-breakermechanism that gives the transmission customer the right of first refusal. However, inthe absence of a competing request for service, the transmission provider is obligatedunder Section 2.2 to grant a request for rollover by an existing long-term transmissioncustomer (assuming that the transmission agreement contains no restrictions on rolloverrights, as discussed above).

C. APPLICATION OF THE PRO FORMA AND AEP OATTs

33. The Respondents argue that the August Order contravenes the plain terms of thepro forma and AEP OATTs that require that rollover requests be treated as newtransmission requests subject to the same procedures as all other requests, except thatsuch requests have certain priority rights over competing requests under Section 2.2. TheRespondents contend that under Section 2.2 of the AEP and the pro forma OATTs, anexisting long-term firm transmission customer has a "transmission reservation priority"over a competing request for firm transmission service, provided that the existing long-term firm customer is willing to match the term and price of the competing request. According to the Respondents, if competing existing firm service customers apply for



35Citing Entergy Power Marketing Corp. v. Southwest Power Pool, Inc., 91 FERC¶ 61,276 at 61,936 (2000) (Entergy).

service that cannot be fully provided, priority rights will be assigned in accordance withfirst-come, first-served principles. The Respondents argue that in an earlier decision, theCommission determined that "[b]y exercising a right of first refusal an existingtransmission customer is, in effect, arranging a new long-term firm point-to-pointtransmission service."35

34. The Respondents state that Sections 13, 17 and 19 of the pro forma and AEPOATTs set out the procedures for arranging firm point-to-point transmission service and,under Section 17.5, SPP is obligated to determine the amount of transmission capacityavailable when it receives a request for firm point-to-point transmission service of oneyear or greater. SPP argues that nothing in Section 17 exempts rollover customers fromthe process. SPP further argues that nothing in Section 19 of the pro forma and AEPOATTs, which sets out the requirements for System Impact and Facilities Studies,exempts rollover customers.

35. SPP contends that the August Order will interfere with the rights of customerswho executed longer-term firm transmission service agreements before many of the one-year service agreements, such as Constellation's, were entered into. SPP argues thatunder Section 13.2 of the AEP Tariff, these customers have a higher reservation prioritythan a transmission customer whose service agreement was executed later in time. SPPstates that a transmission provider has an obligation to offer an "infill" customertransmission capacity that will ultimately be needed by a higher priority customer at alater date, but the transmission provider is not required to grant a transmission customerwho comes later in time perpetual and superior rights to this capacity. SPP argues thatthe August Order will contravene Section 13.2 and give an "infill" customer rights to thecapacity that will prevent or impair the use by the higher priority customer.

Commission Response

36. Contrary to the Respondents' assertions, the August Order is entirely consistentwith the provisions of the pro forma OATT and AEP's OATT. In Order No. 888, weconcluded that, subject to certain limitations, all firm transmission customers(requirements and transmission-only), upon the expiration of their contracts or at the time



36Order No. 888 at 31,665.

37Entergy, 91 FERC at 61,936.

38Id.


their contracts become subject to renewal or rollover, should have the right to continue totake transmission service from their existing transmission provider.36

37. In Entergy, when we stated that "[b]y exercising a right of first refusal an existingtransmission customer is, in effect, arranging a new long-term firm point-to-pointtransmission service,"37 we did not mean that the rollover request was to be treated as anew long-term request for service for purposes of a new determination of availabletransmission capacity under Section 17.5 or a new system impact study. The issue inEntergy was the time period within which a customer exercising its right of first refusalmust make an application for its new service term and notify the transmission providerthat it wishes to exercise its reservation priority. We concluded that, "[c]onsistent withthe reservation procedures in Section 17.1, we clarify that the pro forma tariff requirescustomers to notify the transmission provider that they are exercising their right of firstrefusal at the time they tender their request for the new service term, which must be noless than 60 days prior to the date the existing contract ends and the new service termcommences. This procedure should provide sufficient protection to existing transmissioncustomers (our original rationale for establishing a right of first refusal) as well asprovide a reasonable and consistent notice period for all transmission reservations."38

38. We did not intend to suggest or imply that a transmission provider would make adetermination of available transmission capacity or perform a new system impact studyeach time that a long-term firm transmission customer elects to roll over its existingtransmission service, and SPP's arguments to the contrary are wrong. Indeed, such aninterpretation would effectively undermine the entire rollover rights policy established inOrder No. 888 and set forth in Section 2.2 of the pro forma OATT. The only instance inwhich a transmission provider can require a new system impact study for an existinglong-term customer seeking to rollover over its service would be where that customerrequests a change to a receipt or delivery point in an existing long-term firm transmissionservice agreement. In that instance, the customer's request can be treated as a newrequest for service for purposes of the availability of capacity.39 In Order No. 888-A,with respect to a proposal to limit the right of first refusal to the same points of receiptand delivery as the terminating service, the Commission explained that such a proposal:



40Order No. 888-A at 30,198, n. 52.

would competitively disadvantage existing customers seeking new sources ofgeneration. However, as we stated in Order No. 888, if the customer chooses anew power supplier and this substantially changes the location or direction of thepower flows it imposes on the transmission provider's system, the customer's rightto continue taking transmission service from its existing transmission providermay be affected by transmission constraints associated with the change.40

D. NOTIFICATION BY AEP OASIS POSTINGS

39. The Respondents argue that, in the August Order, the Commission ignores the factthat AEP's transmission customers have been provided with notice that transmissioncapacity along key portions of the AEP transmission system is limited, especially withrespect to north-to-south transfers such as the transaction at issue. The Respondents statethat AEP had posted notifications since May 1997, more than two years before theservice agreement with Constellation was executed, that capacity for north-to-southtransactions is becoming increasingly limited, and that AEP does not expect to be able toaccommodate firm transactions. Respondents argue that by the various postings onAEP's OASIS, transmission customers are fully apprised of the limitations, including thedetailed projections of native load growth underlying the limitations, and have notice thatrenewals might be adversely affected. AEP contends that the Commission, in rejectingthe proposed limitation on renewal in the service agreements filed in Docket No. ERO2-2028-000 as insufficiently specific, ignores these OASIS postings which it arguesprovides the necessary specificity.

Commission Response

40. As we have stated, there are certain limited circumstances under which atransmission provider can restrict a transmission customer's rollover rights under Section2.2 if those restrictions are clearly stated in the initial service agreement between theparties. On this basis, posting of anticipated transmission limitations on AEP's OASIS isnot an acceptable method for restricting a customer's rollover rights. Because theoriginal service agreement here contains no such limitations on Constellation's rolloverrights, Section 2.2 of the AEP OATT controls.



41. Based on the foregoing, we deny the Respondents' requests for rehearing. Furthermore, we dismiss SPP's request that, in the alternative, the findings in the AugustOrder be applied prospectively only.


SPP's and AEP's requests for rehearing are hereby denied.

By the Commission.

( S E A L )

Magalie R. Salas, Secretary.


Notice: This opinion is subject to formal revision before publication in theFederal Reporter or U.S.App.D.C. Reports. Users are requested to notifythe Clerk of any formal errors in order that corrections may be madebefore the bound volumes go to press.

United States Court of AppealsFOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued March 8, 2004 Decided May 14, 2004

No. 03-1162

CONSUMERS ENERGY COMPANY,

PETITIONER

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

ONTARIO ENERGY TRADING INTERNATIONAL CORPORATION AND

INDEPENDENT ELECTRICITY MARKET OPERATOR,

INTERVENORS

On Petition for Review of Orders of theFederal Energy Regulatory Commission

Raymond E. McQuillan argued the cause for petitioner.On the briefs was Deborah A. Moss. Jon R. Robinsonentered an appearance.

Bills of costs must be filed within 14 days after entry of judgment.The court looks with disfavor upon motions to file bills of costs outof time.

2

Lona T. Perry, Attorney, Federal Energy RegulatoryCommission, argued the cause for respondent. With her onthe brief were Cynthia A. Marlette, General Counsel, andDennis Lane, Solicitor.

Matthew W.S. Estes was on the brief for intervenors.Howard E. Shapiro and John J. Buchovecky entered appear-ances.

Before: GINSBURG, Chief Judge, and RANDOLPH andROBERTS, Circuit Judges.

Opinion for the Court filed by Circuit Judge ROBERTS.

ROBERTS, Circuit Judge: It was a close thing, but BenedictArnold’s bold plan to capture Canada for the Revolution fellshort at the Battle of Quebec in early 1776. As a result, theFederal Energy Regulatory Commission must now decidewhen affiliates of Canadian utilities — utilities not subject toFERC jurisdiction — may sell power at market-based ratesin the United States. In a purely domestic case, FERCrequires an applicant for market-based rates to show that itand its affiliates do not have or have adequately mitigatedmarket power in generation and transmission, and cannoterect other barriers to entry. An applicant with a transmis-sion-owning affiliate must show that the affiliate has filed anopen access, non-discriminatory tariff for transmission ser-vice. See Progress Power Marketing, Inc., 76 FERC ¶ 61,-155, at 61,919 (1996).

FERC does not presume to tell foreign transmission-owning utilities what tariffs they must file. If a marketingaffiliate of such a utility wants to sell power at market-basedrates in the United States, however, the utility must offertransmission service comparable to that required of a utilityin the United States. Just as a domestic transmission-owningutility must allow competitors of its marketing affiliate to useits transmission services on a non-discriminatory basis tocompete with the marketing affiliate, so too a foreign trans-mission-owning utility must allow companies that would com-pete with its marketing affiliate to use its transmission ser-vices to reach the United States market and compete on a

3

level playing field with its marketing affiliate. See EnergyAlliance P’ship, 73 FERC ¶ 61,019, at 61,030–31 (1995).

In this case, Ontario Energy Trading International Corpo-ration (Ontario Energy) sought authority to sell power in theUnited States at market-based rates pursuant to Section 205of the Federal Power Act, 16 U.S.C. § 824d. Ontario Ener-gy’s application was opposed by Consumers Energy Company(Consumers), a public utility providing service in Michiganand potentially facing competition from Ontario Energyacross the border. Consumers argued that the Ontario Inde-pendent Electricity Market Operator (IMO) was an affiliate ofOntario Energy and did not offer open access, non-discriminatory transmission service comparable to that re-quired of power companies in the United States. Specifically,Consumers complained that the IMO did not offer transmis-sion service from point A to point B at all, as a United Statesutility would, but instead required companies seeking suchservice to sell power into the system at point A and buy itback out at point B. FERC nonetheless found the IMOservice comparable to that required of companies in theUnited States, and granted Ontario Energy the requestedauthority to sell power at market-based rates. See OntarioEnergy Trading Int’l Corp., 99 FERC ¶ 61,039 (Initial Or-der), on reh’g, 100 FERC ¶ 61,345 (2002) (September 2002Order), on reh’g, 103 FERC ¶ 61,044 (2003) (April 2003Order). Finding that substantial evidence supports the Com-mission’s decision and that the decision is otherwise reason-able, we deny Consumers’ petition for review.

I. Background

In its landmark Order No. 888, FERC required publicutilities subject to its jurisdiction that own, control, or operatetransmission facilities to guarantee non-discriminatory trans-mission service to all market participants. See PromotingWholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities;Recovery of Stranded Costs by Public Utilities and Trans-mitting Utilities, FERC Stats. & Regs. ¶ 31,036, at 31,635–36

4

(1996) (Order No. 888). To ensure non-discriminatory ser-vice, the Commission required public utilities (1) to functional-ly unbundle wholesale power services — separating genera-tion, transmission, and ancillary services, id. at 31,654, and (2)to file open access, non-discriminatory transmission tariffs, id.at 31,635. See generally New York v. FERC, 535 U.S. 1, 11(2002).

Foreign market participants may also obtain transmissionservice through a public utility’s open access tariff. Id. at31,689. Participants with foreign affiliates that own or con-trol transmission facilities, however, may obtain open accesstransmission only if those affiliates comply with tariff reci-procity requirements. Promoting Wholesale CompetitionThrough Open Access Non-Discriminatory TransmissionServices by Public Utilities; Recovery of Stranded Costs byPublic Utilities and Transmitting Utilities, Order No. 888-A,FERC Stats. & Regs. ¶ 31,048, at 30,290 (1997) (Order No.888-A). Those reciprocity requirements mandate that theforeign transmission-owning affiliate also provide open access,non-discriminatory transmission service in the same manneras a public utility in the United States. Id.

A. Restructuring the Ontario Energy Market

In 1997, Ontario Hydro, a government-owned utility servic-ing the Province of Ontario, sought a stay of Order No. 888’sreciprocity requirement. See Promoting Wholesale Competi-tion Through Open Access Non-discriminatory Transmis-sion Services by Public Utilities; Recovery of Stranded Costsby Public Utilities and Transmitting Utilities, 79 FERC¶ 61,182 (1997). The utility claimed that it would be irrepara-bly harmed by the requirement because it could not allowopen access into Ontario without the approval of the Provin-cial Government of Ontario. Id. at 61,866. The Commissionrejected the stay, Promoting Wholesale Competition ThroughOpen Access Non-discriminatory Transmission Services byPublic Utilities; Recovery of Stranded Costs by Public Utili-ties and Transmitting Utilities, 79 FERC ¶ 61,367 (1997),and the Province of Ontario elected to restructure its electric-

5

ity market in order to secure access to that of the UnitedStates.

At that time, the provincial energy market was dominatedby Ontario Hydro, a vertically integrated utility. OntarioHydro generated most of the Province’s power, owned andoperated the bulk electricity transmission system, owned andoperated much of the distribution system, sold power atwholesale rates to municipal utilities in urban areas, regulatedthose municipalities’ retail rates, and sold electricity directlyto retail customers in rural and suburban areas. See InitialOrder, 99 FERC at 61,145.

To establish a competitive market, the Ontario EnergyCompetition Act of 1998 unbundled the functions of powergeneration, power transmission, and control of the bulk powersystem. The Act separated those functions and transferredthem to three new entities: (1) Ontario Power Generation,Inc. (OPG) owns and operates power generation facilities; (2)Hydro One, Inc. owns and operates the transmission systemand portions of the distribution system; and (3) the IMOoperates the bulk power system and the wholesale electricitymarket. Application of Ontario Energy Trading Int’l ForOrder Approving Market-Based Tariff, at 3–4 (Ontario Ener-gy Application). The Provincial Government holds all theshares of both OPG and Hydro One, appointing the directorsof both. September 2002 Order, 100 FERC at 62,580. Ontar-io Energy — an electric power marketing company that buysand sells electricity, but itself owns no power generation ortransmission assets — is a wholly-owned subsidiary of OPG.The Provincial Government also appoints the directors of theIMO, a not-for-profit transmission and market operator.Those directors may be removed only for cause. Id. at62,581.

The IMO assumed operational control of Hydro One’stransmission assets, and became responsible for establishingand operating a provincial electricity market. See OntarioEnergy Application at 7–9. The Act required the IMO todevelop rules to open the market to competition on an openaccess, non-discriminatory basis. Id. at 9. The IMO com-

6

plied, promulgating rules that created a bid-based electricitymarket in which the cost of electricity is set by marketparticipants bidding to buy or offering to sell electricity. Id.Much like a stock exchange, the IMO administers the market,and is neither a buyer nor seller of electricity except whenrequired under emergency conditions to maintain systemreliability. See IMO Market Rules, Chapter 1, § 5.3.

The bid-based market administered by the IMO packagespower and transmission together as a single product. SeeBrief of Ontario Energy Trading Int’l Corp., Docket No.ER02-1021-000 (July 31, 2002), at 10–12 (Ontario EnergyFERC Br.). In the United States, most regional transmis-sion organizations (RTOs) and independent system operators(ISOs) treat power and transmission as two different prod-ucts. Indeed, Order No. 888 requires RTOs and ISOs toallow market participants to reserve transmission capacity ontheir systems in advance of power purchases. See Order No.888 at 31,938–39. In the United States, a power marketercan purchase the right to transmit power from point A topoint B at a set time for a set price, apart from the purchaseof power itself. Not so in Ontario. Entities wishing totransmit electricity through and out of Ontario, from point Ato point B, must sell power into the IMO market at point A toenter the transmission system, and then buy power from themarket at point B to exit the system. Because this distinc-tion is central to the comparability dispute before us, a moredetailed examination of the IMO market is in order.

B. The IMO Energy Market

The IMO operates a real-time electricity market, establish-ing a uniform market-clearing price for all electricity boughtor sold within Ontario. That uniform price is calculatedbased upon three factors: (1) the market price — matchingbids and offers; (2) the uniform uplift charge; and (3) trans-mission service charges. See Ontario Energy FERC Br. at10–12. The uniform uplift charge allocates the costs ofinternal congestion management across the market. See id.

7

at 11–12.1 Transmission service charges recoup the costs ofoperating the transmission system, and are regulated. Un-der this system, purchases and sales can be made at anylocation on the IMO system at the uniform market-clearingprice without regard to internal transmission limitations.

The IMO market uses the same system to facilitate importsinto and exports out of Ontario. The Ontario transmissionsystem is connected to adjacent regions’ transmission systemsthrough external interfaces called interties. Market partici-pants import power into the Ontario transmission system byselling electricity into the IMO market at one of the interties,while those wishing to export power out of the Province do soby purchasing electricity at an intertie adjacent to the desireddestination. Id. at 12. Congestion may occur at an intertiewhen the imports offered or exports sought exceed the trans-fer capability at that intertie. Unlike the situation withrespect to the internal congestion control system, the IMOcontrols congestion at the interties through a market-basedapproach.2 At each intertie, the IMO establishes an intertiezone price (IZP) set at the level at which supply meets

1 Even though transmission service is packaged with the pur-chase of electricity, the market price takes into account only thedemand for electricity, not the demand for transmission. Themarket price, in effect, assumes that the transaction costs oftransmission demand are zero so that purchased electricity can betransmitted immediately to meet real-time demand — a processtermed the ‘‘unconstrained dispatch solution.’’ The IMO marketactually uses a ‘‘constrained dispatch solution,’’ which allows someunits to transmit immediately while delaying others until transmis-sion capacity is available. That process generates costs to reim-burse the delayed units for any difference in price between thetransaction price and the actual price at the later time of transmis-sion. Those reimbursements are the cost of internal congestionmanagement, recouped through the uniform uplift charge.

2 The internal congestion approach of scheduling power dis-patches from generation facilities, see note 1 supra, is not viablebecause the IMO cannot require generation facilities outside Ontar-io to comply with dispatch schedules. Ontario Energy FERC Br.at 12.

8

demand within the transfer capacity of that intertie. See id.at 12–13. Put another way, the IZP clears congestion byprioritizing competing transfers according to price so that themost desired transfer clears first. See id. at 13.

Say a market participant wishes to export power from NewYork into Ontario. That participant must offer to sell thepower into the IMO market. If the market-clearing price inthe IMO is $20, and the quantity of power offered at or below$20 is equal to or less than the transfer capacity at the NewYork-Ontario intertie, then there is no congestion and allparties offering to sell power into Ontario for $20 or less willreceive the $20 market-clearing price. See id. In the samescenario, if the quantity of imports offered exceeds the trans-fer capacity at the intertie, then the IZP would fall below themarket-clearing price to reduce supply into the market — theIZP falling until enough market participants cease makingoffers to sell power into Ontario from New York.

Exporting power out of Ontario is accomplished in a similarfashion by purchasing power at the market-clearing price atan intertie adjacent to the desired destination. If the mar-ket-clearing price is $20 and the demand for exports out ofOntario at or above that price is equal to or less than thetransfer capacity of that intertie, then the transfer capacitycan accommodate the demand. See id. at 15. If the demandexceeds the transfer capacity, the IZP rises above $20 toreduce the demand, increasing until enough purchasers ceasebidding so that the transfer capacity can handle the remain-ing bids.

A party wishing to wheel power through the Province mustengage in a combined import/export transaction. As ex-plained, the IMO system packages transmission service withthe purchase of energy, so transmission service alone can beneither reserved nor obtained in a separate transaction, as itcan in the United States. Market participants wishing totransmit power, for example, from New York to Michiganthrough Ontario must simultaneously sell power into the IMOmarket at the New York-Ontario intertie and purchase powerout of the market at the Ontario-Michigan intertie. See id. at

9

16. Using the example above, if there is no congestion ateither intertie, then the wheeler would sell into the system atthe $20 market-clearing price and buy out of the system atthe $20 market-clearing price, resulting in an off-settingtransaction; the only cost would be an export fee. See id. Ifthere is congestion at either intertie, the cost would be theexport fee plus any difference between the IZP and themarket-clearing price at either intertie. Id.

Market participants can hedge the risk of congestion costsat interties during wheeling transactions by purchasing some-thing called financial transmission rights (FTRs). Id. at 17;see also April 2003 Order, 103 FERC at 61,174. FTRs arepurely financial instruments that entitle the holder to pay-ments equal to the difference between the Ontario market-clearing price and an IZP. The IMO maintains a market inFTRs, periodically auctioning FTRs that span durations ofeither one month or one year. Ontario Energy FERC Br. at17. Each FTR corresponds to a particular intertie; separateFTRs must be purchased for imports and exports at eachintertie. Id. FTRs effectively guarantee the import or ex-port of power at the uniform system-wide market-clearingprice, regardless of any IZP.

C. Procedural HistoryOn February 14, 2002, Ontario Energy filed its application

with the Commission under Section 205 of the Federal PowerAct, 16 U.S.C. § 824d, seeking authority to sell energy,capacity, and ancillary services, and to resell transmissioncapacity, at market-based rates. Initial Order, 99 FERC at61,145. Consumers filed a conditional protest to OntarioEnergy’s application, reserving the right to challenge theapplication if the IMO failed to grant a transmission reserva-tion allowing Consumers to wheel power through Ontario.Motion to Intervene and Conditional Protest of ConsumersEnergy Co. at 2–3. Consumers then went to the IMO andasked for approval of a ‘‘firm 50 MW transmission reservationfor May 2002’’ to facilitate its procurement of electricity fromNew York suppliers and transmission of that power throughOntario to Michigan. Letter from Consumers to IMO (Mar.

10

6, 2002). The IMO denied the request, explaining that theIMO system does not provide transmission reservations, butthat instead Consumers could perform an import/exporttransaction to wheel power through the Province. Consum-ers thereupon filed a supplemental protest to Ontario Ener-gy’s application, claiming that ‘‘Ontario Energy possess[es]transmission market power by virtue of its affiliation with TTT

the IMO, which is not mitigated by the provision of open-access transmission service.’’ Supplemental Protest of Con-sumers Energy Co. at 7.

In the Initial Order, the Commission concluded that Ontar-io Energy’s application presented ‘‘no transmission marketpower concerns,’’ finding that Ontario Energy does not ownor operate transmission facilities and is not an affiliate of anytransmission-owning public utilities. 99 FERC at 61,146–47.The Commission accordingly granted the application. Id. at61,147. Consumers sought rehearing, arguing that the IMOand Ontario Energy were affiliated entities and that the IMOdid not offer open access transmission service on a non-discriminatory basis comparable to the standards establishedin Order No. 888. September 2002 Order, 100 FERC at62,581 ¶ 12. This time the Commission agreed with Consum-ers that Ontario Energy and the IMO were affiliated, butdenied the request for rehearing, finding that the ‘‘IMOprovides open access transmission service on a comparable,non-discriminatory basis’’ in accordance with the principles ofOrder No. 888. Id. ¶ 13.

Consumers again requested rehearing. See April 2003Order, 103 FERC at 61,172. Having prevailed on the affilia-tion issue, it argued that the IMO’s service was not compara-ble to transmission service in the United States because theIMO does not allow the reservation of transmission capacity.According to Consumers, this inability to reserve transmis-sion capacity prevents market participants from obtaining afixed price for transmission service, creating price uncertaintyfor transactions through Ontario. Id. at 61,173. Pointing tothe fact that Ontario Energy could obtain firm transmissionservice reservations at a fixed price from utilities in theUnited States, Consumers argued that the IMO’s bid-based

11

market failed to satisfy the basic reciprocity requirements ofOrder No. 888. See id.

The Commission again denied Consumers’ request for re-hearing. The Commission noted that ‘‘Consumers concedesTTT there is no evidence in this case suggesting that the IMOoperates its transmission system on a discriminatory basis,’’and that the IMO’s governing statute prohibits such discrimi-nation. Id. at 61,174 ¶ 9. Rejecting Consumers’ claims con-cerning lack of comparability, the Commission found thatallegations of potential price increases caused by the IMO’sbid-based system failed to support ‘‘a finding that the designof the IMO’s transmission system, per se, unduly impedesConsumers, or any of Ontario Energy’s other competitors,from reaching United States loads.’’ Id. ¶ 10. To the con-trary, evidence showed that at least 12 United States-basedpower marketers had traded successfully in and out of theIMO market. Id. The Commission concluded that eventhough the IMO market does not offer the type of point-to-point transmission service required under Order No. 888,market participants can ‘‘obtain firm point-to-point servicethrough and out of Ontario at a price that is known inadvance (albeit through a process that involves both theadvance purchase of transmission rights and bidding to buyand sell energy in the Ontario energy market)’’ — ‘‘pro-vid[ing] open access transmission on a comparable, non-discriminatory basis for wheeling through and out of TTT

Ontario.’’ Id. ¶ 13.

Consumers petitioned this court to review the April 2002,September 2002, and April 2003 orders.

II. Analysis

1. This court reviews the award of market-based rateauthority to determine whether the Commission’s decisionwas arbitrary, capricious, an abuse of discretion, or otherwisenot in accordance with law. Louisiana Energy & PowerAuth. v. FERC, 141 F.3d 364, 366 (D.C. Cir. 1998). TheCommission’s factual findings are conclusive if supported bysubstantial evidence. 16 U.S.C. § 825l(b).

12

The Federal Power Act requires that public utilities charge‘‘just and reasonable’’ rates for the transmission or sale ofelectric energy. Id. § 824d(a). In competitive markets,‘‘FERC may rely upon market-based prices in lieu of cost-of-service regulation to assure a ‘just and reasonable’ result.’’Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870 (D.C. Cir.1993). ‘‘[T]he Commission approves applications to sell elec-tric energy at market-based rates only if the seller and itsaffiliates do not have, or adequately have mitigated, marketpower in the generation and transmission of such energy, andcannot erect other barriers to entry by potential competi-tors.’’ Louisiana Energy, 141 F.3d at 365 (footnote omitted);accord Order No. 888 at 31,656.

‘‘To demonstrate the requisite absence or mitigation oftransmission market power, the Commission normally re-quires a power marketer to show that a transmission-owningutility affiliate has on file with the Commission an open accesstransmission tariff for the provision of comparable services.’’TransAlta Enters. Corp., 75 FERC ¶ 61,268, at 61,875 (1996);accord Order No. 888 at 31,656–57. Order No. 888 mandatedthat public utilities file open access transmission tariffs that‘‘offer[ ] both network, load-based service and point-to-point,contract-based service,’’ and established a pro forma tariff todefine the ‘‘non-price minimum terms and conditions of non-discriminatory transmission’’ necessary for compliance. Or-der No. 888 at 31,636. Under the pro forma tariff, utilitiesmust offer firm point-to-point transmission service — trans-mission service ‘‘that is reserved and/or scheduled betweenspecified [p]oints of [r]eceipt and [d]elivery.’’ Id. at 31,931.Such transmission service allows market participants to re-serve transmission capacity to wheel power across differenttransmission systems, ‘‘provid[ing] a means for wholesalepower sellers and buyers to obtain transmission servicesnecessary to compete in, or to reach, competitive markets.’’Id. at 31,673.

As noted, the Commission does not require foreign utilitiesto implement Order No. 888 pro forma tariffs. TransAlta, 75FERC at 61,875 (‘‘[W]e have no direct authority to require[u]tilities, over which we do not have jurisdiction, to file an

13

open access tariff.’’). The Commission is instead ‘‘amenableto a variety of approaches’’ to show the absence or mitigationof transmission market power by foreign utility affiliates ofpower marketers, so long as the power marketer demon-strates that ‘‘its transmission-owning utility affiliate offersnon-discriminatory access to its transmission system that canbe used by competitors of the power marketer to reachUnited States markets.’’ Id. (citing Energy Alliance, 73FERC at 61,030–31). The Commission considers this ques-tion on a case-by-case basis. H.Q. Energy Servs. (U.S.) Inc.,79 FERC ¶ 61,152, at 61,652 (1997).

2. The obvious difference between United States and On-tario power markets — here, transmission and power can bemarketed separately; there, they must be bought and sold asa package — provided Consumers with a ready basis forarguing that the IMO ‘‘does not presently offer transmissionservice that is reciprocal or comparable or non-discriminatoryrelative to that provided in the United States.’’ Pet. Br. at18. According to Consumers, the IMO system does not allowthe reservation of firm point-to-point transmission at a defi-nite price, as required under Order No. 888. The systeminstead subjects market participants who wheel powerthrough Ontario to uncertainty in pricing based upon poten-tial congestion at interties. That uncertainty allegedly harmsConsumers in transactions involving wheeling energy fromNew York to Michigan through Ontario’s transmission sys-tem — when selling wholesale power in Michigan, any priceadvantage gained by Consumers from purchasing wholesalepower in New York could be lost in transmission throughOntario due to congestion costs at the interties. See id. at 23.

The Commission found, however, that because the IMOallows market participants to hedge the risk of congestioncosts at interties through the purchase of FTRs, which ‘‘pro-vide their holders with payments equal to the differencebetween the applicable intertie zone price and the system-wide price,’’ market participants seeking to wheel poweracross Ontario are able to obtain a fixed price for a throughand out transaction such as the one at issue in Consumers’petition — selling power into Ontario at the New York-

14

Ontario intertie and purchasing it back at the Ontario-Michigan intertie. See April 2003 Order, 103 FERC at61,174 ¶¶ 12, 13. Utilizing FTRs, market participants may‘‘obtain firm point-to-point service through and out of Ontarioat a price that is known in advance.’’ Id. ¶ 13. Although theIMO does not provide point-to-point transmission service inthe manner prescribed by Order No. 888, the Commissionreasonably concluded that the IMO provides comparabletransmission service. And that service is non-discriminatory:any entity desiring to transmit power from point A to point Bon the IMO system must engage in the same sell-in/buy-outsort of transaction. Affidavit of Cliff W. Hamal at ¶ 18.

Consumers argues that the Commission disregarded sub-stantial factual evidence showing that the IMO system fails tomitigate the generation market power of OPG, the parent ofOntario Energy. ‘‘OPG’s generation market dominance inthe IMO service area creates the potential for OPG to extractsignificant revenues by causing constraints and congestion-related price differentials at various export [interties].’’ Pet.Br. at 23–24. Consumers argues that OPG could, for exam-ple, flood the Ontario-Michigan intertie with export electrici-ty, purposefully driving up the price to wheel power throughOntario to Michigan. By thereby increasing the cost oftransmission, OPG could undercut Consumers’ ability to reapthe advantage of transporting cheaper New York power toMichigan through Ontario. OPG thus could establish a barri-er to market participants wishing to enter the Michiganmarket — or any other market with an adjacent intertie toOntario.

The Commission concluded that Consumers’ claims of po-tential price manipulation are ‘‘speculative, at best,’’ April2003 Order, 103 FERC at 61,174 n.10, and we agree. In itssecond application for rehearing, Consumers merely advancedbare allegations of potential price increases at the interties:‘‘Consumers allege[d] that the bid-based market operated bythe IMO may require Consumers to incur higher (unspeci-fied) costs to reach the Michigan market, in certain (unspeci-fied) instances when TTT the IMO TTT [must] address amarket constraint on its system,’’ id. ¶ 9. Consumers provid-

15

ed no evidence tying OPG’s market share to increased trans-mission prices or any episodes of discriminatory conduct. Id.at n.10.

On the other hand, substantial record evidence underminesConsumers’ abstract contentions. First, the Commissionfound that since May 1, 2002 — the commencement of theIMO-administered market in Ontario — 12 United States-based power marketers had traded successfully through andout of the Ontario transmission system at the Ontario-Michigan intertie. Id. ¶ 10. Next, even assuming that OPGcould manipulate prices by causing congestion at a particularintertie and raising the IZP, a market participant couldnegate any price impact by purchasing FTRs. Finally, theCommission found that OPG has no generating market poweroutside Ontario. See Initial Order, 99 FERC at 61,146.OPG thus would be cutting off its nose to spite its face bycongesting an intertie out of Ontario: that would increase theprice to export electricity, making it more difficult for OPG tocompete in the United States, where it would be selling moreexpensive electricity without the benefit of market power.We accordingly conclude that the Commission was reasonablein finding ‘‘no evidence TTT that Consumers has [been] or willbe impeded from reaching Michigan markets,’’ April 2003Order, 103 FERC at 61,174 ¶ 10.

Finally, Consumers broadly argues that simply because theIMO service is different from that required under Order No.888, it should not have been accepted by FERC: ‘‘Either theCommission believes its standards of market power mitiga-tion and open access transmission service are the right stan-dards, or it doesn’t[;] it should not matter in that context thatthe affected entities at issue are Canadian.’’ Pet. Reply Br.at 10. We think it reasonable for the Commission to acknowl-edge the reality of an international border in deciding wheth-er to insist on compliance with the minutiae of its regulatoryrequirements; it was certainly open to FERC to decide that aflexible approach requiring comparability on a case-by-casebasis rather than letter-for-letter compliance across-the-boardbetter accommodates jurisdictional limits and promotion ofcompetitive markets for United States loads. See EnergyAlliance, 73 FERC at 61,030 (FERC interest in imposing

16

comparability requirements on foreign affiliates is to promotecompetition to serve United States loads).

3. Consumers also argues that the IMO does not providecomparable service because it fails the particular indepen-dence requirements set forth in the Commission’s Order No.2000, 65 Fed. Reg. 809 (Jan. 6, 2000). Our jurisdiction islimited to objections that have been raised before the Com-mission in an application for rehearing. See 16 U.S.C.§ 825l(b) (‘‘No objection to the order of the Commission shallbe considered by the court unless such objection shall havebeen urged before the Commission in the application forrehearing’’). Consumers asserted an independence argumentbased on Order No. 2000 to challenge the Commission’s initialfindings on affiliation, not comparability. See Brief of Con-sumers Energy Co., Docket No. ER02-1021-001 (July 30,2002), at 5. Consumers won on affiliation; FERC would noteven have proceeded to address comparability in the absenceof such a ruling. Consumers did not separately argue belowthat the IMO’s lack of independence affected its ability toafford comparable transmission service, and such an argu-ment is distinct from a contention that entities are affiliatedso that the Commission must consider comparability. TheCommission, therefore, never had the opportunity to addressthe particular argument that Consumers now attempts toraise, and we accordingly lack jurisdiction to consider it. SeeCity of Orrville v. FERC, 147 F.3d 979, 990 (D.C. Cir. 1998).

* * *

The petition for review is denied.

El Paso Electric Company

Docket No. OA96-200-000

FEDERAL ENERGY REGULATORY COMMISSION - ALJ

84 F.E.R.C. P63,008; 1998 FERC LEXIS 1675

August 25, 1998

CORE TERMS: transmission, load, reliability, generation, generating, reservation, contingency,nomogram, customer, minus, tariff, pro forma, native, interconnection, backup, referencing,provider, reserved, anti-competitive, curtailment, calculation, capability, emergency, non-firm,derating, methodology, tie, forecast, third party, municipal

ACTION:[**1] INITIAL DECISION

SUBSEQUENT HISTORY:As Corrected September 2, 1998.

COUNSEL:

Appearances

James K. Mitchell, Esq. on behalf of El Paso Electric Company

Barbara A. Jost, Esq., Richard M. Lorenzo, Esq. and James C. Beh, Esq. on behalf of TucsonElectric Power Company

Michael J. Rustum, Esq. and Andrew D. Weissman, Esq. on behalf of Phelps Dodge Corporation

John T. Stough, Jr., Esq. on behalf of Public Service Commission of the State of New Mexico

Michael Small, Esq., Alan J. Statman, and Wendy N. Reed, Esq. on behalf of Southwestern PublicService Company

Paul E. Nordstrom, Esq., J. Cathy Fogel, Esq., Clinton A. Vince, Esq., and Sang Y. Paek, Esq. onbehalf of City of Las Cruces, New Mexico

William R. Mapes, Jr., Esq. on behalf of Coalition for a Competitive Electric Market

Page 1

John Bartus, Esq., Linda Walsh, Esq., Jane Froehlich, Esq., Roger E. Smith, Esq., Robert Fallon,Esq., Stan Berman, Esq., and Richard Miles, Esq. on behalf of the Federal Energy RegulatoryCommission

JUDGES: H. Peter Young, Presiding Administrative Law Judge.

OPINION:[*65,069]

H. PETER YOUNG, PRESIDING ADMINISTRATIVE LAW JUDGE

A. BACKGROUND/PROCEDURAL HISTORY

El Paso [**2] Electric Company ("El Paso" or the "Company") provides wholesale and retailelectric services in western Texas and southern New Mexico, including the City of Las Cruces, NewMexico ("Las Cruces"). Exh. EPE-1 at p. 9. The Company also provides wholesale electric servicesto Texas-New Mexico Power Company, Imperial Irrigation District (of California), and ComisionFederal de Electricidad ("CFE"), the state-owned Mexican electric utility.

El Paso has a net installed generating capacity of approximately 1,500 MW. This generatingcapacity consists of approximately 800 MW in the vicinity of El Paso, Texas; 600 MW from anuclear generating station located west of Phoenix, Arizona; and 104 MW from a coal-firedgenerating station located in the northwestern corner of New Mexico. Id. at pp. 9-10.

El Paso's electric system is part of the Western Systems Coordinating Council ("WSCC"). Thesystem is synchronized with other WSCC electric systems, which are linked to El Paso throughvarious AC interconnections. Id. at pp. 6-7; Tr. 96-100. El Paso is subject to WSCC reliabilitycriteria and operating requirements. Exh. EPE-1 at p. 10.

El Paso also is interconnected with the Southwest Power Pool [**3] ("SPP"). Because WSCCand SPP are not synchronized, electricity must be transferred between El Paso and SPP throughhigh voltage back-to-back (AC-DC-AC) interconnectionslocated near Clovis, New Mexico (the"Blackwater Tie") and Artesia, New Mexico (the "Eddy County Tie"). Id. at p. 7. Each of theseinterconnections incorporates a single 345 kV transmission line. Id. The Eddy County Tie's 345 kVtransmission line has a total transfer capability of 200 MW. El Paso owns approximately 133 MWof this capability. Id. at p. 27.

Las Cruces currently receives retail service from El Paso. Las Cruces has taken substantial stepstowards establishing a municipal system which would purchase its power requirements at wholesalefrom Southwestern Public Service Company ("SPS"), a member of SPP. SPS and El Paso aredirectly interconnected via the Eddy County Tie. Id. at pp. 7, 9; Exh. EPE-2; Exh. EPE-3. LasCruces and SPS desire to secure firm transmission service over the Eddy County Tie for the powerLas Cruces purchases from SPS. El Paso maintains that the Company is unable to provide that

Page 284 F.E.R.C. P63,008, *; 1998 FERC LEXIS 1675, **1

service.

On July 8, 1996, El Paso filed an open access transmission tariff ("OATT") pursuant to Order [**4][*65,070] No. 888. n1 El Paso's OATT provides for the network integration transmission service,firm and non-firm point-to-point transmission service and six ancillary services requiredby OrderNo. 888. Pursuant to the blanket suspension in Order No. 888, El Paso's OATT rates becameeffective, subject to refund, on July 9, 1996. Order No. 888 at pp. 31,768-69. On September 25,1996, the Commission issued an order establishing hearing procedures to address El Paso's OATT.See Long Sault, Inc., et al., 76 FERC P61,313 (1996). n2 The parties reached an agreement inprinciple concerning the Company's OATT rates for transmission and ancillary services in Januaryof 1997. El Paso filed an offer of settlement reflecting the parties' agreement on March 18, 1997(the "March Settlement"). The Presiding Judge certified the March Settlement to the Commissionon April 21, 1997. El Paso Electric Company, 79 FERC P63,005 (1997).

n1 Promoting Wholesale Competition Through Open Access Non- DiscriminatoryTransmission Services by Public Utilities, and Recovery of Stranded Costs by Public Utilitiesand Transmitting Utilities, III FERC Stats. & Regs., Regulations Preambles January1991-June 1996 P 31,036 (1996) ("Order No. 888"); Order on reh'g, III FERC Stats. & Regs.,P 31,048 (1997) ("Order No. 888-A"); Order on reh'g, 81 FERC P61,248 (1997); Order onreh'g, 82 FERC P61,046 (1998).

[**5]

n2 The September 26, 1996 order granted interventions in the instant proceeding to:Coalition for a Competitive Electric Market; NorAm Energy Services; PanEnergy Tradingand Market Services, L.L.C.; the Electric Consumers Resource Council and the AmericanIron and Steel Institute; Phelps Dodge Corporation; SPS; Las Cruces; Tucson Electric PowerCompany; and Public Service Company of New Mexico ("PSCNM").

On January 29, 1997-- subsequent to the parties reaching their agreement in principleconcerning the Company's OATT rates, but before the March Settlement was filed-- theCommission issued an order addressing issues presented in a number of OATT filings. SeeAmerican Electric Power Service Corporation, et al., 78 FERC P61,070 (1997)(the "January 29,1997 Order"). Among these issues was El Paso's proposed method for conducting its system impactstudy, including that methodology's implications for transmission service over the Eddy County Tie.

Page 384 F.E.R.C. P63,008, *65,069; 1998 FERC LEXIS 1675, **3

The January 29, 1997 Order consolidated El Paso's system impact study methodology with the rateissues set for evidentiary hearingin this [**6] proceeding. Id. at p. 61,264. The January 29, 1997Order also directed El Paso to file an "entirely new open access compliance tariff consistent with"both Order No. 888 and the January 29, 1997 Order. The Company filed a compliance tariff onFebruary 13, 1997. The compliance filing states that El Paso is "maintaining the full capacity of thetransmission transfer capability of the [Eddy County Tie] as capacity Benefit Margin (CBM) underits AT/TAC determination and thus is only able to use and sell the [Eddy County Tie's] transfercapability as non-firm transmission." See El Paso Compliance Filing, Open Access Tariff, OriginalSheet No. 150, Docket No. OA96-200-003 (February 13, 1997). Various parties filed protests to ElPaso's compliance filing on March 12, 1997. The compliance filing and protests currently arepending before the Commission.

The March Settlement reserved for litigation in this proceeding issues related to El Paso'ssystem impact study methodology, including whether the Company should be required to offer firmtransmission service over the Eddy County Tie. El Paso filed direct testimony on these issues onAugust 25, 1997. Las Cruces and Commission Staff ("Staff") [**7] filed answering testimony onOctober 9, 1997. SPS and Staff filed cross-answering testimony on November 13, 1997. El Pasofiled rebuttal testimony on December 11, 1997.

An evidentiary hearing was conducted from January 13, 1998 through January 15, 1998. Therecord was left open at the conclusion of the hearing to receive supplemental written testimony onone issue. Supplemental testimony was filed by Las Cruces, SPS and Staff, respectively, on January23, 1998, January 30, 1998 and February 10, 1998. Initial briefs were filed on February 27, 1998.Reply briefs were filed on March 24, 1998. Las Cruces submitted a motion for expedited initialdecision on August 6, 1998. n3

n3 The motion for expedited initial decision had no impact on the Initial Decision's dateof issuance. The presiding judge firmly believes that the delay between reply briefs andissuance of this Initial Decision is unacceptable. And while the delay is partially attributableto the presiding judge's hearing schedules in other proceedings, it is principally attributable topervasive inaccuracies contained in various parties' briefs. These inaccuracies compelled thepresiding judge to devote inordinate time and attention to reviewing the evidentiary recordand relevant authority to ensure that this Initial Decision relies on accurate facts, law andpolicy.

[**8]


B. ISSUE ANALYSES

1. Whether "Firm Transmission Service" is Defined or Sufficiently Described in theCommission's pro forma OATT and, If So, What is the Definition and Should that DefinitionBe Followed Here?

a. Party Positions

El Paso asserts that neither the Commission's pro forma OATT nor the statement ofconsiderations relating to that tariff describe [*65,071] the characteristics of "firm" transmissionservice or define "reliability," as that term applies to firm service. El Paso IB at p.8. El Pasomaintains that "firm" and "non-firm" are relative terms used exclusively to establish reservationprocedures and curtailment n4 priorities under the tariff. Id.; Exh. EPE-14 at p. 8. The Companynotes that the pro forma tariff requires transmission providers and their customers to followdifferent procedures to reserve firm and non-firm service, and also assigns a higher curtailmentpriority to firm service than to non-firm service. El Paso submits that while firm transmissionservice recipients enjoy curtailment priority equal to the transmission provider's native load, theprovider has no OATT obligation to accept a request for [**9] firm transmission service in thefirstinstance unless the provider determines that it has sufficient capacity to do so without impairingservice reliability to native load. El Paso IB at p. 9.

n4 The pro forma OATT defines "curtailment" as "a reduction in firm or non-firmtransmission service in response to a transmission capacity shortage as a result of systemreliability conditions." III FERC Stats. & Regs., Regulations Preambles January 1991-June1996 P 31,036, at p. 31,930, Definition 1.7.

Las Cruces appears to agree that the pro forma OATT does not define "firm" transmissionservice. Nevertheless, Las Cruces maintains that the pro forma tariff and El Paso's OATT eachsufficiently describes the salient characteristics of such service. Las Cruces IB at p. 6. Las Crucesargues that whether transmission service may be characterized as "firm" depends on the ability touse specific transmission capacity and the priority of that use. Las Cruces specifically distinguishesthis [**10] characterization from a guarantee that the capacity in question physically will beavailable at all times. Id.; Exh. CLC-2 at p. 15.


SPS contends that the difference between "firm" and "non-firm" transmission service under the proforma OATT depends on reservation and curtailment priorities. SPS IB at p. 8.

SPS emphasizes that the pro forma tariff's reservation and curtailment priorities requiretransmission providers to treat long-term firm point-to-point transmission service identically tonative loads. Thus, transmission providers cannot interrupt firm transmission service to facilitateeconomic transactions. Id.

SPS maintains that El Paso inappropriately distinguishes between "firm" and "non-firm"transmission service based on reliability criteria instead of the reservation and curtailment prioritiesspecified in the pro forma tariff and in the Company's own OATT.

Staff underscores the fact that the pro forma OATT defines "Firm Point-to-Point TransmissionService" as transmission service which is reserved under Part II of the tariff. Staff IB at p. 4. Staffreferences pro forma OATT Part II, Section 13, which is designated "Nature of Firm Point-to-Point[**11] Transmission Service," and which describes firm transmission service. Id. at pp. 4-5 (citingOrder No. 888-Aat pp. 30,515-18). Staff also references Part III, Section 1.21 of the pro forma tarifffor a description of firm transmission service. Id. at p. 5 (citing Order No. 888-A at p. 30,530).According to Staff, Parts II and III of the pro forma tariff define "firm" and "non-firm" service interms of reservation and curtailment priorities, and do not focus on reliability. Staff maintains thatsince El Paso has filed an OATT in compliance with Order No. 888, the Company should berequired to adhere to pro forma tariff definitions. Id. at p. 7.

Public Utility Commission of Texas ("PUCT") maintains that neither the pro forma OATT norOrder No. 888 addresses firmness in terms of reliability. PUCT IB at p. 4. Consistent with Staff'sposition, PUCT argues that the pro forma tariff defines "Firm Point-to-Point Transmission Service"and "Non-firm Point-to-Point Transmission Service" as transmission services which are reserved orscheduled under Part II of the tariff. Id. at pp. 4- 5. PUCT stresses that Part II of the pro forma tariffdescribes access and curtailment [**12] priorities, not reliability criteria. Id. at p. 6.

PSCNM also maintains that the pro forma OATT defines "firmtransmission service" as servicehaving specific reservation and curtailment priorities. PSCNM IB at p. 3. PSCNM asserts that thisdefinition is more limited than the industry's commercial definition, which is not based exclusivelyon economic criteria. Id. at p. 4, n.5.

b. Discussion

Whether "Firm Transmission Service" is defined or sufficiently described in the Commission'spro forma OATT, as well as the definition itself, are clear. The "Definitions" section of the proforma tariff specifically includes the terms "Firm Point-to-Point Transmission Service" and"Non-Firm Point-to-Point Transmission Service." The tariff defines these terms as follows:


1.13 Firm Point-To-Point Transmission Service: Transmission Service under this Tariff thatis reserved and/or scheduled between specified Points of Receipt and Delivery pursuant to Part II ofthis Tariff.

***

1.27 Non-Firm Point-To-Point Transmission Service: Point-To-Point Transmission Serviceunder the Tariff that is reserved [*65,072] and scheduled on an as-available basis and is [**13]subject to Curtailment or Interruption as set forth in Section 14.7 under Part II of this Tariff.Non-Firm Point-To-Point Transmission Serviceis available on a stand-alone basis for periodsranging from one hour to one month.

III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P 31,048, at pp.30,508-09 (1997).

Part II of the pro forma tariff establishes the parameters of "Firm Point-To-Point TransmissionService" by specifying minimum and maximum terms (i.e. durations), reservation and curtailmentpriorities, and scheduling restrictions. Id. at pp. 30,515-18. Part II of the tariff also establishes theparameters of "Non-Firm Point-To-Point Transmission Service" by specifying minimum andmaximum terms-- including a provision addressing sequential terms, reservation priorities, andcurtailment or interruption rights and criteria. Id. at pp. 30,518-20.

It follows that the Commissions's pro forma OATT on its face rebuts El Paso's assertion that thetariff does not describe the characteristics of "firm" transmission service. "Firm Point-To-PointTransmission Service" is specifically defined in the pro forma tariff. The definition [**14] is acomposite of the terms, reservation and curtailment priorities, and scheduling restrictions specifiedin Part II of the tariff. It is immaterial whether the tariff defines "reliability," as that term relates tothe definition of either firm or non-firm transmission service.

I find that the Commission's pro forma OATT defines "firm transmission service." Since El Pasohas filed an OATT in compliance with the pro forma tariff, I also find that the definition of "FirmPoint-To-Point Transmission Service" reflected in Part II of the tariff must be accepted by theCompany.

2. Whether Firm Transmission Service Should Be Available Over Any Transmission PathWhere the Delivery of Electricity is Dependent in Whole or in Part Upon the Availability of aSingle-Circuit Transmission Line Such as [the Eddy County Tie]

a. Party Positions

SPS and Las Cruces assert that El Paso agrees that "firm" transmission service, as contemplatedby the pro forma OATT, may be provided over the Eddy County Tie. SPS IB at pp. 13-15; LasCruces IB at p. 8 (referencing Tr. at pp. 262-63, 295, 314, 319). In addition, they cite various power


transactions and an emergency event [**15] involving the Eddy County Tie as evidence that the tieactually has been used to provide firm transmission service. SPS IB at pp. 13-15; Las Cruces IB atpp. 9-12. SPS and Las Cruces also maintain that the physicalcharacteristics of a single circuitinterconnection do not, in themselves, preclude firm transmission service over the interconnection.SPS IB at pp. 1-12; Las Cruces IB at pp. 8, 11-12.

PUCT also asserts that the Order No. 888 obligation to provide firm transportation serviceextends to single circuit transmission facilities. PUCT IB at p. 6. PUCT points out that aconsequence of limiting transmission service over such facilities to non-firm service would be thatthe service provider could interrupt the service for economic reasons. According to PUCT, OATTservice providers should not have the ability to interrupt customers who may have to rely ontransmission service merely because native load or network transmission customers n5 would paymore for the service. PUCT IB at p. 7.

n5 PUCT also includes firm point-to-point transmission customers in this category. Id.Firm point-to-point transactions should have no impact on economic curtailments of serviceover the Eddy County Tie, however, because it is the Company position that no firmtransmission service whatsoever should utilize a single circuit interconnection.

[**16]

PSCNM maintains that firm transmission service consistent with the pro forma OATT may beoffered over a single circuit facility, provided the customer recognizes the limitations of suchfacilities. PSCNM IB at p. 6. PSCNM emphasizes that an agreement to provide firm transportationservice under an OATT is not a guarantee of service under all conditions. Id. It notes that theservice provider retains the right to curtail service if an emergency or other unforeseen conditionimpairs or degrades system reliability. Id. at p. 7. PSCNM maintains that firm transmission servicecan be offered over the Eddy County Tie so long as the customer understands that the service is linecontingent and cannot be provided if the line goes out of service. Id. at pp. 7-8.

El Paso concedes that it physically is capable of offering "firm" transmission service over theEddy County Tie insofar as the ability to offer such service is determined in accordance withcurtailment priorities-- which the Company distinguishes from interruptibility due to the loss ofspecific interconnection facilities. El Paso IB at pp. 10-11. El Paso underscores that the loss of asingle circuit interconnection such as the [**17] Eddy County Tie could result in an actualinterruption in service if an alternate delivery path cannot be secured. Id. at p. 11. With thepreceding qualification, the Company indicates that it is willing to offer "firm" transmission


[*65,073] service over the Eddy County Tie "in conformance with the reservation and curtailmentpriorities set forth in Order [No.] 888." Id.; Tr. at 262-63.

Staff accepts El Paso's qualified position concerning firm transmission service over the EddyCounty Tie. Staff IB at p. 8. Staff emphasizes that whether transmission service may becharacterized as "firm" under Order No. 888 depends on the service's reservation and curtailmentpriorities, not its reliability. Id.; Exh. S-1 at pp. 10-11; Exh. S-7 at pp. 7-9. Staff therefore contendsthat firm transmission service should be offered over the Eddy County Tie irrespective of the tie'sdependence on a single circuit transmission line and the consequent possibility of interruption. Id.

b. Discussion

It has been established that the Commission's pro forma OATT does not define "firm"transmission service in terms of reliability. See Issue #1, supra. The tariff defines firm transmission[**18] service accordingto service durations, reservation and curtailment priorities, and schedulingrestrictions. See III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P31,048, at pp. 30,515-18 (1997). Every party has conceded this fact. El Paso IB at p. 8; Las CrucesIB at p. 6; SPS IB at p. 8; Staff IB at pp. 4-5; PUCT IB at pp. 4-5; PSCNM IB at p. 3. Consequently,the generic industry definition of "firm" transportation service-- service provided with a guaranteethat the loss of any single element in the service provider's system will not cause an interruption n6-- is inapplicable to service offered in accordance with the pro forma OATT. See also Exh. EPE-1 atp. 29; Exh. S-7 at p. 7; Exh. CLC-8 at pp. 1-2. Simply put, the ability to offer "firm" service inaccordance with the tariff is independent from the reliability of the service offered. It follows that"firm" transmission service, as contemplated by the pro forma OATT, may be offered over a singlecircuit HVDC interconnection. I therefore find that Order No. 888 requires firm transmissionservice to be offered over any single circuit HVDC interconnection-- including the Eddy County[**19] Tie-- if the interconnection has the capacity available to provide the service.

n6 This scenario commonly is referred to as an "N minus 1" contingency, where "N"represents an entire system and "minus 1" represents the loss of the largest single systemcomponent.

The preceding determination notwithstanding, the record establishes that single circuit highvoltage direct current ("HVDC") interconnections like the Eddy County Tie have physicallimitations which synchronous (AC) interconnections do not have. Exh. EPE-1 at pp. 22-23, 27-30;Exh. S-7 at p. 8; Exh. CLC-8 at pp. 1-2; Tr. at 262-64. When a single circuit HVDC interconnectiongoes out of service, transmission over the interconnection is impossible. The record also establishes


that the loss of a single circuit HVDC interconnection such as the Eddy County Tie could result inan actual interruption in service in the event that an alternate delivery path cannot be secured. n7Exh. EPE-1 at pp. 28-30; Exh. S-7 at pp. 8-9; Exh. CLC-8 at pp. 1-2; Tr. at 262-64. [**20] Itfollows that any customer seeking firm transmission service overthe Eddy County Tie under ElPaso's OATT implicitly acknowledges that the service cannot be provided in accordance with "Nminus 1" reliability criteria. By extension, any customer purchasing firm transmission service overthe Eddy County Tie assumes a risk that the service may be interrupted in the event that El Paso iscompelled to take the interconnection out of service in an emergency. I therefore find that whileOrder No. 888 requires El Paso to offer firm transmission service over the Eddy County Tie if it hasthe available capacity to do so, the service necessarily cannot be offered in accordance with "Nminus 1" reliability criteria.

n7 The only available alternate path to the Eddy County Tie is the HVDC Blackwater Tie.Exh. EPE-1 at pp. 7, 35-36; Exh. CLC-2 at p. 14; Exh. CLC-3.

3. Whether El Paso Agreed in the Settlement Agreement to Offer Firm Transmission Service Overthe Eddy County Tie

a. Party Positions

Staff maintains [**21] that El Paso agreed in the March Settlement to provide firm transmissionserviceover the Eddy County Tie. Exh. S-1 at pp. 4-5; Staff IB at p. 11. Staff cites Article II of theMarch Settlement's Introduction and Explanatory Statement, which states, in part:

Specifically, the long-term, point-to-point rate for firm transmission on EPE's system will be $2.31kW/ month. This rate will include service over the Eastern Interconnection Project and theMexican Border Crossing Facilities.

Staff also emphasizes that Article VI of the March Settlement provides that:

The Eastern Interconnection Project, and related facilities, will not be direct assignmentfacilities. Instead, service over the Eastern Interconnection Project, and related facilities, will beincluded in the base transmission rates.

According to Staff, the Eastern Interconnection Project includes the Eddy County Tie, and the basetransmission rates referenced in Article VI of the March Settlement include a network [*65,074]


revenue requirement and a rate for firm transmission service. Exh. S-1 at pp. 5, 8; Staff IB at p. 11.Staff maintains that these facts compel a conclusion that El Paso agreed to provide firm [**22]service over the Eddy County Tie. Exh. S-1 at p. 8; Staff IB at p. 11.

Las Cruces and SPS concur withStaff. They contend that El Paso agreed to provide firmtransmission service over the Eddy County Tie because the firm service rates reflected the MarchSettlement include the cost of that interconnection. Las Cruces IB at pp. 12-13 (referencing Exh.S-1 at pp. 4-5; Exh. SPS-17 at pp. 4-5); SPS IB at p. 16 (referencing Exh. SPS-17 at pp. 4-5; Exh.S-1 at pp. 4-5). n8

n8 In contrast to Exh. SPS-17 at pp. 4-5, which states that El Paso agreed to "provide"firm transmission service over the Eddy County Tie, SPS's Initial Brief states that El Pasoagreed to "offer" firm transmission service over the tie. It is unclear whether SPS intended todistinguish between offering and providing service.

El Paso distinguishes the March Settlement's agreement with respect to the rates to be chargedfor firm transmission service over the Eddy County Tie from an agreement actually to provide firmservice over the tie. El [**23] Paso argues the mere fact that the Company established rates for firmtransmission service over the interconnectionin compliance with Order No. 888 cannot be construedas an acknowledgment that El Paso actually had the available capacity to provide such service. ElPaso IB at p. 12; Exh. EPE-7 at p. 19. The Company maintains that no language contained in theMarch Settlement supports the Staff/Las Cruces/SPS argument to the contrary. El Paso IB at p. 12.El Paso also emphasizes that the March Settlement explicitly reserved for consideration in thisproceeding "system impact study issues, including system impact study issues relating to theEastern Interconnection Project." Id. (referencing March Settlement at p. 7). The Company submitsthat this provision would be meaningless if El Paso already had agreed to provide firm transmissionservice over that facility. Id. n9

n9 PSCNM does not take a position on Issue #3 through Issue #11, inclusive, nor on Issue#14.


b. Discussion

The March Settlement defines [**24] the "Eastern Interconnection Project" as "a back-to-backDC Terminal and a single 125 mile long 345 kV line that runs from the Artesia, New Mexicosubstation to the Amrad substation, near Oro Grande, New Mexico and associated transmission andsubstation equipment." March Settlement, Article I, Definition C. An examination of El Paso'sservice area maps demonstrates that this definition describes the Eddy County Tie. See Exh. EPE-2;Exh. EPE-3. It follows that the March Settlement language relied upon by Staff, Las Cruces andSPS applies to service over the Eddy County Tie.

An examination of the March Settlement itself, however, rebuts the Staff/Las Cruces/SPScontention that the settlement obligates El Paso to provide firm transmission service over the EddyCounty Tie. The March Settlement language cited by Staff, Las Cruces and SPS only addressesrates for firm transmission service over the Eddy County Tie. In addition, the settlement expresslyprovides that:

[El Paso] and the parties hereby sever the issues regarding [El Paso's] existing system impactstudy methodology from those resolved by this Stipulation for resolution in this proceedingseparately from the Stipulation. [**25] This means that system impact study issues, includingsystem impact study issues relating to the Eastern InterconnectionProject and associated facilities(such reservation specifically to include whether the [Eastern Interconnection Project] is to bereserved for purposes of a Capacity Benefit Margin and, if so, the rate consequences, if any, of suchuse...) will be severed for resolution in this proceeding.

March Settlement, Article VIII, System Impact Study Methodology (emphasis added). Order No.888 requires El Paso to accept a request for firm transmission service only if the Company hascapacity available to provide the service without impairing reliability to native load. n10 Since theMarch Settlement specifically severed the issue of whether Eastern Interconnection Project-- i.e.Eddy County Tie-- transmission capacity should be reserved to ensure reliability to native load asCapacity Benefit Margin ("CBM"), the only reasonable interpretation of the March Settlement isthat El Paso did not obligate itself to provide firm transportation service over the Eddy County Tie.Instead, the Company obligated itself to charge specific rates for firm transportation service [**26]over the tie in the event that it was determined in this proceeding that the service could be offeredwithout impairing reliabilityto native load. The March Settlement's reservation of Eddy CountyTie/CBM issues would be superfluous [*65,075] under the Staff/Las Cruces/SPS interpretation.

n10 Order No. 888 requires El Paso to offer to perform a System Impact Study toinvestigate alternate means by which the request could be accommodated in the event that theCompany determines that insufficient firm transmission capacity is available to accommodate


the request. III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P31,036 at p. 31,946.

In light of the preceding analysis, and the fact that Staff, Las Cruces and SPS have cited noMarch Settlement language that is inconsistent with that analysis, I find that El Paso did not agree toprovide firm transmission service over the Eddy County Tie under the March Settlement.

4. Whether El Paso's Failure to Provide Firm [**27] Transmission Service Over the EddyCounty Tie Violates Comparability

a. Party Positions

Staff, SPS and Las Cruces maintain that El Paso's failure either to provide (Staff) or offer(SPS/Las Cruces) firm transmission service over the Eddy County Tie violates Order No. 888's"comparability" requirement. Staff IB at p. 12; SPS IB at p. 17; Las Cruces IB at pp. 14-15. Staff,SPS and Las Cruces each allege that El Paso has provided what the pro forma OATT defines as"firm" transmission service to itself or third parties, and therefore is required to provide/offercomparable service to all third parties. Staff IB at pp. 13-14; SPS IB at p. 17; Las Cruces IB at pp.14-15.

Although El Paso initially construed firm transmission service as service provided in accordancewith "N minus 1" reliability criteria, the Company now acknowledges that firm transmission serviceover the Eddy County Tie must be offered to third parties under the OATT if there is capacityavailable on the interconnection. El Paso IB at p. 13; Tr. at 262. El Paso nevertheless reiterates thatsuch service may be interrupted if the Eddy County Tie goes out of service. Id. The Companymaintains that this [**28] reliability constraint applies to transmission service which El Pasoprovides to itself over the Eddy County Tie, and therefore satisfies Order No. 888's "comparability"requirement. El Paso IB at pp. 13-14.

PUCT echoes El Paso's position that the Company is required to provide "comparable"transmission service over the Eddy County Tie only if capacity is available to provide the service.PUCT IB at p. 8. PUCT also indicates that it considers El Paso's concern with respect to native loadrestrictions on the Company's ability to provide such service to be legitimate. Id.

b. Discussion

El Paso has conceded that the OATT requires the Company to offer firm transmission serviceover the Eddy County Tie. Nevertheless, there appears to be some disparity among the partiesconcerning the scope of El Paso's concession. This disparity suggests that Issue #4 warrantsclarifying discussion.


Order No. 888 specifies that:

An open access tariff that is not unduly discriminatory or anticompetitive should offer thirdparties access on the same or comparable basis, and under the same or comparable terms andconditions, as the transmission provider's uses of its system.

III FERC Stats. [**29] & Regs., Regulations Preambles, January 1991-June 1996 P 31,036, at p.31,647 (quoting American Electric Power Service Corp., 67 FERC P61,168, at p. 61,490 (1994)).Again, it has been established that the Commission's pro formaOATT defines "firm" transmissionservice exclusively according to service durations, reservation and curtailment priorities, andscheduling restrictions. See Issue #1, supra. Moreover, the record indicates that El Paso providesservice to itself over the Eddy County Tie which falls within the pro forma tariff definition of firmtransmission service. See Exh. S-1 at pp. 8-10; Exh. SPS-4; Exh. SPS-43 at p. 1; Exh. CLC-2 at p.14; Exh. CLC-5. It follows that Order No. 888 requires El Paso to offer comparable firmtransmission service to third parties over the Eddy County Tie, provided that the Company hastransmission capacity on the interconnection which is not legitimately dedicated to native load. Anyfailure to offer such service would violate the "comparability" requirement established in Order No.888. Whether El Paso has in fact violated Order No. 888's "comparability" requirement is addressedunder Issue # 8, [**30] infra.

5. Whether El Paso's Denial of Firm Transmission Service Over the Eddy County Tie orOther Segments of El Paso's System is Anti-Competitive or Affected by a Desire to Preventthe Formation of a Las Cruces Municipal Utility

a. Party Positions

Las Cruces states that, since 1987, it has taken significant steps towards establishing a municipalutility. n11 Las Cruces IB at p. 15. Las Cruces alleges that El Paso's denial of firm transmissionservice over the Eddy County Tie [*65,076] is merely the latest event in a systematic andprotracted Company attempt to derail Las Cruces's municipalization efforts. Id. According to LasCruces, El Paso affirmatively has attempted to thwart the formation of a Las Cruces municipalutility by exaggerating Las Cruces's stranded cost obligation, challenging Las Cruces's bondissuance, refusing to negotiate to sell distribution assets to Las Cruces, opposing the Las Crucesvoter referendum concerning establishment of a municipal utility, challenging Las Cruces's attemptto condemn El Paso's distribution facilities, and seeking to enjoin construction of a sub-stationintended to serve industrial load in the city. [**31] Id. at pp. 16-17 (referencing Exh. CLC-1 at pp.4, 7, 10, 11, 13-15). Las Cruces also alleges that El Paso has engaged in anti-competitive behaviorby affirmatively impeding third party access to the Company's transmission facilities. Id. at pp.17-19 (referencing Exh. SPS-17 at p. 3; Exh. SPS-18; Exh. SPS-36; Exh. SPS-38; Exh. SPS-43;Exh. CLC-2 at p. 11).


n11 Las Cruces indicates that it has: (1) prepared feasibility studies; (2) submitted offersto acquire El Paso's distribution facilities; (3) facilitated the enactment and approval of a 1991city ordinance establishing a municipal electric utility; (4) issued $ 72.5 million in revenuebonds to finance the acquisition of El Paso's distribution facilities; (5) declined to renew ElPaso's City of Las Cruces franchise; (6) issued Requests for Proposals resulting in theselection of SPS to provide wholesale power and other services to Las Cruces; (7) sponsoreda successful voter referendum supporting establishment of a municipal utility; (8) initiated aCommission proceeding to address stranded costs arising out of Las Cruces'smunicipalization; and (9) actively participated in El Paso's OATT proceedings. Las Cruces IBat pp. 15-16 (referencing Exh. CLC-1 at pp. 2-12).

[**32]

SPS alleges that El Paso's denial of firm transmission service over the Eddy County Tie isanti-competitive, and is intended to prevent both the formation of a Las Cruces municipal utility andany such utility's access to lower-cost energy. SPS IB at p. 18 (referencing Exh. SPS-17 at pp. 2-3;Exh. CLC-1). SPS underscores the fact that SPS and El Paso have a long history of competing forthe same loads, asserting that El Paso vigilantly has blocked SPS access to the El Paso system. SPSIB at p. 19. SPS also alleges that El Paso has engaged in anti-competitive behavior bysystematically impeding third party access to the Company's transmission facilities. Id. at pp. 19- 21(citing Southwestern Public Service Co. v. El Paso Electric Co., 80 FERC P61,159 (1997); EnronPower Marketing, Inc. v. El Paso Electric Co., 77 FERC P61,013 (1996); and referencing Exh.SPS-1 at p. 16; Exh. SPS-3; Exh. SPS-9; Exh. SPS-17 at p. 3; Exh. SPS-18; Exh. SPS-34; Exh.SPS-36; Exh. SPS-38; Exh. SPS-43; Exh. CLC-1 at p. 12).

Staff did not submit testimony on this issue, and (ostensibly) does not take a position withrespect to El Paso's conduct. Instead, Staff's briefs emphasize [**33] geography and history. Staffsuggests that geography in particularmotivates El Paso to resist providing transmission service tothird parties over the Eddy County Tie irrespective of the Company's ability to do so.

Staff summarizes the relevant geography as: (1) El Paso's system comprises the extreme easternend of the WSCC; (2) SPS's system comprises the extreme western end of the SPP; (3) WSCC andSPP are contiguous, and are interconnected via the Eddy County Tie; and (4) Las Cruces is atransmission-dependent customer located within El Paso's service area. Staff IB at p. 15.

Staff characterizes the relevant history as: (1) El Paso is Las Cruces's current power supplier; (2)Las Cruces seeks to form a municipal utility; (3) Las Cruces solicited bids from alternate powersuppliers; (4) SPS was the winning bidder, and would replace El Paso as Las Cruces's powersupplier; n12 (5) Las Cruces and SPS have attempted to secure firm transmission service from ElPaso over the Eddy County Tie; (6) El Paso has indicated that it will not provide firm transmission


service over the Eddy County Tie; (7) El Paso takes the position that it cannot provide firmtransmission service to third parties [**34] over the Eddy County Tie because the Company mustreserve that interconnection'stransmission capability as CBM n13 to serve native load; and (8) ElPaso's rebuttal testimony indicates that the Company's CBM must be even higher than originallyestimated for weather-related reasons. Id. at pp. 15-16.

n12 The record establishes that SPS and Las Cruces entered into a 15 year firm wholesalefull requirements power contract in 1994. See Exh. SPS-1 at p. 5; Exh. CLC-1 at p. 9.

n13 The record indicates that the CBM concept was developed by the North AmericanElectric Reliability Council ("NERC") in its determination of standards for calculatingavailable transfer capability under Order No. 888. See Exh. EPE-1 at p. 30 (quoting 1996NERC document designated "Available Transfer Capability Definitions and Determination");Exh. EPE-14 at p. 15 (quoting September 1997 NERC document designated "NERC PlanningStandards"). Although the original NERC documents referenced were not introduced intoevidence in this proceeding, El Paso introduced unchallenged pre-filed testimony quoting thedocuments and indicating that they define CBM as "the amount of transfer capability reservedby load-serving entities to ensure access to generation from interconnected systems to meetgeneration reliability requirements." Id.

[**35]

Staff distills the preceding geography and history into a scenario in which Las Cruces seeks tochange power suppliers, but El Paso simply refuses to provide the transmission service which wouldallow Las Cruces to purchase power from SPS. While Staff acknowledges that El Paso haspresented various technical and reliability-related reasons for refusing to provide the transmissionservice which SPS requires to deliver power to Las Cruces, it characterizes these reasons asmeritless. Id. at [*65,077] p. 16. According to Staff, El Paso is simply a high-cost energy producerresisting the loss of an important transmission-dependent customer.

Staff maintains that it is immaterial whether El Paso actually has engaged in anti-competitiveconduct: the Company's dedication of its Eddy County Tie capacity to CBM impairs Las Cruces'sability to receive lower-cost energy from alternate sources such as SPS. This, Staff asserts, isinconsistent with Order No. 888 because it allows El Paso to use control over transmission to thwartcompetition.

El Paso notes at the outset that its Eddy County Tie transmission capacity is limited to 133 MW.


El Paso IB at p. 14 (referencing Exh. EPE-1 at p. [**36] 27). The Companyasserts that it requiresall of this capacity to provide reliable service to native load under both emergency and normalconditions. Id. El Paso therefore contends that it has no firm transmission capacity on the EddyCounty Tie which it could offer to third parties under the OATT. Id. The Company characterizesany allegation that El Paso's denials of firm transmission service requests over the Eddy County Tieare motivated by anti-competitive intent as unsubstantiated speculation.

El Paso stresses that its OATT requires the Company to analyze transmission service requestsfrom El Paso's own merchant power division in the same manner as it evaluates third party requests.Id. at p. 15 (referencing Exh. EPE-5 at p.4). Contrary to Las Cruces's and SPS's allegations, theCompany maintains that its evaluation of firm transmission service requests is based exclusively onthe availability of capacity, determined in accordance with native load reliability constraints. ElPaso argues that no record evidence supports a conclusion that third party transmission servicerequests are evaluated in light of the requests' underlying purposes. Id. The Company categoricallydenies [**37] that the service requestdenials cited by Las Cruces and SPS were motivated byanti-competitive intent or by a desire to obstruct Las Cruces's formation of a municipal utility. Id. atpp. 15-16 (referencing Exh. EPE-7 at pp. 10, 14). El Paso maintains that those service requests hadto be denied because the transmission system was planned, designed and built in 1984--thus,necessarily without consideration of the open-access policy established by Order No. 888 in 1996.Id. at p. 16. Moreover, the Company contends that Order No. 888 does not require El Paso todeprive native load customers of capacity built specifically for their benefit in order toaccommodate third party transmission requests. Id.

b. Discussion

Las Cruces and SPS allege-- and Staff at least implies-- that El Paso's failure to provide firmtransmission service over the Eddy County Tie demonstrates anti-competitive intent or behavior.Las Cruces, SPS and Staff consequently bear the burden to prove that El Paso has acted withanti-competitive intent or in an anti-competitive manner. They have utterly failed to meet thisburden.

Although the Las Cruces/SPS/Staff arguments are logical and plausible, they are completely[**38] unsubstantiated in the record. Without more, a set of historical and geographicalcircumstances, no matter how suggestive, cannot support a finding of anti-competitive intent.Moreover, El Paso has provided substantial record evidence to support a conclusion that its refusalto offer firm transmission service over the Eddy County Tie is motivated-- indeed, necessitated-- byCBM requirements. See, e.g., Exh. EPE- 1 at pp. 30-31; 34; Exh. EPE-7 at pp. 2-3; Exh. EPE-14 atpp. 14-21. The Company also has provided substantial record evidence that it determines availabletransmission capacity on a non-discriminatory basis. See Exh. EPE-1 at pp. 11-14; Exh. EPE-4;Exh. EPE-5. In addition, Las Cruces/SPS/Staff have not demonstrated that Order No. 888 prohibitsEl Paso from rejecting third party transmission requests to ensure native load reliability. A findingof anti-competitive behavior would require substantial record evidence which discredits El Paso's


available transmission capacity calculus and its application of Order No. 888.

I find that the record before me is devoid of material evidence that El Paso's denial of firmtransmission service over the Eddy County Tie or other segments [**39] of the Company'ssystemestablishes anti-competitive intent or is motivated by a desire to prevent the formation of aLas Cruces municipal electric system. n14 Whether El Paso's reliance on CBM to deny firmtransmission service over the Eddy County Tie or other segments of the Company's system isanti-competitive depends on the appropriateness of El Paso's CBM reservation [*65,078] underOrder No. 888, which is addressed under Issue # 8, infra.

n14 In making this determination, I have examined the entire record, includingSouthwestern Public Service Co. v. El Paso Electric Co., 80 FERC P61,159 (1997); EnronPower Marketing, Inc. v. El Paso Electric Co., 77 FERC P61,013 (1996); Exh. SPS-1 at p. 16;Exh. SPS-3; Exh. SPS-9; Exh. SPS-17 at pp. 2-4; Exh. SPS-18; Exh. SPS-19; Exh. SPS-34;Exh. SPS-36; Exh. SPS-38; Exh. SPS-43; and Exh. CLC-1 at pp. 12-17. While thesematerials indicate that El Paso has opposed various third party transmission service requests,as well as some of the methods by which Las Cruces has attempted to form a municipalelectric system, they do not establish anti-competitive motivation or intent.

[**40]

6. Whether El Paso Properly Prepared and Documented its Nomograms in DeterminingSouthern New Mexico Transmission System Import Capability on El Paso's System, and ifProper Documentation Indicates that the Nomograms Were Not Properly Run, Whether ElPaso Should Be Required to Rerun the Nomograms

El Paso's transmission grid is part of the Southern New Mexico Transmission System("SNMTS"). El Paso owns all or part of three 345 kV transmission lines connecting SNMTS withWSCC. Exh. EPE-1 at pp. 6-9. In recognition of these ownership interests, SNMTS has allocated645 MW of firm transmission capacity over the lines to El Paso. Id. at p. 23. The Company uses thiscapacity to import power into SNMTS from outside sources. Id. at p. 25.

El Paso calculates its power transfer capability into SNMTS using system power flow studiesand nomograms n15 developed from those studies. Id. at p. 14. The nomograms reflect NERC andWSCC reliability criteria, and El Paso relies on the nomograms to operate SNMTS on behalf of thesystem's joint owners and to determine whether the Company has sufficient transmission capacity toaccommodate third party transmission requests over the three 345 [**41] kV transmissionlines


connecting SNMTS with WSCC. Exh. EPE-4 at p. 3.

n15 Nomograms are graphical or mathematical representations of the safe and reliableoperating limits across a range of system conditions determined in accordance with "N minus1" operating criteria. Exh. EPE-1 at p. 14.

a. Party Positions

Las Cruces submits that there is insufficient record evidence to determine whether El Pasoproperly prepared and documented its nomograms. Las Cruces IB at p. 19. Las Cruces characterizesEl Paso's nomograms as being based on "massive" load flow data and "numerous" modelingassumptions and simulation parameters. Id. Las Cruces complains that El Paso has data fromapproximately 30,000 load flow contingency runs, but has no studies or reports summarizing theload flow assumptions used to develop the nomograms. Id. According to Las Cruces, the lack ofsummary studies or reports prevents Las Cruces from determining whether the nomograms wereproperly prepared or are based on reasonable assumptions. Id. at [**42] pp. 19-20; Exh. CLC-2 atpp. 24- 25. Las Cruces maintains that unrealistic assumptions can have a dramatic impact on loadflow analysis results and, consequently, El Paso should be required to prepare detailed summariesdescribing the load flow data, modeling assumptions and simulation parameters which produced thenomograms. Las Cruces IB at p. 20; Exh. CLC-2 at p. 5. Las Cruces argues that El Paso should berequired to recalculate the nomograms if the summaries indicate that the nomograms wereimproperly prepared. Id.

Staff states that, like Las Cruces, it has not analyzed the extensive data underlying El Paso'snomograms, and consequently has not identified any specific problems in El Paso's load flowstudies. Staff IB at p. 18. Staff nevertheless takes the position that the Company's nomograms andload flow studies do not support a conclusion that firm transmission capacity over the Eddy CountyTie is unavailable. Id. n16

n16 Staff seems to misapprehend the issue. El Paso's nomograms concern import capacityover the AC lines connecting SNMTS with WSCC, not over the Eddy County Tie. See Exh.EPE-1 at p. 14.


[**43]

El Paso emphasizes that Las Cruces expressly concedes it did not take the opportunity to reviewEl Paso's load flow contingency data. El Paso IB at p. 17 (referencing Exh. CLC-2 at pp. 5, 25). TheCompany notes that Las Cruces had approximately six months to review the data underlying thenomograms in order to confirm that they were valid, but elected not to do so. Id. El Paso contendsthat it is inappropriate for Las Cruces now to insist that the Company prepare additional support forthe nomograms when Las Cruces has neither reviewed the substantial support already available noridentified any specific deficiency in the nomograms themselves. El Paso IB at pp. 17-18.

b. Discussion

There is absolutely no record justification for the Las Cruces/Staff position on this issue. Therecord indicates that the SNMTS nomograms were developed through iterative power flow studiessimulating a wide variety of actual and potential contingency conditions on the system. Exh. EPE-1at p. 15. The record also indicates that El Paso's nomogram studies were performed in accordancewith all applicable industry standards and criteria, and demonstrates in detail the nomograms'developmental methodology. [**44] Id. at pp. 14-22. Neither Las Cruces nor Staff has refuted thisevidence.

Moreover, the record conclusively establishes that: (1) the SNMTS nomograms were generatedbased on approximately 30,000 load flow contingency runs (Exh. CLC-2 at p. 25); (2) neither LasCruces nor Staff reviewed the load flow contingency data on which the nomograms [*65,079]were based (Id.; Staff IB at p. 17) n17 ; and (3) neither Las Cruces nor Staff has identified anyspecific deficiency in the data underlying the nomograms or in the nomograms themselves.Essentially, then, Las Cruces and Staff argue that El Paso should be required to prepare detailedsummaries describing the load flow data, modeling assumptions and simulation parameters whichgenerated the nomograms based on speculation that the Company could have used unrealisticassumptions in its load flow analyses. This argument is rejected for a number of reasons.

n17 Las Cruces and Staff do not allege that the load flow contingency data was not madeavailable to them, nor did either party make a motion to compel disclosure of this data or anyother materials related to the nomograms' development.

[**45]

First, Las Cruces and Staff apparently made no attempt to review the supporting data available


to them, which they concede was substantial. Exh. CLC-2 at p. 25; Staff IB at p. 17. Second, theyhad ample opportunity to seek additional information on discovery, but failed to do so. Third,nothing in 18 C.F.R. § 385.402, 18 C.F.R. § 385.405 or 18 C.F.R. § 385.406, the rules establishingdiscovery parameters in Commission proceedings, requires a participant to prepare studies orreports summarizing documentary evidence in its possession. It would be wholly improper underthe totality of circumstances in this case to require El Paso to prepare detailed summaries describingthe load flow data, modeling assumptions and simulation parameters which generated the SNMTSnomograms, particularly at this late date.

I find that there is no record evidence or other justification to require El Paso to prepare detailedsummaries describing the load flow data, modeling assumptions and simulation parameters whichgenerated the SNMTS nomograms. I find that any such requirement would be unduly burdensometo the Company. [**46] In addition, I find that El Paso properly prepared and documented theSNMTS nomogramssince the record contains substantial and unrefuted evidence that: (1) theSNMTS nomograms are based on adequate and appropriate data; (2) El Paso's nomogram studieswere performed in accordance with applicable industry standards and criteria; and (3) theCompany's SNMTS nomogram developmental methodology has been adequately explained.

7. Whether El Paso's Planning Improperly Imposes Multiple Contingency Criteria on OtherTransmission Customers Under the Method Incorporated in Attachment D of El Paso's TariffWhen El Paso Evaluates its Ability To Import Planned Levels of Emergency GenerationAssistance from Other Systems

The system impact study methodology filed by El Paso in this proceeding (El Paso OATT,Attachment D) states, in part:

The Transmission Provider's ability to import planned levels of emergency generation assistancefrom other systems will be studied to ensure that the reliability of service to Native Load Customersand Network Integration Transmission Service customers is not impaired by the requestedtransaction. The import capability values calculated from these cases [**47] shall be based onmodeling outages of various resources. In such study cases, different combination[sic] of generatorswill be reduced to zero MW and zero MVAR. The outraged [sic] generation will be replaced bymodeling imports from surrounding areas based on their expected ability to supply the power.

Exh. EPE-5 at p. 3. Staff, SPS and Las Cruces object to this language, expressing a concern that itmight permit El Paso to use multiple contingency reliability criteria to evaluate third partytransmission service requests while the Company applies "N minus 1" criteria to itself. See Exh. S-7at pp. 4-6; Exh. SPS- 21 at p. 3; Las Cruces IB at pp. 20-22.

El Paso responds that the "combination of generators" language contained in the system impactstudy methodology is erroneous. El Paso IB at p. 19. The Company represents that, consistent withNERC and WSCC standards, it evaluates all transmission service requests in accordance with "N


minus 1" reliability criteria. See Tr. 322-23. El Paso therefore has agreed to modify the systemimpact study methodology description contained in its OATT. Id. 322. See also El Paso RB at p. 9.

Accordingly, I find that this issue has been [**48] resolved by agreement among the parties. ElPaso must modify the system impact study methodology descriptioncontained in Original Sheet No.179 of the Company's OATT in a supplemental filing which clarifies the fact that all transmissionservice requests will be evaluated in accordance with "N minus 1" reliability criteria. While anacceptable modification would be to delete the words "combination of" from the methodologicaldescription contained in Original Sheet No. 179, I consider it unnecessary to dictate the Company'sprecise manner of compliance.

8. Whether El Paso's Reservation of 133 MW of Capacity in the Eddy County Tie for CBM isAppropriate, and if Not, How [*65,080] Much Capacity, if Any, Should Be Reserved forCBM

a. Party Positions

El Paso maintains that it must reserve the Company's entire 133 MW share of Eddy County Tietransmission capacity as CBM. n18

Exh. EPE-7 at p. 2. El Paso notes that utilities historically have relied on interconnected systems'generation and transmission resources to protect system reliability in emergencies. Exh. EPE-14 atp. 15. See also Exh. S-14 at p. 6. The Company emphasizes, however, that the third [**49] partyfirm transmission capacity reservations facilitated by open access can reduce a transmissionprovider's ability to ensure native loadreliability. El Paso IB at p. 20. According to El Paso, NERCtherefore permits utilities to reserve sufficient CBM to assure native load reliability. Id.

n18 Again, CBM is energy transfer capability reserved by load- serving utilities to ensureaccess to generation from interconnected systems to meet generation reliability requirementsimposed by native load. See fn. 12, supra.

El Paso also underscores the fact that WSCC has established guidelines contemplating thattransmission providers will reserve import capacity as protection against potential resourcecontingencies. Id. (referencing Exh. EPE-1 at p. 31). n19 The Company notes that the resourcecontingencies for which CBM may be reserved under the WSCC guidelines include (i) the need tomeet applicable operating reserve requirements, (ii) load forecast uncertainty, and (iii) the potential


for generation facility [**50] deratings for environmental reasons. Id. at p. 21 (referencing Exh.EPE-14 at p. 17).

n19 Exh. EPE-1 at p. 31 references a February 18, 1997 WSCC document designated"Determination of Available Transfer Capability within the Western Interconnection."Although the original WSCC document was not introduced into evidence in this proceeding,the portion of Exh. EPE-1 quoting the document was introduced unchallenged. Tr. 94.

El Paso asserts that its reservation of all 133 MW of Eddy County Tie transmission capacity asCBM is consistent with NERC and WSCC guidelines. Id. In support of this assertion, the Companyassumes 1997 peak load conditions. Id. El Paso then posits its most serious "N minus 1"contingency-- loss of the 150 MW Rio Grande #8 generating unit. In this circumstance, theCompany argues, "N minus 1" reliability requires El Paso to anticipate its system's next largestpotential hazard, which would be the loss of the 103 MW Newman #3 generating unit. n20 El Pasomaintains that this scenario results [**51] in a CBM requirement of 104 MW. Id.; Exh. EPE-14 atpp. 17-18. The CBM requirement increases to 199 MW when a five percent (5%) load forecastuncertainty (totaling 65 MW) and potential environmental deratings (totaling 30MW) are taken intoaccount. El Paso IB at p. 21; Exh. EPE-14 at p. 18. Since a 199 MW CBM significantly exceeds ElPaso's 133 MW transmission entitlement over the Eddy County Tie, the Company submits that itreasonably has allocated all of its Eddy County Tie entitlement to CBM.

n20 The record indicates that WSCC reliability criteria require El Paso to re-establish "Nminus 1" contingency preparedness within 60 minutes of the first contingency occurrence.See Exh. EPE-14 at pp. 9-10.

SPS maintains that it is inappropriate for El Paso to reserve any Eddy County Tie transmissioncapacity whatsoever as CBM. SPS IB at pp. 23-24. According to SPS, El Paso can re-establish "Nminus 1" reliability after losing the Rio Grande #8 generating unit without relying on the EddyCounty Tie. Id. at p. [**52] 25 (referencing Exh. SPS-11 at p. 5; Exh. S-1 at p. 12). SPS maintains


that EL Paso has 101 MW of internal generation reserves, and may access an additional 49 MW ofgeneration reserves from the Southwest Reserve Sharing Group ("SRSG")-- for which the Companyhas reserved 49 MW of CBM on its western transmission lines. SPS IB at p. 25 (referencing Tr.163-64, 167; Exh. EPE-1 at p. 34). SPS contends that El Paso can use the 150 MW of generatingreserves represented by these sources to re-establish "N minus 1" reliability after losing the RioGrande #8 generating unit. Id. n21

n21 SPS maintains that El Paso actually can cover an "N minus 2" contingency withoutreserving CBM on the Eddy County Tie. SPS asserts that 645 MW of firm transmissioncapacity on the Company's western AC lines is determined in accordance with "N minus 1"reliability criteria (assuming the loss of a single transmission line), and that El Paso accountsfor this contingency without resort to Eddy County Tie transmission capacity. SPS IB at p.26. SPS couples this assertion with its argument that El Paso may rely on a combination ofinternal generation and SRSG reserves to re-establish "N minus 1" reliability after losing theRio Grande #8 generating unit, concluding that the Company therefore can cover an "Nminus 2" scenario without reserving CBM on the Eddy County Tie. Id. This conclusionignores the fact that El Paso's second largest potential hazard is the loss of the 103 MWNewman #3 generating unit, and that this hazard, not the loss of one of the western AC lines,would be the appropriate planning assumption for an "N minus 2" contingency.

[**53]

In addition, SPS contends that El Paso's reservation of CBM on the Eddy County Tie assumes anon-existent contractual relationship with SPS. SPS emphasizes that while El Paso has anemergency service agreement with SPS, [*65,081] the Company has no firm entitlement to SPSgenerating reserves in the event that El Paso's internal generation fails. SPS IB at p. 30 (referencingExh. SPS-11 at pp. 5-6; Exh. SPS-15; Tr. 154-55). SPS argues that El Paso should not be allowed toreserve CBM over the Eddy County Tie when the Company has no firm entitlement to the energywhich would flow over the tie in an emergency. Id. at pp. 30-31.

SPS also challenges El Paso's reliance on (i) the Las Cruces and CFE loads, (ii) load forecastuncertainty and (iii) environmental derating components to support the CBM claim. Id. at pp. 27-32.According to SPS, the 1,107 MW local native load figure which El Paso used to calculate CBMshould be reduced by 300 to 320 MW to reflect future departures of the Las Cruces (100-120 MW)and CFE (200 MW) loads. Id. at pp. 27-28. SPS cites the facts that Las Cruces has entered into a 15year energy supply contract with SPS and that CFE is constructing a 600 MW [**54] generatingfacility, arguing that these circumstances render it inappropriate for El Paso to include the Las


Cruces/CFE loads in the CBM calculation. Id. at pp. 27-30. Moreover, SPS maintains that it isinappropriate for El Paso to buttress its CBM claim with load forecast uncertainty andenvironmental derating because these components are redundant. Id. at p. 31.

Finally, SPS claims that El Paso's 133 MW CBM reservation over the Eddy County Tieconstitutes a blatant abuse of the CBM concept. Id. at p. 32. SPS emphasizes that both NERC andthe Commission have expressed concerns that CBM could be used to anti-competitive effect. Id. atpp. 32-33 (referencing Exh. SPS- 11 at pp. 4-5; Exh. SPS-12; Exh. SPS-13 at p. 4; Tr. 156-58; andciting Pennsylvania-New Jersey-Maryland Interconnection, et al., 81 FERC P61,257, at p. 62,276(1997)). SPS contends that El Paso need not rely on the Eddy County Tie to cover an "N minus 1"contingency, and consequently should be prohibited from abusing the CBM concept by reservingCBM over the interconnection. Id. at p. 33.

Las Cruces also argues that it is inappropriate for El Paso to reserve Eddy County Tietransmission capacity as CBM. [**55] Las Cruces IB at p. 22. Las Cruces criticizes El Paso'sCBM calculation as being based on "worst [case] assumptions" with respect to load, generationoutages, load forecast uncertainty and generator deratings. Id. (quoting Exh. S-17 at pp. 11-12). LasCruces also maintains that El Paso's CBM calculation is inconsistent with the Company'snomograms. Id. According to Las Cruces, El Paso's "most critical single contingency" would be theloss of a 345 kV transmission line. n22 Id. (referencing Exh. CLC-17 at p. 6). Las Cruces maintainsthat El Paso's CBM calculation assumes this "N minus 1" contingency, and then anticipates twoadditional contingencies: the consecutive losses of the 150 MW Rio Grande #8 and the 103 MWNewman #3 generating units. Id. at pp. 23-24. Exacerbating this contingency pancaking, Las Crucesargues, El Paso overstates its western AC line reservations, and consequently can import more thanthe 49 MW of SRSG generation it has reserved over those lines. Id. at pp. 24-25. Las Cruces alsomaintains that its departure from El Paso's system will enhance the Company's import capabilityover the western AC lines. Id. at pp. 25-26.

n22 This language implies that Las Cruces disputes El Paso's contention that its mostserious "N minus 1" contingency would be the loss of the 150 MW Rio Grande #8 generatingunit.

[**56]

In addition, Las Cruces maintains that including load forecast uncertainty and generator deratingcomponents in El Paso's CBM calculation constitutes double counting. According to Las Cruces, ElPaso already accounts for load forecast uncertainty through resource planning/planning reserve


margins, and generator deratings should increase available transmission capacity. Id. at pp. 26-29(referencing Exh. S-6 at p. 4; Exh. SPS-45 at pp. 2-5; Exh. SPS-46; Exh. CLC-17 at p. 3; Exh. S-17at pp. 13-14).

Last, Las Cruces submits that El Paso should not be allowed to reserve CBM over the EddyCounty Tie to serve Las Cruces and CFE loads which intend to depart in the future, or when theCompany has no firm contractual entitlement to the SPS energy which would flow over the tie in anemergency. Las Cruces IB at pp. 29-31. Las Cruces also suggests that a CBM reservation over theEddy County Tie constitutes commercial abuse of CBM in derogation of NERC and Commissionobjectives. Id. at pp. 33-34.

Staff concedes at the outset that both NERC and WSCC recognize CBM as a legitimate use oftransmission capacity. Staff IB at pp. 20-21 (referencing Exh. EPE-1 at pp. 30-33).

Staff nevertheless [**57] emphasizesthat NERC working groups and the Commission haveexpressed concern over the potential to abuse CBM for anti-competitive purposes. Id. at pp. 21-22.Staff draws a distinction between CBM required to meet operating reserve requirements and CBMrequired to meet installed reserve requirements. Staff maintains that while El Paso requires no EddyCounty Tie CBM to meet operating reserve requirements, the Company has a legitimate need toreserve between 50 and 125 MW of Eddy County Tie transmission [*65,082] capacity as installedreserve CBM. Id. at p. 22. Staff also maintains that El Paso's installed reserve CBM requirementwould evaporate if Las Cruces were not part of the Company's native load. Id. n23

n23 PUCT makes essentially the same arguments as Staff. See PUCT IB at pp.10-17.

Staff does not dispute that: (1) as part of the SRSG, El Paso is required to maintain 101 MW ofinternal generating reserves; (2) El Paso may rely on an additional 49 MW of SRSG reserves foronly 60 minutes following [**58] an "N minus 1" contingency; and (3) El Paso's need to establishoperating reserve CBM should be based on the "N minus 1" contingency represented by the loss ofthe 150 MW Rio Grande #8 generating unit. Id. at pp. 22-23. Staff nevertheless disputes that thesefacts support a 133 MW operating reserve CBM reservation over the Eddy County Tie. Id. at p. 23.n24

n24 Like SPS and Las Cruces, Staff also criticizes El Paso's CBM calculation as being


based on a worst case scenario with respect to load, generation outages, load forecastuncertainty and generator deratings. See Exh. S-17 at pp. 11-12.

According to Staff, El Paso ignores an important distinction between the first 60 minutes of an"N minus 1" contingency and the period following the first 60 minutes. Id. at p. 24. Staff argues thatEl Paso can rely on 101 MW of internal reserves, coupled with 49 MW of SRSG reserves/ACinterconnection CBM, for the first 60 minutes of a 150 MW "N minus 1" contingency, and thereforerequires no additional CBM for this period. [**59] Id. at pp. 23-24. Staff submits that reserving anadditional 49 MW of Eddy County Tie capacity as CBM for the first 60 minute period is redundant.See Exh. S-7 at pp. 11-12. Further, Staff maintains, the Company can re-establish requiredoperating reserves in numerous ways in the sixty-first and ensuing minutes of the contingencyperiod. n25 As a consequence, Staff concludes that El Paso need not reserve any Eddy County Tiecapacity as operating reserve CBM. Staff IB at pp. 23-24.

n25 Staff cites contractual load interruption, operating generators at emergency levels,tapping available SNMTS firm and non-firm transmission capacity to import WSCC energy,and purchasing energy from SNMTS utilities. Exh. S-17 at p. 12.

With respect to installed reserve CBM, Staff accepts El Paso's 1998 to 2005 generating capacitypurchase forecasts of between 50 and 125 MW per year. Exh. S-7 at pp. 12-13; Exh. S-8 at p. 1;Exh. S-17 at p. 9. Staff submits that it is reasonable for the Company to reserve equivalent amountsof Eddy [**60] County Tie transmission capacity as CBMfor those years, provided Las Crucesremains part of El Paso's native load. Staff IB at p. 26. Since El Paso concedes that it would makeno firm generating capacity purchases if it did not serve Las Cruces, Staff submits that it would beunreasonable for the Company to reserve Eddy County Tie transmission capacity as CBM if LasCruces exits the El Paso system. Id.

b. Discussion

The record establishes that CBM enhances native load reliability, and that both NERC andWSCC recognize CBM as a legitimate use of transmission capacity. Exh. EPE-1 at pp. 30- 33; Exh.SPS-11 at pp.3-4; Exh. S-7 at pp. 9-10. The record also establishes that WSCC formally hasadopted NERC principles with respect to CBM. Exh. EPE-1 at pp. 31-33; Exh. SPS-11 at p. 4; Exh.S-7 at pp. 9-10. Additionally, the record establishes that El Paso is a member of WSCC and SRSG,


and is subject to WSCC/SRSG reliability criteria and operating requirements. See, e.g., Exh. EPE-1at p. 10; Exh. S-16. These facts are undisputed.

The preceding facts notwithstanding, reserving transmission capacity as CBM-- particularlyover constrained interconnections like the Eddy County Tie-- necessarily [**61] impedes thirdparty access (hencecompetition) to some degree. Further, NERC and the Commission haveexpressed concerns that CBM reservations could be used arbitrarily to impede open access. See,e.g., Exh. SPS-11 at p. 4; Exh. SPS-13 at p. 4; Tr. 156-57. See also Pennsylvania- NewJersey-Maryland Interconnection, et al., 81 FERC P61,257, at p. 62,277 (1997). It follows that thereis an inherent tension between Order No. 888's goals of promoting open access/competition andCBM's goal of ensuring native load reliability. The threshold issue to be decided therefore becomeswhether El Paso's CBM reservation over the Eddy County Tie is inconsistent with Order No. 888. Ifso, the reservation must be rejected absent compelling evidence supporting an exception toCommission policy. If not, the reservation must be examined to ensure that it is not overstated. Thisanalysis is required to promote the Commission's open access policy in a way which does notunreasonably impair reliability to El Paso's native load.

El Paso claims that Order No. 888 does not preclude the Company from reserving firm importcapacity required to protect native load reliability (i.e. CBM) simply because [**62] a third partyseeks accessto that capacity. El Paso IB at p. 25. No party challenges this claim. Moreover, OrderNo. 888 specifies that:

The amount of transmission capacity available to wholesale and unbundled retail customers[*65,083] under the Final Rule pro forma tariff is clearly affected by the amount of transmissioncapacity that the transmission provider reserves for the use of its native load customers and thefuture load growth of those customers. The transmission provider may reserve in its calculation ofATC transmission capacity necessary to accommodate native load growth reasonably forecasted inits planning horizon. However, the transmission provider is obligated to provide transmissionservice to others under the Final Rule pro forma tariff out of capacity reserved for native loadgrowth up to the time the capacity is actually needed for such future needs.

III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P 31,036, at p. 31,745.This language supports an inference that the Commission intended available transmission capacity("ATC") to be calculated by first subtracting existing native load, including a reliability component.[**63] n26 It also indicates that while transmission providers may reserve capacity to serve bothnative load and reasonably forecasted native load growth, capacity reserved for native load growthmust be made available to third parties until the capacity actually is needed and used. See also Id. atp. 31,694.


n26 Quantification of native load in accordance with Order No. 888 subsumes a reliabilitycomponent. See III FERC Stats. & Regs., Regulations Preambles, Definition 1.19, P 31,048,at p. 30,508.

I find that the reservation of transmission capacity as CBM to ensure reliability to native loadand native load growth is consistent with Order No. 888. In addition, I find that any transmissioncapacity (including CBM) reserved for native load growth must be made available to third partiesuntil the capacity actually is needed and used.

Turning to the amount of Eddy County Tie capacity that El Paso has reserved as CBM, theobjections may be summarized as: (1) El Paso's CBM calculation should not be based on 1997 peak[**64] load; (2) the Company has not calculated CBM in accordance with an "N minus 1"contingency; (3) CBM transmission capacity cannot legitimately be reserved in the absence of afirm entitlement to emergency generation; (4) the Las Cruces and CFE loads should not be includedin the CBM calculation; (5) the CBM calculation should not include/double counts load forecastuncertainty or environmental derating components; and (6) El Paso's Eddy County Tie CBMreservation is an anti-competitive device intended to impede open access. These objections will beanalyzed in order.

El Paso's CBM calculation assumes 1997 peak load conditions. Exh. EPE-14 at pp. 17-18. Staffand Las Cruces object to using peak load conditions as the basis for calculating CBM. Theymaintain that calculating CBM based on peak load assumes unlikely and unrealistic circumstances.Exh. S-17 at p. 11; Las Cruces IB at p. 23 (quoting Exh. S-17 at p. 11). The record, however,establishes that CBM is intended to assure native load access to adequate generation at all times.Exh. EPE-1 at pp. 30-33; Exh. SPS-11 at pp.3-4; Exh. S-7 at pp. 9-10. In light of that objective, itwould be imprudent for the Company to calculate CBM [**65] based on anything but peak load.Otherwise, the "N minus 1" contingency-- which, by definition, represents the most extremescenario-- would be inherently understated. Moreover, while Staff and Las Cruces criticize El Paso'speak load assumption, they propose no identifiable alternative. I find that the Company's CBMcalculation appropriately assumes peak load conditions.

The record establishes that WSCC and SRSG reliability and operating criteria require El Paso tooperate its system to provide "N minus 1" reliability. See, e.g., Exh. EPE-1 at pp. 10, 33-34; Exh.S-16. As noted previously, an "N minus 1" operating scenario assumes the loss of the largest singlesystem component. The record indicates that El Paso's most serious "N minus 1" contingency wouldbe the loss of the 150 MW Rio Grande #8 generating unit. Exh. EPE-1 at p. 34; Exh. EPE-14 at p.17; Exh. SPS-33 at p. 2; Tr. 163. n27 The Company maintains that the "N minus 1" reliabilitystandard also requires El Paso to anticipate its system's next largest potential hazard-- loss of the103 MW Newman #3 generating unit-- as soon as the Rio Grande #8 generating unit is lost. The


other parties characterize this as multiple ("N [**66] minus 2") contingency planning.

n27 Las Cruces asserts that El Paso's "most critical single contingency" would be the lossof a 345 kV transmission line. See Exh. CLC-17 at p. 6. This assertion is inadequatelysupported by the record.

The record establishes that El Paso has 101 MW of internal spinning reserves and is entitled toan additional 49 MW of SRSG spinning reserves. Exh. EPE-1 at p. 34; Exh. EPE-7 at p. 25; Exh.S-7 at pp. 11-12; Tr. 163-64, 167. The record therefore indicates that El Paso has sufficient spinningreserves to offset a loss of its 150 MW Rio Grande generating unit #8. Nevertheless, the recordindicates that El Paso has a firm entitlement to 49 MW of SRSG spinning reserves for only the first60 minutes of an "N minus 1" contingency. Exh. EPE-7 at pp. 24-25. More important, WSCCreliability criteria require the Company to re-establish "N [*65,084] minus 1" contingencypreparedness within 60 minutes of an "N minus 1" contingency occurrence. See Exh. EPE-14 at pp.9-10. Exh. EPE-7 [**67] at pp. 24-25. Once the Company taps its 150 MW of internal and SRSGspinning reserves, however, those resources no longer function as available reserves for reliabilitypurposes. See, e.g., Exh. S-7 at p. 11. It follows that WSCC reliability requirements compel El Pasoto reserve additional transmission capacity if the Company's ability to recover fully from a RioGrande generating unit #8 loss within 60 minutes is uncertain.

The SPS/Las Cruces/Staff argument that this reservation constitutes "N minus 2" contingencyplanning is based on a faulty premise: it assumes a static set of circumstances. The whole purposeof contingency planning is to ensure reliability in dynamic and uncertain circumstances. The recordbefore me is far from conclusive that El Paso could fully recover from the loss of its Rio Grandegenerating unit #8 within 60 minutes under all circumstances. n28 Since the loss of the 103 MWNewman #3 generating unit constitutes the worst real time "N minus 1" contingency for any periodafter the Rio Grande generating unit #8 is lost, it is entirely consistent with "N minus 1"contingency planning for El Paso to reserve adequate CBM to cover the potential loss of theNewman [**68] unit as soon as the Rio Grande unit is lost. n29 Accordingly, I find that El Pasocalculated CBM in accordance with "N minus 1" contingency criteria.

n28 Neither does the record adequately establish that alternatives such as contractual loadinterruption, emergency level generator operations, and available firm/non-firm SNMTStransmission and generating capacity are either adequate or appropriate for this purpose.


n29 "N minus 1" contingency planning does not necessarily permit a transmissionprovider to assume a serial loss of multiple generating resources in establishing CBM. Thelogic underlying my determination with respect to the Newman contingency is specific to ElPaso's circumstances and reliability constraints. Additionally, since the Company hasdemonstrated a legitimate basis for reserving CBM to cover the Newman contingency, theNERC/Commission concern that CBM might be reserved arbitrarily to impede open access(see, e.g., Exh. SPS-11 at p. 4; Exh. SPS-13 at p. 4; Tr. 156-57; Pennsylvania-NewJersey-Maryland Interconnection, et al., 81 FERC P61,257, at p. 62,277 (1997)) isinapplicable.

[**69]

I also find that CBM transmission capacity legitimately may be reserved in the absence of a firmentitlement to emergency generation. Neither NERC nor WSCC guidelines indicate that firmentitlement to emergency generation is a prerequisite to CBM reservation. See, e.g., Exh. EPE-14 atp. 19; Tr. 515. In addition, the applicable service schedule between SPS and El Paso provides thatemergencygeneration shall be provided unless doing so would impair or jeopardize service withinthe provider's system or the provider's ability to meet other commitments. See Exh. SPS-15 at p. 1;Exh. S-3 at p. 20. This provision is consistent with general industry standards requiring emergencyservice to be provided if available. The record, moreover, establishes that El Paso historically hasrelied on SPS emergency energy to avert native load curtailments. Exh. EPE-7 at pp. 34-35. In sum,the record does not support conditioning El Paso's CBM reservation on a firm entitlement toemergency generation.

Neither does the record support excluding the Las Cruces and CFE loads from El Paso's CBMcalculus at this time. While the record clearly indicates that Las Cruces has taken significant stepstowards [**70] forming a municipal utility (see generally Exh. CLC-1 at pp. 2-12), the record doesnot establish when-- or even if-- a Las Cruces municipal utility will commence operations. n30 Inaddition, the record indicates that El Paso has served CFE continuously since 1991 and has a firmobligation to furnish 200 MW to CFE in 1998. Tr. 173, 176-81. The record also suggests that CFEmay continue to purchasepower from the Company until CFE completes construction of its owngeneration facility. See Tr. 192. Therefore, the material facts are: (1) El Paso historically hasprovided firm service to Las Cruces/CFE; (2) the Company currently is obligated to provide firmservice to Las Cruces/CFE; and (3) El Paso cannot anticipate with certainty if or precisely when LasCruces/CFE will depart from its system. Under these circumstances, n31 I find it would beinappropriate to require El Paso to exclude the Las Cruces/CFE loads from the Company's CBMcalculus at this time. In accordance with Order No. 888's objectives, however, I also find that ElPaso [*65,085] must immediately recalculate its CBM requirements and ATC if and when eitherLas Cruces or CFE departs from the Company's system.


n30 El Paso's reply brief inappropriately referenced and appended a portion of theFebruary 25, 1998 hearing transcript in Docket No. SC97-2-000, which contains Las Crucestestimony estimating the time frame for condemning the El Paso distribution facilities thatLas Cruces requires to establish a municipal system at between three and five years. Thosematerials were struck by order dated April 14, 1998 and have not been considered in thisproceeding.

[**71]

n31 It should be noted that the record includes evidence concerning potential systemchanges which might offset the CBM reduction implied by El Paso's loss of the LasCruces/CFE loads. These changes include load growth (Tr. 279),increased/decreased/modified internal generation (EPE-1 at p. 25; Exh. S-6 at p. 4; Exh.SPS-47 at p. 2; Tr. 280), and further NERC guidance on calculating CBM (Exh. EPE-14 atpp. 16-17). I have considered this evidence, and find it neither meritless nor persuasive.

Turning to whether El Paso's CBM calculation double counts or otherwise should exclude loadforecast uncertainty or environmental derating components, I note at the outset that no partycontends that it is inappropriate per se to include these components. SPS, Las Cruces and Staffargue instead that El Paso's calculation double counts them. Las Cruces also argues that theCompany has not adequately supported the derating component. As a consequence, analysis of thissub-issue will be limited to whether El Paso double counted load forecast uncertainty orenvironmental derating in its CBM calculation, [**72] and whether the Company adequatelysupported the environmental derating component.

The record demonstrates that the 1,386 MW load/spinning reserve obligation n32 which forms thebasis for El Paso's CBM calculation reflects actual peak load without consideration ofweather-related uncertainty. Exh. EPE-14 at pp. 17-18.; Exh. EPE-7 at p. 24. The record alsodemonstrates that the 793 MW of local generation subsumed in the CBM calculation n33 does notreflect environmental deratings. Exh. EPE-7 at pp. 27-28. Thus, neither load forecast uncertaintynor environmental derating components were reflected in the base figures supporting El Paso'sCBM calculation. n34 I therefore find that the Company has not double counted those components.Since the legitimacy of the load forecast uncertainty component of the CBM calculation isotherwise unchallenged, I also find that the record adequately supports El Paso's 65 MW loadforecast uncertainty adjustment.


n32 The 1,386 MW figure is comprised of 1,332 MW of local load and 54 MW ofspinning reserve. The 54 MW spinning reserve component is derived by subtracting 49 MWof SRSG spinning reserve from the 103 MW spinning reserve required by the potential loss ofthe Newman generating unit #3. See Exh. EPE-14 at pp. 17-18.

[**73]

n33 This figure is reduced to 643 MW when the 150 MW Rio Grande generating unit # 8is assumed to be lost.

n34 Staff's focus on the Company's load and resource plan (which accounts for temporaryenvironmental constraints (see Exh. S-6 at p. 4 and n. 1; Exh. S-17 at pp. 13-14))-- asopposed to actual peak loads and resources-- is misplaced.

The record indicates that El Paso's local generation lies within an EPA-designated"non-attainment" area for NOx emissions. Exh. EPE-7 at pp. 27-28; Exh. EPE-14 at p. 18. Therecord also indicates that Federal air quality standards could require the Company to reduce localgeneration by 20-30 MW during certain weather conditions. Id. n35 This evidence is unrebutted. Asa consequence, I find adequate record support for the Company's 30 MW environmental deratingadjustment.

n35 Although the record contains evidence that such weather conditions have not actuallyoccurred (see Exh. SPS-47 at p. 1), the record does not establish that it is unreasonable for theCompany to plan for those conditions in light of Federal NOx emission restrictions.

[**74]

Finally, the record before me does not demonstrate that El Paso's 133 MW Eddy County TieCBM reservation is an anti-competitive device intended to impede open access. I observe first that


Order No. 888 is intended to provide a level playing field among parties seeking access to availabletransmission capacity. It is not intended to achieve perfect competition by mandating third partyaccess to transmission capacity which has been constructed to provide reliable service to nativeload, and which legitimately is dedicated to that purpose. This is particularly true where, as here, therecord suggests that the third parties requesting transmission service may not have fully exploredalternate sources of transmission capacity. See, e.g., Tr. 208-11.

El Paso has provided substantial record evidence to support a finding that it determinesavailable transmission capacity on a non-discriminatory basis. See Exh. EPE-1 at pp. 11-14; Exh.EPE- 4; Exh. EPE-5. The Company also has provided substantial record evidence to support afinding that its refusal to offer firm transmission service over the Eddy County Tie is necessary toensure reliable service to native load. See, e.g., Exh. EPE-1at [**75] pp. 30-31; 34; Exh. EPE-7 atpp. 2-3; Exh. EPE-14 at pp. 14-21. The fact that El Paso's CBM reservation over the Eddy CountyTie may result in some degree of competitive advantage or economic benefit to the Company iscoincidental, and therefore uncompelling.

I find that El Paso adequately has supported needs for: (1) at least 103 MW of CBM to accountfor the Newman #3 generating unit "N minus 1" contingency; (2) 65 MW of CBM to cover loadforecast uncertainty; and (3) 30 MW of CBM to offset potential environmental deratings. Theseneeds exceed the 133 MW of Eddy County Tie transmission capacity that the Company reserved asCBM. El Paso's 133 MW Eddy County Tie CBM reservation therefore is appropriate, and I cannotfind that the reservation either violates Order No. 888's [*65,086] "comparability" requirement oris anti-competitive.

9. Whether the Eddy County Tie and El Paso's AC Interconnections Provide Similar Supportto The El Paso System or Otherwise Share Similar Characteristics

a. Party Positions

El Paso emphasizes a fundamental physical difference between the Eddy County Tie and theCompany's AC interconnections. The Eddy County Tie is a single circuit [**76] DCinterconnectionbetween El Paso and SPP. Exh. EPE-1 at pp. 29, 44. As a consequence, all transfercapability between the Company and SPP is lost if the Eddy County Tie goes out of service. Id. Incontrast, El Paso does not lose transfer capability between itself and WSCC if one of the Company'sAC interconnections with WSCC is lost; the flow of electricity to WSCC simply re-routes over theremaining AC interconnections with no interruption in service. Id. at pp. 43- 45. El Paso maintainsthat the physical difference between the Eddy County Tie and the AC interconnections necessarilyresults in different levels of transmission system support. El Paso IB at p. 28.

Staff agrees with El Paso's characterization of the physical differences between the Eddy CountyTie and the Company's AC interconnections. Staff IB at pp. 29-30. Staff suggests, however, that ElPaso only relied on these differences to support the argument that the Eddy County Tie is physically


incapable of providing firm transmission service. Id. at p. 31. Staff notes that the Company hasconceded the tie's ability to provide firm service in accordance with the OATT, submitting that thisissue is therefore moot. Id. (referencing [**77] Tr. at 262, 314, 339).

Las Cruces maintains that the Eddy County Tie and El Paso's AC interconnections providesimilar system support. Las Cruces IB at p. 34. According to Las Cruces, any physical distinctionbetween the Eddy County Tie's ability to transfer power and that of the Company's ACinterconnections is unreasonable. Id. at pp. 34-35.

PUCT discusses, but does not take a position on, this issue.

PUCT IB at pp. 17-19.

b. Discussion

Insofar as El Paso's position was intended to support an argument that firm transmission servicecannot be provided over the Eddy County Tie, this issue is moot. I already have determined that theEddy County Tie can provide firm transmission service in accordance with the Commission's proforma OATT. See Issue #2, supra. Nevertheless, I also have determined that single circuit HVDCinterconnections like the Eddy County Tie have physical limitations which synchronous ACinterconnections do not have. Id. (referencing Exh. EPE-1 at pp. 22-23, 27-30; Exh. S-7 at p. 8;Exh. CLC-8 at pp. 1-2; Tr. at 262-64). The record establishes that the reliability of firmtransmission service over the Eddy County Tie may differ from the reliability [**78] of firmtransmissionservice over El Paso's AC interconnections. See Exh. EPE-1 at pp. 7, 28-30; Exh. S-7at pp. 8-9; Exh. CLC-2 at p. 14; Exh. CLC-3; Exh. CLC-8 at pp. 1-2; Tr. at 262-64. Accordingly, Ifind that physical differences between the Eddy County Tie and El Paso's AC interconnections toWSCC may result in different levels of transmission system support insofar as reliability isconcerned.

10. Whether El Paso's Reservation of 49 MW of Capacity in El Paso's Western AC Lines forCBM is Appropriate, and if Not, How Much Capacity, if Any, Should Be Reserved

a. Party Positions

El Paso and Staff take the position that El Paso's 49 MW western AC line transmission capacityreservation is reasonable because it ensures access to the Company's 49 MW SRSG generatingreserve entitlement. El Paso IB at pp. 29-30; Staff IB at p. 32.

SPS contends that El Paso has access to as much as 20 MW of southern New Mexico generationwhich the Company would not use the western AC lines to access, arguing that the western AC linereservation should be reduced to a maximum of 29 MW as a consequence. SPS IB at p. 34. n36 Inaddition, both SPS and Las Cruces contend that El Paso's [**79] nomograms already accountforthe potential loss of Rio Grande generating unit #8. SPS IB at p. 34; Las Cruces IB at pp. 37-38.


They argue that since El Paso has reserved the 49 MW of western AC transmission capacity inspecific anticipation of the Rio Grande unit's loss, the reservation is redundant. Id. SPS and LasCruces therefore take the position that the entire 49 MW western AC line reservation isinappropriate.

n36 SPS references generation from Plains Generation and Transmission Cooperative,Inc. ("Plains"), which is located within SNMTS, and may be accessed by El Paso withoutusing the western AC lines. See Exh. SPS-11 at pp. 6-7; Exh. SPS- 14 at p. 2.

b. Discussion

The record establishes that El Paso relies on SRSG generating reserves as a partial hedge againstthe potential loss of Rio Grande generating unit #8. Exh. EPE-1 at pp. 33-34. The record alsoestablishes that the Company is entitled to 49 MW of SRSG generating reserves (see, e.g., Exh.EPE-1 at p. 34; Exh. EPE-7 at [*65,087] p. [**80] 25; Exh. S-7 at pp. 11-12), and that inaccordance withWSCC guidelines, El Paso reserves 49 MW of firm transmission capacity over thewestern AC lines to ensure access to the SRSG reserves in anticipation of the Rio Grandecontingency. Exh. EPE-1 at p. 33; Exh. S-12 at p. 10.

Contrary to SPS's contention, the record indicates that El Paso cannot rely on southern NewMexico generation in lieu of SRSG spinning reserves. The record reveals that while Plains has adelivery point at the Las Cruces 115 kV bus, the SRSG membership agreement does not requirePlains to provide El Paso with SNMTS emergency generation. Exh. EPE-7 at pp. 31-32. Moreover,the record indicates that Plains is unable to provide SNMTS emergency generation or transmissionunder certain circumstances. Id. These facts undermine SPS's contention that El Paso's western ACline reservation should be reduced to reflect Plains resources.

Similarly, the SPS/Las Cruces contention that El Paso's nomograms already account for the RioGrande unit's potential loss is undermined by the nomograms' actual function. To be available on afirm basis, transmission capacity first must be reserved. El Paso's nomograms do not perform this[**81] function. The record establishes that the nomograms measurefirm transmission capacity, notthe availabilty of such capacity. See, e.g., Exh. EPE-1 at p. 14. It follows that the nomograms do notrender El Paso's western AC line capacity reservation redundant.

I find that a western AC line transmission capacity reservation is necessary to ensure Companyaccess to SRSG generating reserves. I also find that 49 MW is the appropriate amount oftransmission capacity for El Paso to reserve over the western AC lines.


11. Whether El Paso's Limitation of Liability with Respect to the Results or InformationContained in a System Impact Study is Reasonable

a. Party Positions

El Paso maintains that Order No. 888 does not require a transmission provider to guarantee theaccuracy of system impact studies. El Paso IB at p. 32. The Company emphasizes that it must relyon third party information when preparing a system impact study. Id. El Paso maintains that sincethe accuracy of such information may affect system impact study results, the following disclaimer isreasonable:

[El Paso] makes no expressed or implied warranties with respect to the results or theinformation [**82] contained in the report(s) and does not assume any liability resulting fromorrelating to the use of the report or the information contained in the report.

Exh. EPE-5 at p. 4 (El Paso OATT, Attachment D, p. 4).

Staff, SPS and Las Cruces submit that the disclaimer is inappropriate. Staff notes that theCommission considered this issue, and specifically declined to revise the pro forma OATT to limittransmission provider liability for system impact study results. Staff IB at p. 33 (referencing OrderNo. 888-A at pp. 30,301-02). According to Staff, the Commission imposes the same liabilitystandards on available capacity determinations as it imposes on any other system operation. Id. SPSand Las Cruces argue that it would make no sense for Order No. 888 to require a system impactstudy and, at the same time, permit the transmission provider to disclaim the results of the study.SPS IB at pp. 34-35; Las Cruces IB at p. 39. In addition, SPS submits that the ability to disclaimsystem impact study results encourages transmission providers to make misrepresentations intendedto impede open access. SPS IB at p. 35.

b. Discussion

Order No. 888-A expressly rejected a request [**83] to revise the pro forma OATT to specifythat transmission providers would not beliable for good faith errors in transfer capability estimates.Order No. 888-A at p. 30,301. Order No. 888-A also is dispositive that the Commission did notintend to limit transmission provider liability or indemnification for negligence or intentionalwrongdoing in preparing transfer capability estimates. Id. Moreover, holding El Paso responsiblefor its own negligence or intentional wrongdoing does not mean that the Company will be heldaccountable for inaccurate third party information. At a minimum, the Company would have to befound negligent in relying on such information in preparing a system impact study before it couldbe held accountable.


I find that El Paso's system impact study liability disclaimer is unreasonable. The disclaimer isinconsistent with Commission policy as expressed in Order No. 888-A. It also is unnecessary inlight of Order No. 888-A's negligence/intentional wrongdoing liability standard. Accordingly, I findthat the Company must delete the last paragraph on Original Sheet No. 180 of its OATT.

12. Whether El Paso Should Be Required to Offer Back-Up or Firming [**84] Service toWholesale Customers, and if So, What is the Nature of the Service to Be Provided?

a. Party Positions

SPS, Las Cruces and Staff argue that El Paso should be required to provide backup generating[*65,088] service, n37 at least to some degree. SPS argues that the Company must provide backupsupply service to customers taking wholesale transmission service over the Eddy County Tiebecause those customers require a backup power supplier in order to sell firm power to customerson El Paso's side of the tie. SPS IB at p. 35. Since there is no alternate path to transmit power if theEddy County Tie goes out of service, wholesale transmission customers utilizing the tie would beunable to serve loads in El Paso's control area unless the Company provides backup generation. Id.at pp. 35-36. SPS maintains that El Paso exercises control area market power and currently providesbackup service to itself, and therefore violates comparability/unlawfully discriminates by notoffering backup supply service to third parties. Id. at p. 36.

n37 Order No. 888 incorporates the NERC definition of backup service:

Backup Supply service is electric generating capacity: (1) to replace the outage ofgeneration or the failure to deliver generation due to outage of transmission sources; and/or(2) to cover that portion of the customer's load that exceeds its generation. Capacity(planning) reserves, installed capacity obligations, or capacity (planning) reserve sharingagreements are common mechanisms to supply Backup Supply service.

Exh. S-13 at p. 2 (excerpt from NERC document designated "Defining InterconnectedOperations Under Open Access"). See also Order No. 888 at p. 31,710.

[**85]

Las Cruces argues that the particular circumstances surrounding SPS's wholesale service to LasCruces via the Eddy County Tie furnish the basis to require El Paso to provide backup supply


service. Las Cruces IB at pp. 39-40. Las Cruces echoes the SPS contention that El Paso excercisescontrol area market power, claiming that this market power creates a significant barrier tocompetition in the Company's wholesale markets. Id. at p. 40. According to Las Cruces, El Paso is"uniquely situated" to provide backup supply service, and therefore should be required to do so. Id.

Staff concedes at the outset that backup service is not a precondition of comparable open accesstransmission service under Order No. 888. Staff IB at p. 35 (referencing Order No. 888 at p.31,710). Nevertheless, Staff asserts that the Eddy County Tie places El Paso in an atypical situationwhich warrants requiring the Company to provide backup supply service under limitedcircumstances. Staff submits that if SPS is assumed to be Las Cruces's exclusive generatingresource, that resource could be lost exclusively due to an outage of Eddy County Tie transmission(vs. generation) capability. Id. at pp. 35-36. Staff [**86] suggeststhat it is appropriate to require ElPaso to provide backup generation service in this single situation because Las Cruces's need wouldbe caused by a failure of El Paso transmission facilities instead of an SPS generation failure. Id.Staff maintains that El Paso is the only entity with sufficient generating capacity to provide backupsupport for the SPS/Las Cruces transaction, and therefore should be required to provide that supportif: (1) the Company has adequate available generating capacity to provide the service; and (2)providing the service would not impair native load reliability. Staff RB at p. 23; Tr. 570.

PUCT takes the position that the backup or firming services proposed by SPS, Las Cruces andStaff are not required under Order No. 888. PUCT IB at p. 20. According to PUCT, the proposedservices exceed the operating reserve time limits specified in Order No. 888, and therefore wouldconstitute commercial services. Id. PUCT nevertheless suggests that it may be appropriate to requireEl Paso to provide backup service because the Company may be the only utility capable of backingup the SPS/Las Cruces transaction. Id.

PSCNM maintains that El Paso should not be [**87] required to provide backup or firmingservices. PSCNM emphasizes that Order No. 888 requires unbundled service and shifts risks anddecision-making responsibilities to the transmission service customer. PSCNM IB at p. 18. PSCNMsubmits that the economic consequences attending a customer's decision to depart from a utility'ssystem do not constitute legitimate grounds to impose non-transmission- related generatingresponsibilities on a transmission service provider in derogation of Order No. 888 and its underlyingcompetitive objectives. Id. at pp. 13-15.

El Paso argues that Order No. 888 applies only to specific transmission and ancillary services.The Company emphasizes that the only ancillary services specified in Order No. 888 are: (1)Scheduling, System Control and Dispatch Service; (2) Reactive Supply and Voltage Control fromGeneration Sources Service; (3) Regulation and Frequency Response Service; (4) Energy ImbalanceService; (5) Operating Reserve/Spinning Reserve Service; and (6) Operating Reserve/SupplementalReserve Service. El Paso IB at p. 33 (referencing III FERC Stats. & Regs., Regulations PreamblesJanuary 1991-June 1996 P 31,036, at pp. 31,705-08). [**88]


El Paso also emphasizes that Order No. 888 expressly states-- and all partiesconcede-- that backupservice is not a necessary condition of comparable open access transmission service. El Paso RB atp. 21. The Company [*65,089] maintains that the SPS, Las Cruces and Staff proposals constituteunauthorized deviations from the pro forma OATT at this (compliance) stage of the proceeding, andthat the appropriate procedure for presenting these proposals to the Commission would be to initiatea separate proceeding under Section 206 of the Federal Power Act. n38 Id. at p. 22.

n38 El Paso also submits that the SPS, Las Cruces and Staff proposals may constituteimpermissible collateral attacks on Order No. 888. El Paso IB at p. 35; El Paso RB at p. 22.

b. Discussion

I note at the outset that Article VIII of the March Settlement explicitly confined this proceedingto "system impact study issues." March Settlement at p. 7. In my opinion, whether El Paso shouldbe required to provide backup or firming [**89] service falls well beyond those parameters.Nevertheless, the Revised Joint Statement of Issues reflects this issue, and no party has objected toit. I therefore find the parties have stipulated that whether El Paso should be required to providebackup or firming service in the context of this proceeding should be addressed.

All parties concede that Order No. 888 does not require El Paso to provide the backup orfirming services proposed by SPS, Las Cruces or Staff. See SPS IB at p.37; Las Cruces IB at pp.39-40; Staff IB at p. 35; PUCT IB at p. 20. This concession notwithstanding, SPS, Las Cruces andStaff argue that El Paso should be required to provide backup or firming services to assuagecomparability and anti-competitive concerns. These arguments are untenable.

Order No. 888 specifically addresses backup supply service, stating:

We will not require this service as an ancillary service under an open access transmission tariff.Backup Supply Service is not required for comparable open access transmission service.

***

Backup Supply is a generation service that may reasonably be viewed as the responsibility ofthe transmission customer, who may contract for backup service [**90] or curtail load.

We will impose no obligation on the transmission provider to provide power to the customerfora time longer than specified in the tariff for the customer's own backup power supply to be made


available. The transmission provider is obligated to protect against emergencies for a short time; ithas no obligation to furnish replacement power on a long term basis if the customer loses its sourceof supply.

III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P 31,036, at pp.31,710-11 (emphasis added). This language conclusively establishes that Order No. 888 not onlydoesn't require El Paso to provide backup supply service to satisfy the comparability requirementsof open access transmission service, but specifically excuses the Company from doing so. n39

n39 SPS also indicates that El Paso should be required to provide transmission servicesimilar to that which El Paso provides to Texas-New Mexico Power Company and PSCNMfor a period of time coincident with a line segment outage in order to replace the transmissioncapability lost as a result of such outage ("firming service"). See SPS IB at p. 40 (referencingTr. 217; Exh. SPS-40, Art. II at p. 4). The record, however, indicates that this is a bundledservice which was arranged prior to the implementation of Order No. 888. Tr. 294; Exh.SPS-40. Moreover, the service is provided as part of a comprehensive agreement amongSNMTS members specifically negotiated to defer construction of additional transmissionfacilities into SNMTS, and is available only to SNMTS members. Id. Since SPS neither is amember of SNMTS nor contributes to SNMTS, SPS has no legitimate claim to the benefits ofthe SNMTS agreement.

[**91]

Order No. 888 also conclusively rebuts the SPS, Las Cruces and Staff contentions that El Pasoshould be required to provide backup service because the Company is uniquely situated to do so:

The transmission provider is not uniquely situated to provide Backup Supply Service to itstransmission customers, nor does it have a comparative advantage over others in providing suchservice.

Id. at p. 31,711. Even if I were to find that an exception to the Commission's stated position couldbe made in the context of a pro forma tariff compliance proceeding-- a finding which I believewould be in error-- the record before me does not establish that El Paso is the only available sourceof the backup service advocated by SPS, Las Cruces or Staff. In fact, it suggests otherwise. See,e.g., Exh. SPS-11 at p. 7; Exh. S-3 at pp. 44-45; Tr. 208-11, 463-64, 518. Neither does the recordestablish that, insofar as the Eddy County Tie is involved, the bulk power agreement between SPSand Las Cruces is viable at this time.


In addition, Order No. 888 states that:

...as Backup Supply Service may require substantial amounts of generation capability, it isinappropriate to require the transmission [**92] providerto assume significant generationresponsibilities as we functionally unbundle transmission from generation.

III FERC Stats. & Regs., Regulations Preambles, January 1991-June 1996 P 31,036, at p. 31,711.The instant case underscores the the Commission's foresight. If El Paso were [*65,090] required toprovide backup supply service to SPS, the Company would have to reserve adequate generation andtransmission capacity to serve the entire Las Cruces load. See, e.g., Exh. EPE-12 at p. 10. This notonly would be an inefficient dedication of significant resources, it would preclude El Paso fromcompetitively marketing the firm generation made available by Las Cruces's intended departurefrom the Company's system. Such effects are inconsistent with Order No. 888's stated objectives.See Id. at pp. 31,839-41.

I find that El Paso should not be required to offer backup or firming services to wholesalecustomers in the context of this compliance proceeding. See, e.g., Florida Power & Light Company,83 FERC P61,187, at p. 61,773 & n.9 (1998)(compliance filing proceeding addresses only whetherfiling at issue complies with Commission directive). [**93] The appropriate procedure to presentthis and related issues, includingEl Paso's market power n40 and appropriate rates for backup orfirming services, for Commission consideration would be to initiate a separate proceeding underSection 206 of the Federal Power Act. The possibility that parties with an interest in such issuesmay not have anticipated a need to participate in El Paso's pro forma tariff compliance proceedingprovides additional support for this conclusion.

n40 The SPS and Las Cruces arguments rely heavily on market power allegations, butprovide scant record support for those allegations.

13. What is the Appropriate Rate for Back-Up or Firming Service?

I find it is unnecessary to address this issue in light of my determinations with respect to Issue#12, supra.

14. Whether it is Appropriate for El Paso to Use Base-and- Change Power Flow Simulations and, ifSo, Whether the Base-and-Change Method Used by El Paso to Evaluate the Impact on its System of


a Requested Transaction Involving [**94] Entities Internal to its Control Area Are Compared to aCase Not Including ThisTransaction is Reasonable

a. Party Positions

El Paso uses the base-and-change power flow methodology to simulate the impact oftransactions on its system. Exh. EPE-1 at pp. 46-50. Essentially, El Paso's methodology comparessystem impacts between scenarios in which specific loads are served: (1) by Company generation;and (2) by another supplier, in which case El Paso generation is reduced and power imports--particularly those over the Eddy County Tie-- are increased by an identical amount. Id. at p. 47. ElPaso maintains that these comparisons illustrate power flow changes resulting from changes ingenerating sources. Id. The Company contends that such comparisons produce reasonable results,and are commonly used in the industry to evaluate transmission system impacts. Id. Staff agrees.Staff IB at pp. 41-43.

Las Cruces maintains that El Paso's methodology is an illegitimate application ofbase-and-change analysis. Las Cruces IB at p.45. According to Las Cruces, transactions such as theproposed SPS to Las Cruces import over the Eddy County Tie already have been taken into accountin El Paso's [**95] nomograms, and a base-and-change analysis therefore is neither necessary norappropriate. Id. at p. 47. Las Cruces maintains that the nomograms alone should constitute theCompany's available transmission capability study. Id. at p. 48.

b. Discussion

The record indicates that the base-and-change methodology is commonly used in the industry toevaluate transmission system impacts. Exh. EPE-1 at p. 47. This fact is uncontested. Moreover, LasCruces concedes that base-and-change load flow analyses are legitimate under numerouscircumstances. Exh. CLC-2 at pp. 25-26. And while the record indicates that El Paso's nomogramsmodel Eddy County Tie power flows ranging from 0-200 MW, that fact does not establish that it isunreasonable for the Company to use the base-and-flow methodology to assess real world impacts,particularly with respect to the SPS/Las Cruces transaction. To the contrary, the record establishesthat: (1) El Paso owns and operates the only generating resources in SNMTS; (2) Las Crucescurrently is served exclusively from El Paso's generating resources; (3) the power El Paso uses toserve Las Cruces ordinarily does not flow over the Eddy County Tie; and (4) the power [**96] SPSwould use to serve Las Cruces would flow over the Eddy County Tie. See, e.g., Exh. EPE-1at p. 47.The record therefore indicates that the base-and-flow methodology is particularly suited to simulatereasonable transmission system impacts between alternate scenarios in which the Las Cruces load isserved by El Paso and SPS.

On the record before me, I find that El Paso's base-and-change power flow simulations areappropriate and reasonable.


15. Whether the Provision in [OATT] Attachment G Requiring a Network Customer toPurchase Full Load Reserve Requirements to Receive Firm Service Over an HVDCInterconnection is Reasonable [*65,091] and, if Not, What is the Proper Amount of LoadRequirements El Paso Can Require a Firm Network Customer to Purchase?

a. Party Positions

Attachment G to El Paso's OATT, which specifies Network Operating Agreement parameters,requires customers taking network service over the Eddy County Tie to purchase "full loadrequirement reserves to maintain network firm service" in case of transmission outages. See Exh.EPE-6 at p. 7. SPS, Las Cruces and Staff object to this requirement. n41

n41 PUCT does not expressly object, but suggests on brief that the procedures theCommission has adopted under Section 211 of the Federal Power Act may be appropriate toaddress the reliability issues in this case. PUCT IB at pp. 24-25.

[**97]

SPS maintains that the full load reserve requirement is inconsistent with El Paso's OATT ingeneral. SPS IB at pp. 46-47. According to SPS, firm network transmission customers takingservice over the Eddy County Tie should not be required to purchase more reserves than theCompany or firm network transmission customers not utilizing the tie must purchase. Id. at p. 47.SPS emphasizes that El Paso's OATT offers operating reserve ancillary services, and requirescustomers to purchase only 3.5 percent in reserve transmission capacity to support each of thoseservices. Id. SPS maintains that the Company should not require customers utilizing the EddyCounty Tie to purchase more than this amount. Id.

Las Cruces contends that a full load reserve requirement is anti-competitive and undulyburdensome. Las Cruces IB at p. 48. Las Cruces argues that Eddy County Tie customers should notbe required to purchase more reserves than any other transmission customer, including El Paso. Id.at p. 49. Consequently, Las Cruces maintains that the Company should require customers utilizingthe Eddy County Tie to purchase only 3.5 percent in reserve transmission capacity to support eachservice over [**98] thetie, resulting in a combined purchase obligation of seven percent. Id. at pp.49-50.

Staff maintains that if customers purchase SPP generating capacity over the Eddy County Tie,


the full load reserve requirement compels them to purchase the capacity twice: once from SPP, andagain from WSCC. Staff IB at p. 43. Although Staff concedes that some reserve is required, Staffmaintains that the proper amount is 16 percent of the transmission capacity reservation, which isconsistent with Staff's recommended backup supply service rate. Id. (referencing Exh. S-7 at pp.14-17; Exh. S-12 at pp. 4-7).

PSCNM opposes the SPS, Las Cruces and Staff proposals. PSCNM argues that the backupsupply service assumptions which underlie these proposals grossly understate the amount of serviceinvolved and fail to recognize the appropriate cost treatment for such services. PSCNM IB at pp.19-22.

El Paso defends the full load reserve requirement on the basis that while the Company relies onpower from the Eddy County Tie, it also reserves sufficient WSCC generation to maintain reliableservice if the tie is lost. El Paso IB at p. 47. El Paso argues that imposing a full load reserverequirement on [**99] other EddyCounty Tie transmission service customers simply assurescomparability of service among all system users. Id. According to El Paso, Eddy County Tietransmission service customers may ensure reliability either by purchasing WSCC reservegeneration or by taking service subject to interruption if the tie is lost. Id. at pp. 47-48. The onlyother alternative, which the Company maintains is inconsistent with Order No. 888's objectives,would be to require El Paso to provide generation whenever the tie is out of service. Id. at p. 48. Inaddition, El Paso states that Attachment G "is a recommended set of principles to be used as aguideline in negotiating a network integration transmission service agreement," suggesting that theattachment's operating principles are flexible and may be modified. Id. at p. 49.

b. Discussion

El Paso OATT, Attachment G provides at the outset that "[a] Network Operating Agreementshall be negotiated between the Transmission Provider and the Network Integration Customer." SeeExh. EPE-6 at p. 1. This language, and the specification of "Issues To Be Addressed DuringNegotiations" immediately following it, implies that the Network Operating Agreement's [**100]ultimateterms and conditions all are subject to negotiation. That inference is encouraged by ElPaso's briefs. See El Paso IB at p. 49; El Paso RB at p. 25. Any such inference, however, would beinconsistent with Attachment G's "Summary of Operating Principles," which specifies that "theNetwork Operating Agreement will be based on the following summary of operating principles." Id.(emphasis added). Since the provision at issue here is an essential element of one of those operatingprinciples (id. at p. 7), an inference that the provision is subject to negotiation would be invalid. n42

n42 Of course, El Paso could eliminate this concern by modifying the Summary ofOperating Principles' introductory language.


[*65,092]

I already have determined that the Eddy County Tie has physical limitations which restricttransmission service reliability. See Issue #2, supra (referencing Exh. EPE-1 at pp. 22-23, 27-30;Exh. S-7 at p. 8; Exh. CLC-8 at pp. 1-2; Tr. at 262-64). If the Eddy County Tie goes out [**101] ofservice, transmission over theinterconnection is impossible and an actual service interruption mayoccur. As stated previously, any customer purchasing firm transmission service over the EddyCounty Tie under El Paso's OATT implicitly acknowledges that the service cannot be provided inaccordance with "N minus 1" reliability criteria and assumes a risk that the service may beinterrupted if the tie is lost.

The preceding discussion resolves two problems. First, it eliminates El Paso's concern that theCompany not be burdened with reserving firm generation to support transmission customer use ofthe Eddy County Tie. If Eddy County Tie transmission customers require firm generating reserves,they must secure that service independently, and at an appropriate market rate. Second, in light ofthe Eddy County Tie's restricted reliability, it is unnecessary for El Paso to impose a full loadreserve requirement on third parties. Judgments concerning appropriate generating resourcereservations should be left to the transmission service customer who is ultimately responsible fordelivering the power.

I find that it is unnecessary, and therefore unreasonable, for El Paso to impose a full [**102]load reserve requirement on firmnetwork transmission customers taking service over the EddyCounty Tie. The Company must delete any reference to that requirement from its OATT. In light ofmy determinations with respect to backup supply service, moreover, it is unnecessary for me toaddress the SPS, Las Cruces and Staff alternative proposals.

C. ORDER

Wherefore, it is ordered, subject to review by the Commission on exceptions or on its ownmotion, as provided by the Commission's Rules of Practice and Procedure, that within thirty days ofthe issuance of the Final Order of the Commission in this proceeding, El Paso shall comply with thefindings and conclusions contained in this Initial Decision, and shall file revised tariff sheets, asadopted or modified by the Commission.

H. Peter Young

Presiding Administrative Law Judge

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1Exelon Generation Company, LLC v. Southwest Power Pool, Inc., 99 FERC¶ 61,235 (2002) (May Order).

101 FERC ¶ 61, 226UNITED STATES OF AMERICA


Before Commissioners: Pat Wood, III, Chairman; William L. Massey, Linda Breathitt, and Nora Mead Brownell.

Exelon Generation Company, LLC, Docket No. EL02-86-001Complainant

v.Southwest Power Pool, Inc.,

Respondent


(Issued November 22, 2002)

1. In an order issued on May 31, 2002,1 the Commission granted the complaint filedby Exelon Generation Company, LLC (Exelon) against Southwest Power Pool, Inc.(SPP) alleging that SPP had refused to honor Exelon's rollover rights related to itsexisting long-term firm point-to-point transmission service agreement in violation ofSection 2.2 of the SPP open access transmission tariff (OATT) and the Commission'spolicy. This order denies SPP's request for rehearing of the May Order.

BACKGROUND

2. On May 3, 2002, Exelon filed a complaint alleging that SPP refused to roll overExelon's one-year service agreement for 400 MW of firm point-to-point transmissionservice from a point of receipt on the Central & South West Services system (CSW) to apoint of receipt on the Entergy Services system (Entergy) for another one-year termbeginning on June 1, 2002. In response to Exelon's rollover request, SPP sent Exelon aSystem Impact Study (SIS) relating to the requested service which stated that there wasinsufficient transmission capacity available on the SPP system to grant Exelon's request. The SIS provided that if Exelon permitted SPP to curtail Exelon's 400 MW long-termfirm transmission service on the SPP system between the CSW system and the AmerenEnergy system (Ameren) in its entirety during the summer of 2002, SPP would be able to


Docket No. EL02-86-001 - 2 -

2Section 2.2 provides in relevant part:Reservation Priority For Existing Firm Service Customers: Existingfirm service customers (wholesale requirements and transmission-only,with a contract term of one-year or more, and retail) . . . have the right tocontinue to take transmission service from the Transmission Provider whenthe contract expires, rolls over, or is renewed . . . This transmissionreservation priority for existing firm service customers is an ongoing rightthat may be exercised . . . at the end of all firm contract terms of one yearor longer . . . If competing existing firm service requirements customersapply for service that cannot be fully provided, the priority rights will beranked in accordance with first-come, first-served principles. If firmservice customers tie, then the capacity for which they receive priorityrights under this Tariff shall be apportioned on a pro rata basis.

3May Order at P 26.

provide Exelon with 226 MW of long-term firm transmission service from CSW toEntergy. The SIS stated that if Exelon's service request over the CSW-to-Ameren pathcould not be curtailed, then the available transmission capacity on Exelon's requestedCSW-to-Entergy path would be zero.

3. In the May Order, the Commission granted Exelon's complaint and stated thatExelon has the right to request a rollover of its existing firm point-to-point transmissionservice. The May Order explained that SPP is obligated, under Section 2.2 of its OATT(which adopts the language of the Commission's pro forma OATT),2 to maintainavailable transmission capacity for its existing long-term transmission customers withrollover rights, such as Exelon, until the time expires for those customers to exercise theirrollover rights.3

REQUEST FOR REHEARING AND OTHER PLEADINGS

4. On June 27, 2002, SPP filed a request for rehearing arguing that the Commissionerred by determining that a transmission customer has an automatic right to renew itsservice even if studies regarding the transmission request show that insufficienttransmission capacity is available and that providing such service would adversely affectreliability. SPP contends that the Commission's determination will have an adverseeffect on reliability by causing greater curtailments and Transmission Loading Relief(TLRs) of existing firm load and outages. In addition, SPP argues that the Commissionerred by determining that a transmission provider may only recall capacity to serve nativeload and only if the need for this limitation is forecasted and is set forth in the initial


Docket No. EL02-86-001 - 3 -

4The Designated SPP Transmission Owners are: City Utilities of Springfield,Missouri, the Empire District Electric Company, Oklahoma Gas & Electric Company,Kansas City Power and Light Company, Westar Energy, Inc., and Kansas Gas andElectric Company.

service agreement, even if capacity is no longer available due to events or circumstancesthat arose after the initial service was entered into. SPP claims that the Commissionerred by announcing a new policy without providing adequate notice and opportunity foraffected parties to comment or participate. SPP further asserts that the Commission'sdecision represents an unexplained reversal of the Commission's prior orders on Section2.2 and the language of the pro forma OATT and SPP's OATT. SPP asks that we reversethe decision in the May Order or, at the very least, apply the decision prospectively.

5. On July 26, 2002, SPP filed a letter in support of its request for rehearing toprovide supplemental information describing recent TLRs which it alleges were caused,at least in part, by SPP being required to provide rollover service to various transmissioncustomers, including Exelon.

6. On July 26, 2002, the Designated SPP Transmission Owners4 filed comments insupport of the request for rehearing filed by SPP.

7. On July 17, 2002, the Western Farmers Electric Cooperative (WFEC) filed amotion to intervene out-of-time. On July 26, 2002, Midwest Energy, Inc. (MidwestEnergy) also filed a motion to intervene out-of-time and comments.

DISCUSSION

Procedural Matters

8. We will deny the motions to intervene out-of-time filed by WFEC and MidwestEnergy. When late intervention is sought after the issuance of a dispositive order, theprejudice to other parties and burden upon the Commission of granting the lateintervention may be substantial. Thus, movants bear a higher burden to demonstrategood cause for granting such late intervention. We find that this burden has not been methere. We will also dismiss the comments filed by the Designated SPP TransmissionOwners because they are not intervenors in these proceedings.


Docket No. EL02-86-001 - 4 -

5See Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs byPublic Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs.¶ 31,036at 31,694 (1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, orderon reh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C,82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom. Transmission Access PolicyStudy Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New Yorkv. FERC, 122 S. Ct. 1012 (2002). See also Commonwealth Edison Co., 95 FERC¶ 61,252 at 61,874, reh'g denied 96 FERC ¶ 61,158 at 61,690 (2001).

6Order No. 888 at 31,665; Order No. 888-A at 30,195.

Analysis

9. As discussed in greater detail below, SPP's request for rehearing of the May Order is basically a collateral attack of the Commission's rollover rights policy as established inOrder No. 888.5 In that order, the Commission concluded that all firm transmissioncustomers with contracts for a term of one-year or more should have the right to continueto take transmission service from their existing transmission provider upon the expirationof their contracts or at the time their contracts become subject to renewal or rollover.6 Once a transmission provider evaluates the impacts on its system of providingtransmission service to a customer and decides to grant such a request, the rollover rightspolicy obligates the transmission provider to plan and operate its system with theexpectation that it will continue to provide service to that customer should the customerrequest rollover of its contract term. In other words, the transmission provider isexpected to plan its system to accommodate transmission customers' rollover rights. Ifthe transmission system becomes constrained such that the transmission provider cannotsatisfy existing customers, then the obligation is on the transmission provider to eithercurtail service pursuant to the provisions of its OATT or to build more capacity to relievethe constraint.

10. Many of the issues raised by SPP on rehearing (e.g, the one-year minimum term;the impact of rollover on reliability of the transmission system) go to the heart of theCommission's rollover rights policy established in Order No. 888. On this basis, they areissues that should have been raised on rehearing of Order No. 888. The Commission willnot revisit in this order its prior determinations in Order No. 888, which have beenaffirmed by U.S. Court of Appeals for the District of Columbia Circuit and the U.S.Supreme Court.


Docket No. EL02-86-001 - 5 -

A. IMPACT ON RELIABILITY

i. Ability to Predict all Factors that Could Limit Capacity

11. SPP argues that the Commission's determination in the May Order will have adetrimental impact on reliability in the region. SPP contends that a transmission providercannot predict at the outset of entering into a service agreement all of the factors thatcould potentially limit the amount of available transmission capacity because thesefactors vary over time due to conditions that may not be predictable or may be outside ofthe transmission provider's control. SPP states that its denial of Exelon's requestedrollover service was due to circumstances beyond its control or ability to predict. SPPexplains that the amount of capacity available on its transmission system has diminishedover time due to factors such as loop flows from other systems, the effects of newgeneration going on-line in Entergy and other areas outside of the SPP footprint, andchanges in market conditions and system topology, so that SPP could not provideExelon's requested rollover service without potentially harming reliability or othercustomers.

12. SPP contends that if a transmission provider with limited available transmissioncapacity is compelled to provide service, the result will be more firm demand on thetransmission system than can be accommodated, which will adversely affect native loadcustomers and long-term customers, as well as potential new customers. SPP adds that,as a policy matter, it is neither fair nor appropriate for customers who only committed toa one-year term of service to cause curtailments of firm customers who have been payingfor the costs of the system for a much longer period of time and who are obligated tocontinue to pay for those system costs for a far longer period. Furthermore, SPP statesthat the May Order has forced it to reject new service requests because of uncertainty asto whether existing customers will roll over their requests.

Commission Response

13. SPP's arguments do not diminish Exelon's rollover rights under Section 2.2 of theSPP OATT. Under Section 2.2 of its OATT, SPP is responsible for maintainingavailable transmission capacity for existing long-term transmission customers withrollover rights, such as Exelon, until the time expires for those customers to exercise theirrollover rights. In providing for Exelon's rollover rights in Section 2.2, SPP isresponsible for evaluating the impact of the exercise of these rights on its system.

14. Notwithstanding SPP's attempt to portray rollover rights as detrimental toreliability, rollover rights are intended to promote system planning and reliability, not to


Docket No. EL02-86-001 - 6 -


8Pursuant to Section 21.1 of its OATT, SPP is not responsible for additions tothird-party systems.


undermine it. Rollover rights should facilitate a transmission provider's orderly planningand operation, i.e., provide for available capacity, which is essential to SPP's obligationof preserving system reliability. A transmission provider is expected to include all long-term transmission customers (i.e., those with rollover rights) in its long-term planning. While it may be the case, as SPP suggests, that subsequent circumstances may negativelyimpact a transmission provider's available transmission capacity, the presence of suchconstraints do not give a transmission provider the right to deny a rollover request. Under Section 2.2 of its OATT, SPP is responsible for maintaining availabletransmission capacity for existing long-term transmission customers with rollover rights,such as Exelon, until the time expires for those customers to exercise their rollover rights. Thus, the constraints that SPP cites are not sufficient to override Exelon's rollover rights. If constraints arise after a transmission provider enters into a long-term agreement with atransmission customer (and that agreement contains no restrictions on the transmissioncustomer's rollover rights), the obligation is on the transmission provider to either buildadditional transmission facilities to relieve the constraint or to implement the curtailmentprocedures set forth in its OATT.

15. In its rehearing request, SPP states that "[t]he Commission's orders will force SPPand other transmission providers to presume that all long-term customers will renew theirservice, and evaluate the impact of the service for years beyond the requested term of theproposed service agreement."7 SPP is correct in this regard. Indeed, it was the intent ofthe Commission in establishing the rollover policy that long-term customers have theright to continue to take service and, accordingly, that the transmission provider be in theposition of continuing to provide it. Again, to the extent that SPP disagrees with theCommission's policy call in this regard, it should have sought rehearing and/orclarification at the time that the Commission established the rollover rights policy.

16. With respect to SPP's arguments that third-party system impacts prevent it fromproviding service to Exelon, SPP is not authorized by the pro forma OATT or by its ownOATT8 to condition a transmission customer's right to transmission service on whetherthere is transmission capacity on a third party's transmission system.9 A transmissionprovider may not condition a transmission customer's right to roll over transmissionservice on the transmission provider's system at the end of an existing service agreement


Docket No. EL02-86-001 - 7 -

10Commonwealth Edison Co., 95 FERC ¶ 61,252 at 61,875 (2001), reh'g deniedCommonwealth Edison Co., 96 FERC ¶ 61,158 (2001).

11Citing Idaho Power Co., 95 FERC ¶ 61,224 at 61,759 (2001) (Idaho PowerRehearing Order), aff'g Idaho Power Co., 94 FERC ¶ 61,311 (2001) (Idaho Power).

12Citing Northeast Utils. Serv. Co., 56 FERC ¶ 61,269 at 62,030 (1991), reh'gdenied, 59 FERC ¶ 61,042 (1992), aff'd in relevant part, 993 F.2d 937, 954-55 (1st Cir.199); New England Power Pool, 83 FERC ¶ 61,045 at 61,235 (1998); Duke Elec.Transmission, 96 FERC ¶ 61,145 at 61,626-27 (2001).

based on whether there is enough transmission capacity available on a third-partytransmission system.10

ii. Absolute Right to Capacity

17. SPP argues that the May Order grants transmission customers an absolute right tocapacity based on a one-year long-term contract. Consequently, SPP claims, the orderrequires transmission providers to accept transactions regardless of whether sufficientcapacity exists. As a result, according to SPP, transmission providers could overloadtheir systems and have to curtail reserved service as well as transmission service to othercustomers or risk severe and possibly cascading system outages.

18. SPP further contends that because construction times are usually longer than the60-day renewal period provided to customers, the Commission's policy could forcetransmission providers to build new capacity based on the possibility that a customer willroll over its service. SPP states that this is contrary to the Commission's prior statementsthat transmission owners are not obligated to build new capacity to serve a rolloverrequest.11 SPP states that this is also contrary to Section 13.5 (dealing with atransmission customer's obligations for facility additions or redispatch costs) of the proforma tariff and the Commission's cost-causation and "but for" pricing principles.12 SPPfurther notes that this may be difficult given the number of problems that transmissionowners have experienced when attempting to upgrade their transmission systems.

Commission Response

19. All long-term firm transmission customers have the right to roll over their service,but the potential that a transmission customer will choose to do so does not require SPPto remove the associated capacity from its OASIS forever and restore it only if thecustomer declines to exercise its option at some future period. As the Commission has


Docket No. EL02-86-001 - 8 -

13Commonwealth Edison Co., 96 FERC at 61,690.

14Id.

15Idaho Power Rehearing Order, 95 FERC at 61,759.

explained, SPP may post the associated capacity on its OASIS and accept competingreservations until the time that the existing customer chooses to roll over its contract byexercising its right of first refusal.13 If the existing customer does so and agrees to matchthe rate offered by another potential customer seeking the same transmission capacity (upto the transmission provider's filed rate), it then takes priority over the competingreservation. If the existing customer declines to exercise its right of first refusal, thetransmission provider may accept the next competing reservation.14 In any event, Exelonhas not been granted service in perpetuity to the extent that competing service requestsmay: (1) replace service to Exelon absent a rollover of its request; or (2) supplant suchservice if Exelon declines to match a competing request with a longer term.

20. Furthermore, SPP has misconstrued our statement that "the right of first refusalprovision applies to existing capacity and does not require a transmission provider tobuild additional capacity in response to a request to rollover a transmission service."15 By this statement, the Commission did not intend, as SPP seems to suggest, that atransmission provider could deny a customer's rollover request to the extent that thetransmission provider did not have sufficient available capacity to meet the request andcould only grant the request if it were to build additional capacity. Implicit in thisstatement was the expectation that the transmission provider had already studied theimpacts on its existing system of providing the transmission service and determined thatit could provide that service (including any rollover if requested) using its existingsystem. Because a determination to grant the initial service request carried with it theobligation to assume that the customer would continue to take service, the Commissionexpected that the transmission provider would have sufficient existing capacity to serve arollover request and not then need to build additional capacity to serve that rolloverrequest.

21. In evaluating Exelon's original request for long-term firm transmission service,SPP was obligated to determine whether or not it had available existing capacity to serveExelon, taking into account Exelon's right to renew or roll over its transmission service. As we have indicated above, if constraints arise after a transmission provider enters intoa long-term agreement with a transmission customer (and that agreement contains norestrictions on the transmission customer's rollover rights), the obligation is on thetransmission provider to determine whether or not to build additional facilities to


Docket No. EL02-86-001 - 9 -

16See Order No. 888 at 31,655. See also Order No. 888-A at 30,195, 30,197-98.

accommodate new transmission customers. If the transmission system is constrained tothe extent that the transmission provider cannot satisfy its existing transmissioncustomers' contracts, then the transmission provider has the choice of eitherimplementing the curtailment procedures set forth in its OATT or building additionaltransmission facilities to relieve the constraint.

iii. Gaming the System

22. SPP further contends that the May Order removes any incentives for customers torequest service for more than a year, which will inhibit the ability of transmissionproviders and transmission owners to engage in long-term planning, further harmingreliability. SPP argues that the May Order encourages gaming because customers whoare aware that a system is becoming increasingly constrained can simply requesttransmission service for a one-year period even if they intend to use the service for amuch longer period of time. SPP argues that by choosing a one-year service term,customers can avoid paying for upgrades necessary to support their service which theywould have to pay for if they had requested a multi-year service term. SPP claims thatthis is inconsistent with the Commission's "or" pricing and cost causation principles.

Commission response

23. The Commission has consistently found that Section 2.2 of the pro forma OATTrequires a transmission provider to allow a customer with a one-year firm reservation toroll over that service for a longer period of time, subject to matching competing requestsfor that service. Order No. 888 contemplated such an arrangement,16 and the policy tookeffect at the time Order No. 888 was issued. On this basis, we will not reexamine ourdecision that the rollover rights provisions of Section 2.2 apply to contracts with terms ofone year or more.

24. Further, a long-term firm transmission service customer cannot game the systemand avoid paying for upgrades simply by choosing a contract with a one-year term. Regardless of the length of the contract term, a transmission provider will grant a requestfor long-term firm transmission service only if it determines that it has sufficientavailable transmission capacity to provide the service. In making this determination, thetransmission provider is obligated to plan its system to meet all of its firm loads,including any prospective rollovers of the transmission services used to meet those loads. Thus, if, a transmission customer requests transmission service for only one year, but the


Docket No. EL02-86-001 - 10 -

17We also note that transmission customers do have incentives to request servicefor more than one year. If, for example, a transmission customer enters into a ten-yearcontract instead of a one-year contract, it does not face having to exercise its rolloverrights every year, with the risk that a competing customer seeks its transmission capacity,and the attendant risk that it must match any longer-term request in order to retain itstransmission service. The transmission customer with the ten-year contract has muchmore certainty than the customer with the one-year contract.

18Citing Nevada Power Co., 97 FERC ¶ 61,324 (2001) (Nevada Power) andPublic Service Co. of New Mexico v. Arizona Public Service Co., 99 FERC ¶ 61,162(2002) (PSNM).

transmission provider determines that it has native load growth or another contractobligation that commences in the future, it can reflect those obligations in the requestedlong-term contract and thereby limit the prospective transmission customer's rolloverrights. If the transmission customer seeks service beyond the period when the nativeload growth or future contractual obligation becomes effective, it must pay for thefacility upgrades necessary to support its service request. Likewise, if a customerrequests transmission service for ten years, but the transmission provider indicates that ithas available capacity to provide the service for only three years, the customer must payfor facility upgrades if it wants service beyond the initial three-year period. Thus, if thetransmission provider properly reflects its planning in the initial transmission contract asdiscussed above, there will be no opportunity for a firm transmission service customer togame the system by requesting a shorter-term contract.17

B. APPLICATION OF ROLLOVER RIGHTS POLICY

i. Reservation in Initial Service Agreement

25. SPP states that the Commission's determination in the May Order that atransmission provider may only recall capacity to serve native load and only if thislimitation is forecasted and set forth in the initial service agreement is a change in policyannounced in orders issued after the service agreement with Exelon was entered into, andcould not have provided notice to SPP of the Commission's changed policy.18 SPPargues that the Commission has changed its policy and has failed to provide adequatenotice to all affected parties that the initial service agreements must include specificprovisions reserving capacity for native load growth. SPP states that the one case citedby the Commission that was adopted prior to the execution of the Exelon service


Docket No. EL02-86-001 - 11 -

1985 FERC ¶ 61,240 at 62,006 (1998) (1998 PSNM Order).

20Further, we find SPP's attempt to distinguish the 1998 PSNM Order to bemisplaced. The 1998 PSNM Order was an order on rehearing addressing, among otherthings, the requirement that "[t]he only way a transmission provider can reclaim capacityis if it explicitly includes in future transmission agreements language that the right of firstrefusal does not apply due to a need for the capacity that is reasonably forecasted at thetime of the agreement's execution." 85 FERC at 62,006. See also Public ServiceCompany of New Mexico, 82 FERC ¶ 61,127 at 61,457 (1998). What is relevant forpurposes of the instant rehearing is that both of these cases confirm and apply theCommission's policy that limitations to rollover rights must be included in the serviceagreement when it is first executed, thereby refuting SPP's argument that theCommission's action constitutes a change in policy.

agreement, Public Service Co. of New Mexico,19 did not involve a situation such as theone SPP faces, where a specific transmission service agreement had expired and thecapacity was simply not available. SPP argues that the 1998 PSNM Order involvedattempts by a single transmission provider to modify its tariff to place restrictions on itscustomers' rollover rights in undefined situations. Therefore, SPP contends, the 1998PSNM Order was inadequate to put the industry or SPP on notice as to the Commission'schanged interpretation of Section 2.2. and should not be applied here.

26. SPP adds that, if the Commission does not grant rehearing, it should state that theMay Order applies prospectively only to service agreements entered into after the date ofthe Commission's rehearing order in this proceeding or at least as of the date of the MayOrder. SPP also requests that the Commission state that the need to satisfy native loadgrowth is not the only reason why a rollover request can be denied, and that factors otherthan native load growth can justify rejection of a rollover request, if specified in theservice agreement. SPP contends that the Commission should state that any suchlimitation can be specified in both the initial service agreement and any agreement for arenewal term, not just in the initial service agreement.

Commission Response

27. We disagree with SPP's argument that the Commission's action in the 1998 PSNMOrder, the May Order, and other orders issued after the service agreement with Exelonwas executed constitutes a change in its policy with regard to rollover rights.20 To thecontrary, our action in the May Order and the other cases cited by SPP is fully consistentwith the rollover rights policy that we established in Order No. 888. In announcing therollover rights policy in Order No. 888, we explained that there are circumstances under


Docket No. EL02-86-001 - 12 -

21Order No. 888 at 31,694.

22Order No. 888-A at 30,198.

23See, e.g., 1998 PSNM Order, 85 FERC at 62,066 (discussing requirement tostate expressly in future transmission contracts (as distinguished from existing (i.e., pre-Order No. 888) contracts) if the right of first refusal does not apply due to a need for thecapacity that is reasonably forecasted at the time of the contract's execution; PSNM, 99FERC at 61,667; Nevada Power, 97 FERC at 62,493.


which a transmission provider can restrict a transmission customer's rollover rights underSection 2.2. For example, the Commission determined that public utilities may reserveexisting transmission capacity needed for native load growth reasonably forecastedwithin the public utility's current planning horizon.21 In Order No. 888-A, theCommission stated that "if a utility provides firm transmission service to a third party fora time until native load needs the capacity, it should specify in the contract that the rightof first refusal does not apply to that firm service due to a reasonably forecasted need atthe time the contract is executed."22

28. Since the issuance of Order Nos. 888 and 888-A, the Commission has consistentlyreaffirmed this policy, stating that a transmission provider can deny a customer the abilityto roll over its long-term firm service contract if the transmission provider includes in theoriginal service agreement a specific limitation based on reasonably forecasted nativeload needs for the transmission capacity provided under the contract at the end of the contract term.23

29. The industry was on adequate notice with the issuance of Order Nos. 888 and888-A of the Commission's policy regarding restrictions on rollover rights. To theextent that, after the issuance of those orders, SPP was uncertain as to the Commission'spolicy in this regard, SPP could have sought clarification at that time. In any event,because the 1998 PSNM Order, the May Order, and the other orders cited by SPP werefully consistent with the Commission's rollover rights policy as established in therulemaking proceeding, none of those orders provided a "changed interpretation ofSection 2.2", as SPP contends.24

30. On this basis, we also will reject SPP's request that the Commission apply itspolicy prospectively only to service agreements entered into after the date of theCommission's rehearing order in this proceeding or at least as of the date of the May


Docket No. EL02-86-001 - 13 -

25See, e.g., Order No. 888-A at 30,198; 1998 PSNM Order, 85 FERC at 62,008;Nevada Power, 97 FERC at 62,493; PSNM, 99 FERC at 61,667; Southern CompanyServices, Inc., 100 FERC ¶ 61,237 at P 17 (2002), reh'g pending.

26See, e.g., Southwest Power Pool, Inc., 100 FERC ¶ 61,358 at P 12; SouthwestPower Pool, Inc, 100 FERC ¶ 61,239 at P 26 (2002), reh'g pending.

27See Section 19.7 of the Order No. 888 pro forma tariff (concerning partialinterim service); see also Morgan Stanley Capital Group v. Illinois Power Company, 93FERC ¶ 61,081 at 61,220 (2000) ("[H]ad Morgan Stanley requested, for example, long-term service for a two-year period, but only one year was available, Illinois Power wouldhave been obligated to offer service for that one available year").

Order. We further will reject SPP's request that limitations on rollover rights can bespecified in both the initial service agreement and any agreement for a renewal term, notjust in the initial service agreement. Commission precedent is clear that such limitationsmust be clearly stated in the customer's original service agreement.25

31. SPP also requests that the Commission state that the need to satisfy native loadgrowth is not the only reason why a rollover request can be denied, and that factors otherthan native load growth can justify rejection of a rollover request, if specified in theservice agreement. In a number of recent orders, the Commission has addressed thisissue and specifically rejected requests by a transmission provider to reduce the capacityavailable for a renewal of transmission service by a transmission customer "due to factorssuch as changes in transmission system topology, loop flow impacts due to changes intransactions on other transmission systems, redispatch of designated networkresources."26

32. However, it may be reasonable for a transmission provider to limit the terms underwhich a new long-term agreement may be rolled over based on a pre-existing contractobligation that commences in the future. For example, to the extent that a SIS completedprior to the execution of the original service agreement indicates that available transfercapability to serve the customer will only be available for a particular time period, afterwhich time it is already committed to another transmission customer under a previously-confirmed transmission request (i.e., an agreement under which service would commenceat some time in the future), the transmission provider can reflect those obligations in thelong-term contract and thereby limit the prospective transmission customer's rolloverrights.27


Docket No. EL02-86-001 - 14 -

28Citing Order No. 888-A at 30,198; Idaho Power, 94 FERC at 62,144-45;Entergy Power Marketing Co. v. Southwest Power Pool, 91 FERC 61,276 at 61,936(2000); Wisconsin Public Power Inc. Sys. v. Wisconsin Public Service Corp., 84 FERC61,120 at 61,655 (1998).

ii. Tie-Breaker Provision

33. SPP argues that Order No. 888-A, the pro forma OATT, and prior Commissionorders describe Section 2.2 as a tie-breaker provision to be used when there arecompeting and substantially similar firm service requests.28 SPP further argues that theCommission's May Order directly contradicts the Commission's prior determinations thatSection 2.2 is intended to provide certain existing customers with a reservation prioritywhen there is a competing request for long term firm point-to-point transmission service,and is not an absolute right to service.

Commission Response

34. Once again, SPP has misconstrued our previous orders. While it is true, as SPPsuggests, that Section 2.2 can serve a a tie-breaking mechanism, that provision is notintended to function only as a tie-breaker. In other words, the rollover rights policy is notintended to apply only when there are competing and substantially similar firm servicerequests. As we have explained in previous orders, Section 2.2 provides a tie-breakingmechanism when a transmission provider has insufficient transmission capacity and thereare competing requests for that available capacity, including an existing long-term firmtransmission customer whose transmission service agreement is up for renewal orrollover. If the transmission provider has insufficient capacity, then Section 2.2 providesa tie-breaker mechanism that gives the transmission customer the right of first refusal. However, in the absence of a competing request for service, the transmission provider isobligated under Section 2.2 to grant a request for rollover by an existing long-termtransmission customer (assuming that the transmission agreement contains no restrictionson rollover rights, as discussed above).

C. APPLICATION OF THE PRO FORMA AND SPP OATTs

35. SPP argues that the May Order contravenes the plain terms of the pro forma andSPP OATTs that require that rollover requests be treated as new transmission requestssubject to the same procedures as all other requests, except that such requests havecertain priority rights over competing requests under Section 2.2. SPP contends that


Docket No. EL02-86-001 - 15 -

29Citing Entergy Power Marketing Corp. v. Southwest Power Pool, Inc., 91 FERC¶ 61,276 at 61,936 (2000) (Entergy).

under Section 2.2 of the SPP and the pro forma OATT, an existing long-term firmtransmission customer has a "transmission reservation priority" over a competing requestfor firm transmission service, provided that the existing long-term firm customer iswilling to match the term and price of the competing request. According to SPP, ifcompeting existing firm service customers apply for service that cannot be fullyprovided, priority rights will be assigned in accordance with first-come, first-servedprinciples. SPP argues that in an earlier decision, the Commission determined that "[b]yexercising a right of first refusal an existing transmission customer is, in effect, arranginga new long-term firm point-to-point transmission service."29

36. SPP states that Section 17 of the pro forma and SPP OATTs sets out theprocedures for arranging firm point-to-point transmission service and, under Section17.5, SPP is obligated to determine the amount of transmission capacity available when itreceives a request for firm point-to-point transmission service of one year or greater. SPP argues that nothing in Section 17 exempts rollover customers from the process. SPPfurther argues that nothing in Section 19 of the pro forma and SPP OATTs, which setsout the requirements for System Impact and Facilities Studies, exempts rollovercustomers.

37. SPP contends that the May Order will interfere with the rights of customers whoexecuted longer-term firm transmission service agreements before many of the one-yearservice agreements, such as Exelon's, were entered into. SPP argues that under Section13.2 of the SPP Tariff, these customers have a higher reservation priority than atransmission customer whose service agreement was executed later in time. SPP statesthat a transmission provider has an obligation to offer an "infill" customer transmissioncapacity that will ultimately be needed by a higher priority customer at a later date, butthe transmission provider is not required to grant a transmission customer who comeslater in time perpetual and superior rights to this capacity. SPP argues that the MayOrder will contravene Section 13.2 and give an "infill" customer rights to the capacitythat will prevent or impair the use by the higher priority customer.

Commission Response

38. Contrary to SPP's assertions, the May Order is entirely consistent with theprovisions of the pro forma OATT and SPP's OATT. In Order No. 888, we concludedthat, subject to certain limitations, all firm transmission customers (requirements and


Docket No. EL02-86-001 - 16 -

30Order No. 888 at 31,665.

31Entergy, 91 FERC at 61,936.

32Id.


transmission-only), upon the expiration of their contracts or at the time their contractsbecome subject to renewal or rollover, should have the right to continue to taketransmission service from their existing transmission provider.30

39. In Entergy, when we stated that "[b]y exercising a right of first refusal an existingtransmission customer is, in effect, arranging a new long-term firm point-to-pointtransmission service,"31 we did not mean that the rollover request was to be treated as anew long-term request for service for purposes of a new determination of availabletransmission capacity under Section 17.5 or a new system impact study. The issue inEntergy was the time period within which a customer exercising its right of first refusalmust make an application for its new service term and notify the transmission providerthat it wishes to exercise its reservation priority. We concluded that, "[c]onsistent withthe reservation procedures in Section 17.1, we clarify that the pro forma tariff requirescustomers to notify the transmission provider that they are exercising their right of firstrefusal at the time they tender their request for the new service term, which must be noless than 60 days prior to the date the existing contract ends and the new service termcommences. This procedure should provide sufficient protection to existing transmissioncustomers (our original rationale for establishing a right of first refusal) as well asprovide a reasonable and consistent notice period for all transmission reservations."32

40. We did not intend to suggest or imply that a transmission provider would make adetermination of available transmission capacity or perform a new system impact studyeach time that a long-term firm transmission customer elects to roll over its existingtransmission service, and SPP's arguments to the contrary are wrong. Indeed, such aninterpretation would effectively undermine the entire rollover rights policy established inOrder No. 888 and set forth in Section 2.2 of the pro forma OATT. The only instance inwhich a transmission provider can require a new system impact study for an existinglong-term customer seeking to rollover over its service would be where that customerrequests a change to a receipt or delivery point in an existing long-term firm transmissionservice agreement. In that instance, the customer's request can be treated as a newrequest for service for purposes of the availability of capacity.33 In Order No. 888-A,with


Docket No. EL02-86-001 - 17 -

34Order No. 888-A at 30,198, n. 52.

respect to a proposal to limit the right of first refusal to the same points of receipt anddelivery as the terminating service, the Commission explained that such a proposal:

would competitively disadvantage existing customers seeking new sources ofgeneration. However, as we stated in Order No. 888, if the customer chooses anew power supplier and this substantially changes the location or direction of thepower flows it imposes on the transmission provider's system, the customer's rightto continue taking transmission service from its existing transmission providermay be affected by transmission constraints associated with the change.34

41. Based on the foregoing, we deny SPP's request for rehearing. Furthermore, wedismiss SPP's request that, in the alternative, the findings in the May Order be appliedprospectively only.


SPP's request for rehearing is hereby denied.

By the Commission.

( S E A L )

Magalie R. Salas, Secretary.


Tab 10



November 5, 2008

In Reply Refer To:H.Q. Energy Services (U.S.) Inc.Docket Nos. ER97-851-017

ER97-851-018ER97-851-019

Skadden, Arps, Slate, Meagher & Flom LLPAttn: Jerry L. Pfeffer, Esq.1440 New York Avenue, N.W.Washington, D.C. 20005-2111

Reference: Updated Market Power Analysis in Compliance with Order No. 697

Dear Mr. Pfeffer:

1. On June 26, 2008, H.Q. Energy Services (U.S.) Inc. (H.Q. Energy) filed anupdated market power analysis in accordance with the regional reporting scheduleadopted in Order No. 697.1 H.Q. Energy also submitted revised tariff sheets to

1 Market-Based Rates for Wholesale Sales of Electric Energy, Capacity andAncillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252, atP 882, clarified, 121 FERC ¶ 61,260 (2007) (Order Clarifying Final Rule), order onreh’g, Order No. 697-A, 73 Fed. Reg. 25,832 (May 7, 2008) FERC Stats. & Regs.¶ 31,268 (2008), order on reh’g and clarification, 124 FERC ¶ 61,055 (2008). TheCommission stated that “both the Commission and market participants will benefit fromgreater data consistency that will result from regional examination of updated marketpower analyses and a methodical study of all sellers in the same region. This will givethe Commission a more complete view of market forces in each region and theopportunity to reconcile conflicting submissions, enhancing our ability to ensure thatsellers’ rates remain just and reasonable.” Order Clarifying Final Rule, 121 FERC¶ 61,260 at P 13.

20081105-3006 FERC PDF (Unofficial) 11/05/2008

Docket No. ER97-851-017, et. al. 2

incorporate the required provisions adopted by the Commission in Order Nos. 697 and697-A.2

2. On July 29, 2008, H.Q. Energy submitted revised tariff sheets to provide for thesale of ancillary services in the market administered by the Midwest Independent SystemOperator, Inc.3

3. On September 19, 2008, H.Q. Energy filed a notice of change in status updating arepresentation made in its June 26, 2008 updated market power analysis. H.Q. Energyclarifies that possible changes to H.Q. Energy’s Canadian transmission affiliates’4 openaccess transmission tariffs (OATTs) to conform with the requirements of Order Nos. 890and 890-A,5 currently under consideration by the Québec Energy Board (Régie del’énergie), will likely be implemented after January 2009 rather than before January2009, given that the Régie de l’énergie will not rule on H.Q.-TransÉnergie’s OATT bythe end of the year.

4. As discussed below, H.Q. Energy’s submittals satisfy the Commission’s standardsfor market-based rate authority, and are accepted for filing,6 effective September 27,2008, as requested.

5. H.Q. Energy is a wholly-owned subsidiary of Hydro-Québec (H.Q.), a Crowncorporation in the Province of Québec, Canada.

6. In the United States, H.Q. Energy has an indirect ownership interest in BucksportEnergy, LLC, a qualifying cogeneration facility located in Bucksport, Maine located inthe ISO New England, Inc. (ISO-NE) market. Also, H.Q. Energy owns the Les Cedars

2 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 914-18, Order No. 697-A,FERC Stats. & Regs. ¶ 31,268 at P 382-85.

3 Midwest Independent System Operator, Inc., 123 FERC ¶ 61,297, at P 46 (2008).

4 H.Q. Energy’s Canadian transmission affiliates are Hydro-Québec TransÉnergie(H.Q. TransÉnergie) and Cedar Rapids Transmission Company (collectively,transmission affiliates).

5 Preventing Undue Discrimination and Preference in Transmission Service,Order No. 890, FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERCStats. & Regs. ¶ 31,261 (2007), order on reh’g and clarification, Order No. 890-B,123 FERC ¶ 61,299 (2008).

6 H.Q. Energy Services (U.S.) Inc., First Revised FERC Rate Schedule No. 1,Third Revised Sheet Nos. 2 (superseding Second Revised Sheet Nos. 1-2).



generating plant, which is physically located in Québec but which the New YorkIndependent System Operator, Inc. (NYISO) models as an integral generator in theNYISO market.7

7. Notices of H.Q. Energy’s June 26, 2008 filing, its July 29, 2008 filing, and itsSeptember 19, 2008 filing were published in the Federal Register,8 with interventions orprotests due on or before August 25, 2008, August 19, 2008, and October 10, 2008respectively. On July 17, 2008, Newfoundland and Labrador Hydro filed a timely motionto intervene and provide informational comments. On July 28, 2008, H.Q. Energy filedan answer.

8. Pursuant to Rule 214 of the Commission’s Rule of Practice and Procedure,18 C.F.R. § 385.214 (2008), Newfoundland and Labrador Hydro’s timely, unopposedmotion to intervene serves to make it a party to this proceeding. Rule 213(a)(2) of theCommission’s Rules of Practice and Procedure, 18 C.F.R. § 385.213(a)(2) (2008),prohibits an answer to a protest unless otherwise ordered by the decisional authority. Wewill accept H.Q. Energy’s answer because it has provided information that assisted us inour decision-making process.

9. Newfoundland and Labrador Hydro states that it does not take a position regardingany action the Commission may pursue with respect to H.Q. Energy’s filing.Newfoundland and Labrador Hydro states that it seeks to provide backgroundinformation regarding positions that it has taken before the Régie de l’énergie, whichregulates electricity transmission in Québec. Newfoundland and Labrador Hydro statesthat its interests are directly affected by this proceeding, as it plans to export electricity tothe United States beginning in 2015 from its Lower Churchill Project and is in activediscussions with H.Q. Energy’s Canadian transmission affiliate, H.Q. TransEnergie.Newfoundland and Labrador Hydro alerts the Commission to concerns it has regardingthe sufficiency of H.Q. TransÉnergie’s OATT and its implementation in an open andnon-discriminatory manner. Newfoundland and Labrador Hydro states that over the past

7 H.Q. Energy was authorized to sell electric energy and capacity at wholesale atmarket-based rates in HQ Energy Services (U.S.) Inc., 81 FERC ¶ 61,184 (1997), reh’gdenied, 82 FERC ¶ 61,234 (1998); HQ Energy Services (U.S.) Inc., 79 FERC ¶ 61,152(1997).

8 73 Fed. Reg. 40,571 (2008); 73 Fed. Reg. 46,615 (2008); 73 Fed. Reg. 56,811(2008).



year, it has filed three complaints with the Régie de l’énergie regarding administration ofH.Q. TransÉnergie’s OATT in relation to its transmission service requests.9

10. Newfoundland and Labrador Hydro states that H.Q. TransÉnergie has not yetupdated its OATT to be consistent with Order No. 890’s additional transmission planningrequirements.

11. Newfoundland and Labrador Hydro states that its present complaints before theRégie de l’énergie are to ensure that an erroneous implementation of the H.Q.TransÉnergie OATT does not deprive Newfoundland and Labrador Hydro of access tothe U.S. Northeast electricity markets over the H.Q. TransÉnergie system.Newfoundland and Labrador Hydro states that its complaints before the Régie del’énergie raise issues regarding insufficient information provided in system impactstudies and failure to properly calculate and post available transmission capacity, whichare similar to issues the Commission has addressed in OATT compliance cases.

12. In its reply comments, H.Q. Energy states that Newfoundland and Labrador Hydrohas not objected to anything contained in H.Q. Energy’s updated market power analysis.H.Q. Energy further states that the issues raised by Newfoundland and Labrador Hydroare currently pending before the Régie de l’énergie.

13. The Commission allows power sales at market-based rates if the seller and itsaffiliates do not have, or have adequately mitigated, horizontal and vertical marketpower.10 As discussed below, the Commission concludes that H.Q. Energy satisfies theCommission’s standards for market-based rate authority.

14. The Commission adopted two indicative screens for assessing horizontal marketpower, the pivotal supplier screen and the wholesale market share screen.11 H.Q. Energyhas prepared the pivotal supplier and wholesale market share screens for the ISO-NE andNYISO markets, consistent with the requirements of Order No. 697.12

9 Newfoundland and Labrador Hydro included the three complaints as anattachment to its comments: Case No. P-110-1565, Newfoundland and Labrador Hydrov. Hydro Quebec (filed Jan. 11, 2008); Case No. P-1566, Newfoundland and LabradorHydro v. Hydro Quebec (filed Jan. 11, 2008); and P-110-1597, Newfoundland andLabrador Hydro v. Hydro Quebec (filed April 4, 2008).

10 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 62, 399, 408, 440.

11 Id. P 62.

12 Id. P 235.



15. The Commission has reviewed H.Q. Energy’s pivotal supplier screen andwholesale market share screen and has determined that H.Q. Energy passes the pivotalsupplier screen and the wholesale market share screen in the ISO-NE and NYISOmarkets. Accordingly, the Commission finds that H.Q. Energy satisfies theCommission’s requirements for market-based rates regarding horizontal market power.

16. The Commission requires in cases where a market-based rate seller is a foreignutility or is affiliated with a foreign utility that owns, operates, or controls transmissionfacilities outside of the United States and is interconnected with the United States todemonstrate that comparable, non-discriminatory access is offered on those facilities sothat competitors of the seller may reach United States markets.13

17. The Commission also considers a seller’s ability to erect other barriers to entry aspart of the vertical market power analysis.14 The Commission requires a seller to providea description of its ownership or control of, or affiliation with an entity that owns orcontrols, intrastate natural gas transportation, storage or distribution facilities; sites forgeneration capacity development; and sources of coal supplies and equipment for thetransportation of coal supplies such as barges and rail cars (collectively, inputs to electricpower production).15 The Commission also requires sellers to make an affirmativestatement that they have not erected barriers to entry into the relevant market and will noterect barriers to entry into the relevant market.16

18. H.Q. Energy states that its transmission affiliates own transmission assets locatedin Québec, which are subject to OATTs accepted by the Commission as satisfyingreciprocity requirements and which do not allow H.Q. Energy and its affiliates to raisebarriers to entry or impede competitors in Canada from accessing U.S. electricitymarkets.17 H.Q. Energy also states that its transmission affiliates are in the process ofadapting their OATTs to the provisions of Order Nos. 890 and 890-A, and those OATTs

13 Id. P 1007-1008.

14 Id. P 440.

15 Id. P 447. In Order No. 697-A, the Commission revised the definition of inputsto electric power production to include “physical coal supply sources and ownership of orcontrol over who may access transportation of coal supplies.” Order No. 697-A, FERCStats. & Regs. ¶ 31,268 at P 176.

16 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 447.

17 H.Q. Energy’s June 26, 2008 Filing at 7-8.



are currently under consideration by the Régie de l’énergie.18 H.Q. Energy also statesthat its transmission affiliates continue to provide open and non-discriminatory access toall suppliers within Canada seeking to deliver power to the U.S. markets over andthrough their transmission facilities, and therefore H.Q. Energy has mitigated anytransmission market power.19 Further, H.Q. Energy states that it does not own or controlinputs to electric power production, and it affirmatively states that neither it nor itsaffiliates have or will erect barriers to entry in relevant markets.

19. Based on H.Q. Energy’s representations, H.Q. Energy satisfies the Commission’srequirements for market-based rates regarding vertical market power.

20. Order No. 697 adopted two standard required provisions that each seller mustinclude in its market-based rate tariff: a provision requiring compliance with theCommission’s regulations and a provision identifying any limitations and exemptionsregarding the seller’s market-based rate authority.20 In addition to the required tariffprovisions, Order No. 697 adopted a set of standard provisions that must be included in aseller’s market-based rate tariff to the extent that they are applicable and also requires anasset appendix.21 In Order No. 697-A, the Commission also required that each sellerinclude in its market-based rate tariff a provision identifying which category of seller itqualifies as in each region.

21. H.Q. Energy’s market-based rate tariff includes the Commission’s two requiredprovisions, indicating that H.Q. Energy intends to comply with the Commission'sregulations, including the affiliate restrictions. H.Q. Energy’s market-based rate tariffalso includes a set of standard provisions with regard to sales of certain ancillary servicesin various markets, as well as a provision regarding sales of ancillary services as a thirdparty supplier, and the required category designation. H.Q. Energy’s filing also includes

18 H.Q. Energy submits that its transmission affiliates anticipate that the revisedterms and conditions of the OATTs will become effective after January 2009. H.Q.Energy’s June 26, 2008 Filing at 7, n.16 & Attachment D. H.Q. Energy further states thaton September 11, 2008, the Régie de l’énergie ruled that it required additionalinformation to support the proposed tariff amendments in H.Q. TransÉnergie’s requestfor tariff modifications to comply with Order Nos. 890 and 890-A. H.Q. Energy’sSeptember 19, 2008 Filing at 2.

19 See H.Q. Energy Services (U.S.) Inc., 79 FERC ¶ 61,152 at 61,652-53;TransÉnergie U.S.,Ltd., 91 FERC ¶ 61,230, at 61,838 (2000).


21 Id. at P 917.



the required asset appendix. We find that H.Q. Energy’s market-based rate tariff satisfiesthe Commission’s requirements set forth in Order Nos. 697 and 697-A, and accept theirrevised market-based rate tariffs, effective September 27, 2008, as requested.

22. Consistent with the procedures the Commission adopted in Order No. 2001, anentity with market-based rates must file electronically with the Commission an ElectricQuarterly Report containing: (1) a summary of the contractual terms and conditions inevery effective service agreement for market-based power sales; and (2) transactioninformation for effective short-term (less than one year) and long-term (one year orlonger) market-based power sales during the most recent calendar quarter.22 Publicutilities must file Electric Quarterly Reports no later than 30 days after the end of thereporting quarter.23

23. H.Q. Energy must timely report to the Commission any change in status thatwould reflect a departure from the characteristics the Commission relied upon in grantingmarket-based rate authority.24

24. Additionally, in Order No. 697, the Commission created two categories ofsellers.25 Category 1 sellers are not required to file regularly scheduled updated marketpower analyses. Category 1 sellers are wholesale power marketers and wholesale power

22 Revised Public Utility Filing Requirements, Order No. 2001, FERC Stats. &Regs. ¶ 31,127, reh’g denied, Order No. 2001-A, 100 FERC ¶ 61,074, reh’g denied,Order No. 2001-B, 100 FERC ¶ 61,342, order directing filing, OrderNo. 2001-C,101 FERC ¶ 61,314 (2002), order directing filing, Order No. 2001-D,102 FERC ¶ 61,334 (2003). Attachments B and C of Order No. 2001 describe therequired data sets for contractual and transaction information. Public utilities mustsubmit Electric Quarterly Reports to the Commission using the EQR Submission SystemSoftware, which may be downloaded from the Commission’s website athttp://www.ferc.gov/docs-filing/eqr.asp.

23 The exact filing dates for these reports are prescribed in 18 C.F.R. § 35.10b(2008). Failure to file an Electric Quarterly Report (without an appropriate request forextension), or failure to report an agreement in an Electric Quarterly Report, may result inforfeiture of market-based rate authority, requiring filing of a new application for market-based rate authority if the applicant wishes to resume making sales at market-based rates.

24 Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority, Order No. 652, FERC Stats. & Regs. ¶ 31,175, order on reh’g,111 FERC ¶ 61,413 (2005); 18 C.F.R. § 35.42 (2008).




producers that own or control 500 MW or less of generation in aggregate per region; thatdo not own, operate, or control transmission facilities other than limited equipmentnecessary to connect individual generation facilities to the transmission grid (or havebeen granted waiver of the requirements of Order No. 88826); that are not affiliated withanyone that owns, operates or controls transmission facilities in the same region as theseller’s generation assets; that are not affiliated with a franchised public utility in thesame region as the seller’s generation assets; and that do not raise other vertical marketpower issues.27 Sellers that do not fall into Category 1 are designated as Category 2 andare required to file regularly scheduled updated market power analyses.28

25. Based on H.Q. Energy’s representations, we find that H.Q. Energy meets thecriteria for a Category 1 seller and is so designated.

By direction of the Commission.

Kimberly D. Bose,Secretary.

26 Promoting Wholesale Competition Through Open Access Non-discriminatoryTransmission Services by Public Utilities and Recovery of Stranded Costs by PublicUtilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 (1997), order onreh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C,82 FERC ¶ 61,046 (1998), aff'd in part and rev'd in part sub nom. Transmission AccessPolicy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v.FERC, 535 U.S. 1 (2002).

27 18 C.F.R. § 35.36(a)(2) (2008).



Document Content(s)

19796085.DOC..........................................................1-8


Tab 11

Tab 12



18 CFR Part 40

[Docket Nos. RM08-19-000, RM08-19-001, RM09-5-000, RM06-16-005]

Mandatory Reliability Standards for the Calculation of Available Transfer Capability,Capacity Benefit Margins, Transmission Reliability Margins, Total Transfer Capability,and Existing Transmission Commitments and Mandatory Reliability Standards for the

Bulk-Power System

(Issued March 19, 2009)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Proposed Rulemaking.

SUMMARY: Pursuant to section 215 of the Federal Power Act, the Commission

proposes to approve six Modeling, Data, and Analysis Reliability Standards submitted to

the Commission for approval by the North American Electric Reliability Corporation, the

Electric Reliability Organization certified by the Commission. The proposed Reliability

Standards require certain users, owners, and operators of the Bulk-Power System to

develop consistent methodologies for the calculation of available transfer capability or

available flowgate capability.

DATES: Comments are due [insert date that is 60 days after publication in the

FEDERAL REGISTER]


Docket Nos. RM08-19-000, et al. 2

ADDRESSES: You may submit comments, identified by docket number by any of the

following methods:

• Agency Web Site: http://ferc.gov. Documents created electronically using word

processing software should be filed in native applications or print-to-PDF format

and not in a scanned format.

• Mail/Hand Delivery: Commenters unable to file comments electronically must

mail or hand deliver an original and 14 copies of their comments to: Federal

Energy Regulatory Commission, Secretary of the Commission, 888 First Street,

N.E., Washington, D.C. 20426.

FOR FURTHER INFORMATION CONTACT:

Mason Emnett (Legal Information)Office of the General CounselFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426(202) 502-6540

Cory Lankford (Legal Information)Office of the General CounselFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426(202) 502-6711

Keith O’Neal (Technical Information)Office of Electric ReliabilityFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426(202) 502-6339



Christopher Young (Technical Information)Office of Electric ReliabilityFederal Energy Regulatory Commission888 First Street, N.E.Washington, D.C. 20426(202) 502-6403

SUPPLEMENTARY INFORMATION:




Mandatory Reliability Standards for the Calculation ofAvailable Transfer Capability, Capacity BenefitMargins, Transmission Reliability Margins, TotalTransfer Capability, and Existing TransmissionCommitments and Mandatory Reliability Standards forthe Bulk-Power System

Docket Nos. RM08-19-000RM08-19-001RM09-5-000RM06-16-005

NOTICE OF PROPOSED RULEMAKING

TABLE OF CONTENTS


Paragraph Numbers

I. Background................................................................................................................... 4.A. Order Nos. 888 and 889 ........................................................................................... 4.B. Order Nos. 890 and 693 ........................................................................................... 8.

II. Proposed Reliability Standards............................................................................... 12.A. Coordination with Business Practice Standards..................................................... 17.B. Available Transmission System Capability, MOD-001-1 ..................................... 19.C. Capacity Benefit Margin Methodology, MOD-004-1 ........................................... 26.D. Transmission Reliability Margin Methodology, MOD-008-1............................... 41.E. Three Methodologies for Calculating Available Transfer Capability.................... 51.

1. Area Interchange Methodology, MOD-028-1 .................................................... 53.2. Rated System Path Methodology, MOD-029-1 ................................................. 61.3. Flowgate Methodology, MOD-030-2................................................................. 65.

F. Implementation Plan ............................................................................................... 72.

III. Discussion................................................................................................................. 75.A. Implementation of the Reliability Standards.......................................................... 80.

1. Available Transfer Capability Implementation Documents............................... 87.2. Capacity Benefit Margin Implementation Documents....................................... 95.3. Transmission Reliability Margin Implementation Documents .......................... 98.

B. Proposed Modifications of the Reliability Standards........................................... 102.


Docket Nos. RM08-19-000, et al. ii

1. Availability of Implementation Documents ..................................................... 103.2. Consistent Treatment of Assumptions.............................................................. 106.3. Capacity Benefit Margin (MOD-004-1)........................................................... 109.4. Calculation of Total Transfer Capability under the Rated System PathMethodology (MOD-029-1) .................................................................................. 112.5. Treatment of Network Resource Designations................................................. 116.

C. Violation Risk Factors and Violation Severity Levels......................................... 121.D. Disposition of Other Reliability Standards .......................................................... 130.

1. MOD-010-1 through MOD-025-1.................................................................... 130.2. Reliability Standards Proposed to be Retired or Withdrawn............................ 133.

E. Definitions ............................................................................................................ 139.

IV. Information Collection Statement ....................................................................... 143.

V. Environmental Analysis ......................................................................................... 148.

VI. Regulatory Flexibility Act Certification ............................................................. 149.

VII. Comment Procedures .......................................................................................... 151.

VIII. Document Availability ....................................................................................... 155.


UNITED STATES OF AMERICAFEDERAL ENERGY REGULATORY COMMISSION

Mandatory Reliability Standards for the Calculation ofAvailable Transfer Capability, Capacity BenefitMargins, Transmission Reliability Margins, TotalTransfer Capability, and Existing TransmissionCommitments and Mandatory Reliability Standards forthe Bulk-Power System

Docket Nos. RM08-19-000RM08-19-001RM09-5-000RM06-16-005

NOTICE OF PROPOSED RULEMAKING


1. Pursuant to section 215 of the Federal Power Act (FPA),1 the Federal Energy

Regulatory Commission (Commission) proposes to approve, and direct modifications to,

six Modeling, Data and Analysis (MOD) Reliability Standards submitted to the

Commission by the North American Electric Reliability Corporation (NERC), which has

been certified by the Commission as the Electric Reliability Organization (ERO) for the

United States.2 The proposed Reliability Standards pertain to methodologies for the

consistent and transparent calculation of available transfer capability or available

flowgate capability. The Commission also proposes to retire the existing MOD

Reliability Standards replaced by the versions proposed here. The retirement of these

1 16 U.S.C. 824o.

2 North American Electric Reliability Corp., 116 FERC ¶ 61,062 (EROCertification Order), order on reh’g & compliance, 117 FERC ¶ 61,126 (ERO RehearingOrder) (2006), appeal docketed sub nom. Alcoa, Inc. v. FERC, No. 06-1426 (D.C. Cir.Dec. 29, 2006).



Reliability Standards would be effective upon the effective date of the proposed MOD

Reliability Standards.

2. In Order No. 890, the Commission found that the lack of a consistent and

transparent methodology for calculating available transfer capability is a significant

problem because the calculation of available transfer capability, which varies greatly

depending on the criteria and assumptions used, may allow the transmission service

provider to discriminate in subtle ways against its competitors.3 The calculation of

available transfer capability is one of the most critical functions under the open access

transmission tariff (OATT) because it determines whether transmission customers can

access alternative power supplies. Improving transparency and consistency of available

transfer capability calculation methodologies will eliminate transmission service

providers’ wide discretion in calculating available transfer capability and ensure that

customers are treated fairly in seeking alternative power supplies. The Commission

believes that the Reliability Standards proposed here address the potential for undue

discrimination by requiring industry-wide transparency and increased consistency

regarding all components of the available transfer capability calculation methodology and

certain definitions, data, and modeling assumptions.

3 Preventing Undue Discrimination and Preference in Transmission Service, OrderNo. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), order onreh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats & Regs. ¶ 31,261(2007), order on reh’g, Order No. 890-B, 73 FR 39092 (July 8, 2008), 123 FERC¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009).



3. The Commission proposes to approve the Reliability Standards filed by NERC in

this proceeding as just, reasonable, not unduly discriminatory or preferential, and in the

public interest. These Reliability Standards represent a step forward in eliminating the

broad discretion previously afforded transmission service providers in the calculation of

available transfer capability. The proposed Reliability Standards will enhance

transparency in the calculation of available transfer capability, requiring transmission

operators and transmission service providers to calculate available transfer capability

using a specific methodology that is both explicitly documented and available to

reliability entities who request it.4 The proposed Reliability Standards also require

documentation of the detailed representations of the various components that comprise

the available transfer capability equation, including the specification of modeling and risk

assumptions and the disclosure of outage processing rules to other reliability entities.

These actions will make the processes to calculate available transfer capability and its

various components more transparent, which in turn will allow the Commission and

others to ensure consistency in their application.

4 Reliability entities include: transmission service providers, planningcoordinators, reliability coordinators, and transmission operators as those entities aredefined in the NERC Glossary. Standards adopted by the North American EnergyStandards Board (NAESB) govern disclosure of this information to other entities. TheCommission addresses the proposed NAESB business practices in a Notice of ProposedRulemaking issued concurrently in Docket No. RM05-5-013. See Standards for BusinessPractices and Communication Protocols for Public Utilities, 126 FERC ¶ 61,248 (2009).



I. Background

A. Order Nos. 888 and 889

4. In April 1996, as part of its statutory obligation under sections 205 and 206 of the

FPA5 to remedy undue discrimination, the Commission adopted Order No. 888

prohibiting public utilities from using their monopoly power over transmission to unduly

discriminate against others.6 In that order, the Commission required all public utilities

that own, control or operate facilities used for transmitting electric energy in interstate

commerce to file open access non-discriminatory transmission tariffs that contained

minimum terms and conditions of non-discriminatory service. It also obligated such

public utilities to “functionally unbundle” their generation and transmission services.

This meant that public utilities had to take transmission service (including ancillary

services) for their own new wholesale sales and purchases of electric energy under the

open access tariffs, and to separately state their rates for wholesale generation,

transmission and ancillary services.7 Each public utility was required to file the pro

5 16 U.S.C. 824d, 824e.

6 Promoting Wholesale Competition Through Open Access Non-discriminatoryTransmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilitiesand Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. &Regs. ¶ 31,036 (1996), order on reh’g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997),FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d inrelevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667(D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).

7 This is known as “functional unbundling” because the transmission element of awholesale sale is separated or unbundled from the generation element of that sale,although the public utility may provide both functions.



forma OATT included in Order No. 888 without any deviation (except a limited number

of terms and conditions that reflect regional practices).8 After their OATTs became

effective, public utilities were allowed to file, pursuant to section 205 of the FPA,

deviations that were consistent with or superior to the pro forma OATT’s terms and

conditions.

5. The same day it issued Order No. 888, the Commission issued a companion order,

Order No. 889,9 addressing the separation of vertically integrated utilities’ transmission

and merchant functions, the information transmission service providers were required to

make public, and the electronic means they were required to use to do so. Order No. 889

imposed Standards of Conduct governing the separation of, and communications

between, the utility’s transmission and wholesale power functions, to prevent the utility

from giving its merchant arm preferential access to transmission information. All public

utilities that owned, controlled or operated facilities used in the transmission of electric

energy in interstate commerce were required to create or participate in an Open Access

8 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,769-70 (noting that thepro forma OATT expressly identified certain non-rate terms and conditions, such as thetime deadlines for determining available transfer capability in section 18.4 or schedulingchanges in sections 13.8 and 14.6, that may be modified to account for regional practicesif such practices are reasonable, generally accepted in the region, and consistentlyadhered to by the transmission service provider).

9 Open Access Same-Time Information System (Formerly Real-Time InformationNetworks) and Standards of Conduct, Order No. 889, 61 FR 21737 (May 10, 1996),FERC Stats. & Regs. ¶ 31,035 (1996), order on reh’g, Order No. 889-A, FERC Stats.& Regs. ¶ 31,049 (1997), order on reh’g, Order No. 889-B, 81 FERC ¶ 61,253 (1997).



Same-Time Information System (OASIS) that was to provide existing and potential

transmission customers the same access to transmission information.

6. Among the information public utilities were required to post on their OASIS was

the transmission service provider’s calculation of available transfer capability. Though

the Commission acknowledged that before-the-fact measurement of the availability of

transmission service is “difficult,” the Commission concluded that it was important to

give potential transmission customers “an easy-to-understand indicator of service

availability.”10 Because formal methods did not then exist to calculate available transfer

capability and total transfer capability, the Commission encouraged industry efforts to

develop consistent methods for calculating available transfer capability and total transfer

capability.11 Order No. 889 ultimately required transmission service providers to base

their calculations on “current industry practices, standards and criteria” and to describe

their methodology in an Attachment C to their tariffs.12 The Commission noted that the

requirement that transmission service providers purchase only available transfer

capability that is posted as available “should create an adequate incentive for them to

calculate available transfer capability and total transfer capability as accurately and as

uniformly as possible.”13

10 Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 21749.

11 Id. at 21750.

12 Id.

13 Id.



7. Although Order No. 888 obligated each public utility to calculate the amount of

transfer capability on its system available for sale to third parties, the Commission did not

standardize the methodology for calculating available transfer capability, nor did it

impose any specific requirements regarding the disclosure of the methodologies used by

each transmission service provider.14 As a result, a variety of available transfer capability

calculation methodologies have been used with very few clear rules governing their use.

Moreover, there was often very little transparency about the nature of these calculations,

given that many transmission service providers historically filed only summary

explanations of their available transfer capability methodologies in Attachment C to their

OATTs.

B. Order Nos. 890 and 693

8. Section 215 of the FPA requires a Commission-certified ERO to develop

mandatory and enforceable Reliability Standards, which are subject to Commission

review and approval. If approved, the Reliability Standards are enforced by the ERO,

subject to Commission oversight, or by the Commission independently. As the ERO,

NERC worked with industry to develop Reliability Standards improving consistency and

transparency of available transfer capability calculation methodologies. On April 4,

2006, as modified on August 28, 2006, NERC submitted to the Commission a petition

seeking approval of 107 proposed Reliability Standards, including 23 Reliability

Standards pertaining to Modeling, Data and Analysis (MOD). The MOD group of

14 Order No. 888, FERC Stats. & Regs. ¶ 31,036 n.610.



Reliability Standards is intended to standardize methodologies and system data needed

for traditional transmission system operation and expansion planning, reliability

assessment and the calculation of available transfer capability in an open access

environment.

9. On February 16, 2007, the Commission issued Order No. 890, which addressed

and remedied opportunities for undue discrimination under the pro forma OATT adopted

in Order No. 888. Among other things, the Commission required industry-wide

consistency and transparency of all components of available transfer capability

calculation and certain definitions, data and modeling assumptions. The Commission

concluded that the lack of industry-wide standards for the consistent calculation of

available transfer capability poses a threat to the reliable operation of the Bulk-Power

System, particularly with respect to the inability of one transmission service provider to

know with certainty its neighbors’ system conditions affecting its own available transfer

capability values. As a result of this reliability concern, the Commission asserted that the

proposed available transfer capability reforms were also supported by FPA section 215,

through which the Commission has the authority to direct the ERO to submit a Reliability

Standard that addresses a specific matter.15 Thus, the Commission in Order No. 890

directed industry to develop Reliability Standards, using the ERO’s Reliability Standards

development procedures, that provide for consistency and transparency in the

methodologies used by transmission owners to calculate available transfer capability.

15 FPA section 215(d)(5). 16 U.S.C. 824o(d)(5).



10. The Commission stated in Order No. 890 that the available transfer capability-

related Reliability Standards should, at a minimum, provide a framework for available

transfer capability, total transfer capability and existing transmission commitments

calculations. The Commission did not require a single computational process for

calculating available transfer capability because, among other things, it found that the

potential for discrimination and decline in reliability level does not lie primarily in the

choice of an available transfer capability calculation methodology, but rather in the

consistent application of its components, input and exchange data, and modeling

assumptions.16 The Commission found that, if all of the available transfer capability

components, and certain data inputs and assumptions are consistent, the three available

transfer capability calculation methodologies would produce predictable and sufficiently

accurate, consistent, equivalent and replicable results.17

11. On March 16, 2007, the Commission issued Order No. 693, approving 83 of the

107 Reliability Standards filed by NERC in April 2006.18 Of the 83 approved Reliability

Standards, the Commission approved ten MOD Reliability Standards.19 However, the

Commission directed NERC to prospectively modify nine of the ten approved MOD


17 Id. P 1030.

18 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693,72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No.693-A, 120 FERC ¶ 61,053 (2007).

19 Id. P 1010.



Reliability Standards to be consistent with the requirements of Order No. 890.20 The

Commission reiterated the requirement from Order No. 890 that all available transfer

capability components (i.e., total transfer capability, existing transmission commitments,

capacity benefit margin, and transmission reliability margin) and certain data input, data

exchange, and assumptions be consistent and that the number of industry-wide available

transfer capability calculation formulas be few in number, transparent and produce

equivalent results.21 The Commission directed public utilities, working through the

NERC Reliability Standards and NAESB business practices development processes, to

produce workable solutions to implement the available transfer capability-related reforms

adopted by the Commission. The Commission also deferred action on 24 proposed

Reliability Standards, which did not contain sufficient information to enable the

Commission to propose a disposition.22

II. Proposed Reliability Standards

12. In response to the requirements of Order No. 890 and related directives of Order

No. 693,23 on August 29, 2008, NERC submitted for Commission approval five MOD

20 Id.

21 Id. P 1029-30; see also Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 207.

22 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 287-303. Some of theseReliability Standards required the regional reliability organizations to develop criteria foruse by users, owners or operators within each region. The Commission set aside suchReliability Standards and directed NERC to provide additional details prior toconsidering them for approval. Id. P 287-303.

23 The Reliability Standards were originally due on December 10, 2007. SeeOrder No. 890, FERC Stats. & Regs. ¶ 31,241 at P 223. NERC requested additional time

(continued…)



Reliability Standards: MOD-001-1 – Available Transmission System Capability, MOD-

008-1 - TRM Calculation Methodology (hereinafter Transmission Reliability Margin

Methodology), MOD-028-1 Area Interchange Methodology, MOD-029-1 - Rated System

Path Methodology, and MOD-030-1 - Flowgate Methodology.24 On November 21, 2008,

NERC submitted for Commission approval a sixth MOD Reliability Standard: MOD-

004-1 - Capacity Benefit Margin (hereinafter Capacity Benefit Margin Methodology).

On March 6, 2009, NERC submitted for Commission approval: MOD-030-2 – a revised

Flowgate Methodology Reliability Standard and withdrew its request for approval of

MOD-030-1.

13. The Available Transmission System Capability Reliability Standard (MOD-001-1)

serves as an “umbrella” Reliability Standard that requires each applicable entity to select

and implement one or more of the three available transfer capability methodologies found

in MOD-028-1, MOD-029-1, or MOD-030-2. MOD-004-1 and MOD-008-1 provide for

the calculation of capacity benefit margin and transmission reliability margin, which are

inputs into the available transfer capability calculation. If approved, NERC states that its

to develop the Reliability Standards in order to address concerns raised in its stakeholderprocess. See NERC November 21, 2007 Request for Extension of Time, DocketNos. RM05-17-000, et. al, at 7. The Commission ultimately granted three requests forextension of time, extending NERC’s deadline by over seven months, so that NERCcould develop the Reliability Standards proposed here.

24 NERC designates the version number of a Reliability Standard as the last digitof the Reliability Standard number. Therefore, version zero Reliability Standards endwith “-0” and version one Reliability Standards end with “-1.”



filing wholly addresses eight of the 24 Reliability Standards that the Commission did not

approve in Order No. 693 because further information was needed.

14. NERC contends that the proposed Reliability Standards will have no undue

negative effect on competition, nor will they unreasonably restrict available transfer

capability on the Bulk-Power System beyond any restriction necessary for reliability and

do not limit use of the Bulk-Power System in an unduly preferential manner. NERC

contends that the increased rigor and transparency introduced in the development of

available transfer capability and available flowgate capability calculations serve to

mitigate the potential for undue advantages of one competitor over another. Under the

proposed Reliability Standards, applicable entities are prohibited from making

transmission capability available on a more conservative basis for commercial purposes

than for either planning for native load or use in actual operations, thereby mitigating the

potential for differing treatment of native load customers and transmission service

customers. NERC states that data exchange, which has been heretofore voluntary, is now

mandatory and it is required that the data be used in the available transfer

capability/available flowgate capability calculations. None of these requirements exist in

the current available transfer capability-related Reliability Standards. NERC contends

that these improvements help the Commission achieve many of the primary objectives of

Order No. 890 regarding transparency, standardization and consistency in available

transfer capability calculations.

15. NERC states that all three methodology Reliability Standards (MOD-028-1,

MOD-029-1, and MOD-030-2) share fundamental equations that, while mathematically



equivalent, are written in slightly different forms. As a result, the manner of determining

the components varies between methodologies. The employment of any two

methodologies, given the same inputs, may produce similar, but not identical, results. As

noted by NERC there are fundamental differences in the proposed methodologies that can

keep them from producing identical results. For example, the rated system path

methodology does not use the same frequent simulations of power flow used by the other

two methodologies. NERC states that the rated system path methodology therefore will

rarely generate numbers that identically match those determined by an entity using the

other two methodologies.

16. NERC proposes to make the MOD Reliability Standards proposed here applicable

to transmission operators and transmission service providers. NERC states that the

drafting team considered applying the Reliability Standards to the transmission operator

instead of the transmission service provider. According to NERC, the Reliability

Standard drafting team believes that the NERC Functional Model supports a

determination that responsibility for several of the requirements lies with the transmission

operator.25 NERC also states that a number of entities argued in the NERC drafting

process that the transmission service provider actually undertakes efforts to meet those

requirements. NERC states that the drafting team believes this points to a delegation of

25 NERC has developed a “Functional Model” that defines the set of functions thatmust be performed to ensure the reliability of the Bulk-Power System. The FunctionalModel identifies 14 functions and the name of a corresponding entity responsible forfulfilling each function. NERC’s functional model can be found athttp://www.nerc.com/page.php?cid=2|247|108.



tasks to a larger entity that is the byproduct of a regional transmission organization and

its regional transmission tariff. Accordingly, NERC states that the MOD Reliability

Standards retain the use of transmission operators in the Reliability Standards, and

explained to entities how delegation or joint registration organizations address the

compliance implications of the assignment.

A. Coordination with Business Practice Standards

17. NERC states that it has worked closely and collaboratively with NAESB,

conducting numerous joint meetings and conference calls, to develop the Reliability

Standards proposed here and related NAESB business-practice standards.26 NERC states

that the focus of the proposed Reliability Standards is to address only the reliability

aspects of available transfer capability and available flowgate capability and not to

address the commercial aspects of available transfer capability, except to the extent that

commercial system availability closely matches actual remaining system capability. The

associated NAESB business practice standards are intended to focus on the competitive

aspects of these processes. Through implementation of these Reliability Standards,

access to the grid may indirectly be restricted, but NERC states that NAESB business

practices and Commission orders related to these Reliability Standards ensure that any

limitation will be applied in a manner that ensures open access and promotes competition.

26 As noted above, the Commission addresses the proposed NAESB businesspractices in a Notice of Proposed Rulemaking issued concurrently in Docket No. RM05-5-013.



18. According to NERC, it and NAESB have coordinated the development of these

business practices and the Reliability Standards to ensure that there are no duplications or

double counting between the business practice standards and the Reliability Standards,

and they will continue to coordinate as necessary so that the available transfer capability-

related Reliability Standards are compatible and consistent.

B. Available Transmission System Capability, MOD-001-1

19. NERC proposes the Available Transmission System Capability Reliability

Standard (MOD-001-1) as part of a set of Reliability Standards which are designed to

work together to support a common reliability goal: to ensure that transmission service

providers maintain awareness of available system capability and future flows on their

own systems as well as those of their neighbors. NERC states that, historically,

differences in implementation of available transfer capability methodologies and a lack of

coordination between transmission service providers have resulted in cases where

available transfer capability has been overestimated. As a result, systems have been

oversold, resulting in potential or actual system operating limits and interconnection

reliability operating limits being exceeded. NERC states that MOD-001-1 is the

foundational Reliability Standard that obliges entities to select a methodology and then

calculate available transfer capability or available flowgate capability using that

methodology, thereby ensuring that the determination of available transfer capability is

accurate and consistent across North America and that the transmission system is neither

oversubscribed nor underutilized.



20. NERC states that, unlike the current set of voluntary available transfer capability

standards, MOD-001-1 requires adherence to a specific documented and transparent

methodology. NERC states that it requires applicable entities to calculate available

transfer capability on a consistent schedule and for specific timeframes. According to

NERC, MOD-001-1 requires users, owners and operators to disclose counterflow

assumptions and outage processing rules to other reliability entities. NERC states that

this Reliability Standard prohibits applicable entities from making transmission capability

available on a more conservative basis for commercial purposes than the system’s

capability in actual operations. NERC’s MOD-001-1 also requires entities, for the first

time, to exchange and use available transfer capability data. NERC states that the

Reliability Standard reflects industry’s consensus best practices for determining available

transfer capability.

21. As proposed, this Reliability Standard includes nine requirements, which would be

applicable to all transmission service providers and transmission operators. To ensure

consistency of enforcement, NERC states that each requirement is supported by a

measure that identifies what is required and how the requirement will be enforced.

22. Under NERC’s proposed Requirement R1, a transmission operator must select one

of three methodologies for calculating available transfer capability or available flowgate

capability for each available transfer capability path for each time frame (hourly, daily or

monthly) for the facilities in its area. As stated above, the three proposed methodologies

are: the area interchange methodology, the rated system path methodology, and the

flowgate methodology.



23. Several proposed requirements within this Reliability Standard address the

calculation of available transfer capability or available flowgate capability. Requirement

R2 requires each transmission service provider to calculate available transfer capability

or available flowgate capability values hourly for the next 48 hours, daily for the next 31

calendar days and monthly for the next 12 months. Requirement R6 requires each

transmission operator in its calculation of total transfer capability or total flowgate

capability to use assumptions no more limiting than those used in its planning of

operations. NERC contends that, consistent with the requirements of Order No. 890 and

related directives of Order No. 693, Requirement R6 will minimize the differences

between total transfer capability and total flowgate capability for transmission and

transfer capability used in native load and reliability assessment studies.27 Similarly,

Requirement R7 requires each transmission service provider, in its calculation of

available transfer capability or available flowgate capability, to use assumptions no more

limiting than those used in its planning of operations. NERC contends that this

requirement addresses the Commission’s directive in Order No. 693 for the ERO to

modify the available transfer capability Reliability Standards to include a requirement

that the assumptions used in available transfer capability and available flowgate

capability calculations be consistent with those used for planning the expansion or

27 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 237; Order No. 693,FERC Stats. & Regs. ¶ 31,242 at P 1051.



operation of the Bulk-Power System to the maximum extent possible.28 Requirement R8

requires each transmission service provider to recalculate available transfer capability at a

certain specified interval (hourly, daily, monthly) unless the input values specified in the

available transfer capability calculation have not changed. NERC contends that

Requirement R8 satisfies the Commission’s directive to calculate available transfer

capability on a consistent time interval.29

24. MOD-001-1 also proposes several record keeping and information sharing

requirements for transmission service providers. Requirement R3 requires each

transmission service provider to keep an available transfer capability implementation

document that explains the implementation of its chosen methodology(ies), its use of

counterflows, the identities of entities with which it exchanges information for

coordination purposes, any capacity allocation processes, and the manner in which it

considers outages. Requirement R4 requires transmission service providers to keep

specific reliability entities advised regarding changes to the available transfer capability

implementation document.30 Requirement R5 requires the transmission service provider

28 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1057; see also OrderNo. 890, FERC Stats. & Regs. ¶ 31,241 at P 292.

29 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 301; Order No. 693,FERC Stats. & Regs. ¶ 31,242 at P 1057.

30 These include: each planning coordinator, reliability coordinator, andtransmission operator associated with the transmission service provider’s area; and eachplanning coordinator, reliability coordinator, and transmission service provider adjacentto the transmission service provider’s area.



to make the available transfer capability implementation document available to those

same reliability entities.31 Finally, proposed Requirement R9 allows a transmission

service provider thirty calendar days to begin to respond to a request from any other

transmission service provider, planning coordinator, reliability coordinator or

transmission operator for certain data to be used in the requestor’s available transfer

capability or available flowgate capability calculations.

25. In Order No. 693, the Commission directed the ERO to develop modifications to

the available transfer capability Reliability Standards to include a requirement that

applicable entities make available assumptions and contingencies underlying available

transfer capability and total transfer capability calculations. NERC contends that this

Reliability Standard addresses this issue by requiring disclosure in the available transfer

capability implementation document under Requirement R3.1 and part of the data

exchange required by Requirement R9. NERC states that it has agreed with NAESB that

requirements for posting information are more appropriately addressed through the

NAESB process. Accordingly, NERC states that NAESB will be addressing the

requirements associated with posting this information, instead of NERC.

31 Although the Reliability Standards only require the transmission serviceprovider to make the available transfer capability implementation document available tocertain reliability entities, the NAESB standard on OASIS posting requirements(Standard 001-13.1.5) requires transmission service providers to provide a link to thedocument on OASIS.



C. Capacity Benefit Margin Methodology, MOD-004-1

26. As proposed, the Capacity Benefit Margin Methodology Reliability Standard

(MOD-004-1) provides for the calculation of capacity benefit margin, which is defined

by NERC as the amount of firm transmission capability preserved by the transmission

service provider for load-serving entities, whose loads are located on that transmission

service provider’s system, to enable access by the load-serving entities to generation from

interconnected systems to meet generation reliability requirements.32 The purpose of this

Reliability Standard is to promote the consistent and reliable calculation, verification,

preservation, and use of capacity benefit margin to support analysis and system

operations. NERC states that preservation of capacity benefit margin for a load-serving

entity allows that entity to reduce its installed generating capacity below that which may

otherwise have been necessary without interconnections to meet its generation reliability

requirements. NERC states that the transmission transfer capability preserved as capacity

benefit margin is intended to be used by the load-serving entities only in times of

emergency generation deficiencies.

27. NERC proposes to apply MOD-004-1 to transmission service providers,

transmission planners, load-serving entities, resource planners and balancing authorities.

As discussed more fully below, NERC states that it does not specify a particular

methodology for calculating capacity benefit margin, but rather improves transparency by

32 See North American Electric Reliability Council, Glossary of Terms Used inReliability Standards, (Effective February 12, 2008), available at:http://www.nerc.com/docs/standards/rs/Glossary_12Feb08.pdf.



requiring adherence to specific documented and transparent methodology to ensure

consistent and reliable calculation, verification, preservation and use of capacity benefit

margin.

28. To improve consistency and transparency in the calculation of capacity benefit

margin, the proposed Reliability Standard imposes twelve requirements on entities

electing to use a capacity benefit margin. Requirement R1 requires the transmission

service provider that maintains capacity benefit margin to prepare and keep current a

capacity benefit margin implementation document that includes at a minimum: (1) the

process through which a load-serving entity within a balancing authority associated with

the transmission service provider, or the resource planner associated with that balancing

authority area, may ensure that its need for transmission capacity to be set aside as

capacity benefit margin will be reviewed and accommodated by the transmission service

provider to the extent transmission capacity is available; (2) the procedure and

assumptions for establishing capacity benefit margin for each available transfer capability

path or flowgate; and (3) the procedure for a load-serving entity or balancing authority to

use transmission capacity set aside as capacity benefit margin, including the manner in

which the transmission service provider will manage situations where the requested use

of capacity benefit margin exceeds the amount of capacity benefit margin available.

29. Requirement R2 requires the transmission service provider to make its current

capacity benefit margin implementation document available to the transmission

operators, transmission service providers, reliability coordinators, transmission planners,

resource planners, and planning coordinators that are within or adjacent to the



transmission service provider’s area, and to the load-serving entities and balancing

authorities within the transmission service providers area, and notify those entities of any

changes to the capacity benefit margin implementation document prior to the effective

date of the change.

30. Requirements R3 and R4 require each load-serving entity and resource planner

determining the need for transmission capacity to be set aside as capacity benefit margin

for imports into a balancing authority to develop that need by using one or more of the

following to determine the generation capability import requirement:33 loss of load

expectation studies, loss of load probability studies, deterministic risk-analysis studies,

and reserve margin or resource adequacy requirements established by other entities, such

as municipalities, state commissions, regional transmission organizations, independent

system operators, regional reliability organizations, or regional entities.

31. Requirement R5 requires the transmission service provider to establish at least

every 13 months a capacity benefit margin value for each available transfer capability

path or flowgate to be used for available transfer capability or available flowgate

capability during the 13 full calendar months (months 2 – 14) following the current

month (the month in which the transmission service provider is establishing the capacity

benefit margin values). Similarly, Requirement R6 requires the transmission planner to

33 NERC defines the generation capability import requirement as the amount ofgeneration capability from external sources identified by a load-serving entity or resourceplanner to meet its generation reliability or resource adequacy requirement as analternative to internal resources.



establish a capacity benefit margin value for each available transfer capability path or

flowgate to be used in planning during each of the full calendar years two through ten

following the current year (the year in which the transmission planner is establishing the

capacity benefit margin values). All values must reflect consideration of each of the

following, if available: (1) any studies performed by load-serving entities or resource

planners pursuant to Requirement R3 for loads within the transmission service provider’s

area; or (2) any reserve margin or resource adequacy requirements for loads within the

transmission service provider’s area established by other entities, such as municipalities,

state commissions, regional transmission organizations, independent system operators,

regional reliability organizations, or regional entities. Once determined, the capacity

benefit margin values will be allocated along available transfer capability paths based on

the expected import paths or source regions provided by load-serving entities or resource

planners. Capacity Benefit Margin values for flowgates will be allocated based on the

expected import paths or source regions provided by load-serving entities or resource

planners and the distribution factors associated with those paths or regions, as determined

by the transmission service provider.

32. Requirements R7 and R8 require the transmission service provider and the

transmission planner to notify, within 31 calendar days after the establishment of capacity

benefit margin, all load-serving entities and resource planners that determined they had a

need for capacity benefit margin of the amount, or the amount planned, of capacity

benefit margin set aside.



33. Requirement R9 requires the transmission service provider that maintains capacity

benefit margin and the transmission planner to provide, subject to confidentiality and

security requirements, copies of the applicable supporting data, including any models,

used for determining capacity benefit margin or allocating capacity benefit margin over

each available transfer capability path or flowgate to each of the associated transmission

operators and to any transmission service provider, reliability coordinator, transmission

planner, resource planner, or planning coordinator within 30 calendar days of their

making a request for the data.

34. Requirement R10 requires the load-serving entity or balancing authority to request

to import energy over firm transfer capability set aside as capacity benefit margin only

when experiencing a declared level 2 or higher NERC energy emergency alert.

35. When reviewing an arranged interchange using capacity benefit margin,

Requirement R11 requires all balancing authorities and transmission service providers to

waive, within the bounds of reliable operation, any real-time timing and ramping

requirements.

36. Requirement R12 requires all transmission service providers maintaining capacity

benefit margin to approve, within the bounds of reliable operation, any arranged

interchange using capacity benefit margin that is submitted by an “energy deficient

entity”34 under an energy emergency alert level 2 if the capacity benefit margin is

34 Energy deficient entities are defined by NERC in the Capacity and EnergyEmergencies Reliability Standard. See EOP-002-2, Attachment 1.



available, the emergency is declared within the balancing authority area of the energy

deficient entity, and the load of the energy deficient entity is located within the

transmission service provider’s area.

37. NERC states that the proposed Reliability Standard complies with the

requirements of Order No. 890 and related directives of Order No. 693 because it sets

standards that allow load-serving entities to request transfer capability to be set aside in

the form of capacity benefit margin in a consistent and transparent manner. Consistent

with the Commission’s direction, the Reliability Standard provides an approach for

determining capacity benefit margin that is flexible and does not mandate a particular

methodology.35 NERC contends that this is appropriate because various parts of the

country have already developed robust methodologies for determining capacity benefit

margin. NERC states that Requirements R3 and R4 allow load-serving entities or

resource planners to perform specific studies to determine their need for capacity benefit

margin. By specifying the types of studies load-serving entities or resource planners

must perform, NERC contends that MOD-004-1 ensures that capacity benefit margin and

transmission reliability margin are not used for the same purpose.36 In response to the

Commission’s transparency requirement,37 NERC states that Requirement R9 ensures

35 Citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1078; see also OrderNo. 890, FERC Stats. & Regs. ¶ 31,241 at P 257.

36 Citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1105.

37 Citing id. P 1077.



that capacity benefit margin studies are made available to the appropriate reliability

entities for their review and analysis. With regard to public disclosure, NERC states that

it has agreed with NAESB that requirements for posting information are more

appropriately addressed through the NAESB process.

38. Requirements R5 and R6 require that the transmission service provider and

transmission planner utilize the information contained in the studies if it has been

provided to them when establishing capacity benefit margin values and mandate the re-

evaluation of capacity benefit margin at least once every thirteen months.38 NERC states

that, consistent with Order Nos. 890 and 693, Requirements R5 and R6 also require

allocation of capacity benefit margin based on the available transfer methodology chosen

under MOD-001-1.39 NERC states that Requirements R10, R11 and R12 specify the

manner in which capacity benefit margin is to be used.40 NERC states that any additional

requirements specified by the transmission service provider must be identified in the

capacity benefit margin implementation document, as mandated in Requirement R1.3.

39. In response to the requirement that capacity benefit margins be verifiable,41 NERC

states that Requirements R5, R6 and R9 ensure that the studies used to establish a need

38 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 358. NERC statesthat it chose thirteen months to ensure enough flexibility for a yearly update withoutbeing so prescriptive as to require it on a specific day.

39 Citing id. at P 257; Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1082.

40 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 256-7.




for capacity benefit margin are made available to any of the reliability entities specified

in Requirement R9 that request them. NERC explains that the Reliability Standard does

not mandate the verification of requested amounts of capacity benefit margin because it

would place a functional entity (either the transmission service provider or transmission

planner) in the position of having to judge the quality of each request, which could create

conflicts of interest or potentially result in liability for that entity. Rather than mandate

any particular approach for validation, NERC states that Requirements R3 and R4

mandate the specific kinds of studies to be performed and supporting information that is

to be maintained when determining the underlying need for capacity benefit margin. To

the extent that entities do not use these methods or maintain this supporting information,

NERC states that they will be in violation of the Reliability Standard.

40. In response to the Commission’s call for clarity in the process for requesting

capacity benefit margin,42 NERC states that Requirement R1.1 requires the transmission

service provider explain the process by which load-serving entities and resource planners

may ensure that their need for transmission capacity to be set aside as capacity benefit

margin is reviewed and accommodated by the transmission service provider to the extent

transmission capacity is available. Requirement R1.3 requires the transmission service

provider to describe the procedure for load-serving entities and resource planners to use

transmission capacity that has been set aside as capacity benefit margin. If the requested

use of capacity benefit margin exceeds the amount of capacity benefit margin available,

42 Id. P 1081.



Requirement R1.3 also requires a description of how the transmission service provider

will manage such situations. In addition, NERC states that Requirements R7 and R8

mandate that the transmission service provider notify load-serving entities and resource

planners that determined they had a need for capacity benefit margin of the amount of

capacity benefit margin set aside, so that they may make informed decisions about how to

proceed if their full request for capacity benefit margin could not be accommodated.

D. Transmission Reliability Margin Methodology, MOD-008-1

41. As proposed, the Transmission Reliability Margin Methodology Reliability

Standard (MOD-008-1) provides for the calculation of transmission reliability margin,

which describes the reliability aspects of determining and maintaining a transmission

reliability margin and the components of uncertainty that may be considered when

making that determination. The purpose of this Reliability Standard is to promote the

consistent and reliable calculation, verification, preservation, and use of transmission

reliability margin to support analysis and system operations. Transmission reliability

margin is transmission transfer capability set aside to mitigate risks to operations, such as

deviations in dispatch, load forecast, outages, and similar such conditions. It is distinctly

different from capacity benefit margin, which is transmission transfer capability set aside

to allow for the import of generation upon the occurrence of a generation capacity

deficiency.

42. NERC proposes to apply MOD-008-1 only to transmission operators that have

elected to keep a transmission reliability margin. As discussed more fully in the

discussion section below, NERC states that the Reliability Standard does not specify one



approach for calculating transmission reliability margin, but rather improves transparency

by providing the key requirements and items that must be contained in any transmission

reliability margin methodology.43

43. To improve the transparency of transmission reliability margin calculations, the

proposed Reliability Standard imposes five requirements on transmission service

providers electing to keep a transmission reliability margin. Requirement R1 provides

that a transmission operator must keep a transmission reliability margin implementation

document that explains how specific risks such as aggregate load forecast uncertainty,

load distribution uncertainty, and forecast uncertainty in transmission system topology44

are accounted for in the transmission reliability margin, how transmission reliability

margin is allocated, and how transmission reliability margin is determined for various

time frames.

44. Requirement R2 allows a transmission operator to account only for the risks

identified in Requirement R1 in transmission reliability margin, and prohibits the

43 NERC August 29, 2008 Filing, Docket No. RM08-19-000 at 38 (NERC Filing).

44 This includes, but is not limited to, forced or unplanned outages andmaintenance outages; allowances for parallel path (loop flow) impacts; allowances forsimultaneous path interactions; variations in generation dispatch (including, but notlimited to, forced or unplanned outages, maintenance outages and location of futuregeneration); short-term system operator response (operating reserve actions); reservesharing requirements; and inertial response and frequency bias.



transmission operator from incorporating risks that are addressed in capacity benefit

margin.45 It allows reserve sharing to be included in transmission reliability margin.

45. Requirement R3 requires each applicable entity to make the transmission

reliability margin implementation document and associated information available to the

following reliability entities if requested: transmission service provider, reliability

coordinator, planning coordinator, transmission planner, and transmission operator.

46. Requirement R4 provides that each applicable transmission operator must

determine the transmission reliability margin value per the methods described in the

transmission reliability margin implementation document at least once every thirteen

months. Finally, Requirement R5 states that each applicable transmission operator must

provide that transmission reliability margin value to its transmission service providers

and transmission planners no more than seven days after it has been determined.

47. NERC states that MOD-008-1 complies with Order No. 890 by specifying the

critical areas of analysis required for transmission reliability margin.46 Further, it states

that it has specified the appropriate uses of transmission reliability margin in

Requirement R1 and prohibited the use of other values and double counting in

Requirement R1. In addition, it maintains that MOD-008-1 complies with Order No. 693

45 The capacity benefit margin Reliability Standard, MOD-004-1, was filed onNovember 21, 2008 in Docket No. RM09-5-000.

46 NERC Filing at 32 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 atP 273).



by imposing clear requirements for making documents supporting the transmission

reliability margin determination available through Requirements R1 and R3.

48. In response to the requirement to expand the applicability of the transmission

reliability margin Reliability Standard to planning authorities and reliability

coordinators,47 NERC states that the drafting team was not able to identify any

requirements for these entities, based on the current drafting of the Reliability Standard.

Therefore, these entities are not included in the proposed Reliability Standard. NERC

states that, until such time as the transmission reliability margin methodology becomes

more detailed, there does not seem to be any measurable action that can be imposed on

the planning coordinator48 or reliability coordinator.

49. In response to the Commission’s statement that it would not require transfer

capability that is set aside as transmission reliability margin to be sold on a non-firm

basis,49 NERC states that it has included this requirement in each of the three

methodologies as a part of firm and non-firm equations. NERC states that, because some

of the uncertainties included in the transmission reliability margin may reduce or be

eliminated as one approaches real time, the non-firm equations allow for the partial


48 The Commission notes that NERC uses the terms planning coordinator andplanning authority interchangeably in its standards, as indicated in the proposed additionsto the glossary of terms, addressed below. The interchangeable use of these terms maylack the clarity generally preferred, but the Commission understands that NERC iscurrently working on modifications to address this issue.

49 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 273.



release of transmission reliability margin. In the Area Interchange Methodology (MOD-

028-1), this is addressed in Requirement R11; in the Rated System Path Methodology

(MOD-029-1), this is addressed in Requirement R8; and in the Flowgate Methodology

(MOD-030-2), this is addressed in Requirement R9.

50. NERC contends that choosing a “best” approach to transmission reliability margin

calculation would require a much more thorough technical effort. NERC therefore

requests that the Commission provide additional guidance on this topic regarding its

priority and a determination whether or not such an effort should be included in NERC’s

annual planning process.

E. Three Methodologies for Calculating Available Transfer Capability

51. In Order No. 890, the Commission did not require a uniform methodology for

calculating available transfer capability. The Commission noted that NERC was

developing Reliability Standards for three available transfer capability calculation

methodologies and concluded that, if all of the available transfer capability components

and certain data inputs and assumptions are consistent, the three available transfer

capability calculation methodologies being developed by NERC will produce predictable

and sufficiently accurate, consistent, equivalent and replicable results.50 Consistent with

Order No. 890, NERC proposes three methodologies for calculating available transfer

capability as detailed in the following Reliability Standards: MOD-028-1, MOD-029-1

and MOD-030-2. NERC contends that these three methodologies meet the requirements

50 Id. P 210.



established by the Commission in Order No. 890, as well as those established in Order

No. 693.

52. NERC asserts that the three methodologies are a significant improvement over the

existing available transfer capability related requirements. While current MOD-001-0 is

essentially a “fill-in-the-blank” Reliability Standard,51 the proposed methodologies

replace the original fill-in-the blank standard by specifying in detail how total transfer

capability is to be determined – from modeling requirements, to the simulation of

dispatch to determine native load impacts, to the treatment of reservations and to the

incorporation of neighboring data. According to NERC, MOD-001-1 specifies how

existing transmission commitments and available transfer capability are to be determined

in detail and clearly describes the treatment of capacity benefit margin and transmission

reliability margin in the available transfer capability equations. Thus, NERC contends,

these Reliability Standards reduce the potential for seams discrepancies and improve the

wide-area understanding of the Bulk-Power System on a forward-looking basis. NERC

states that, by promoting consistency, standardization and transparency, they directly

support and improve the reliability of the Bulk-Power System and help achieve the

Commission’s objectives stated in Order No. 890.

51 A fill-in-the-blank Reliability Standard requires the regional entities to developcriteria for use by users, owners or operators within each region. In Order No. 693, theCommission held 24 Reliability Standards (mainly fill-in-the-blank standards) as pendinguntil further information was provided on each standard and requires users, owners andoperators to follow these pending standards as “good utility practice” pending theirapproval by the Commission.



1. Area Interchange Methodology, MOD-028-1

53. NERC states that the area interchange methodology is characterized by

determination of incremental transfer capability via simulation, from which total transfer

capability can be mathematically derived. Capacity benefit margin, transmission

reliability margin, and existing transmission commitments are subtracted from the total

transfer capability, and postbacks and counterflows are added, to derive available transfer

capability. NERC also states that, under the area interchange methodology, total transfer

capability results are generally reported on an area to area basis.

54. MOD-028-1 describes the area interchange methodology (previously referred to as

the network response available transfer capability methodology) for determining

available transfer capability. NERC intends to use the Area Interchange Methodology

Reliability Standard to increase consistency and reliability in the development and

documentation of transfer capability calculation for short-term use performed by entities

using the area interchange methodology to support analysis and system operations.

55. This Reliability Standard would apply only to transmission operators and

transmission service providers that have elected to implement this particular methodology

as part of their compliance with MOD-001-1, Requirement R1. The proposed Reliability

Standard consists of eleven requirements. Requirement R1 provides the additional

information that a transmission service provider using the area interchange methodology

must include in its available transfer capability implementation document. This includes

information describing how the selected methodology has been implemented, in such

detail that, given the same information used by the transmission operator, the results of



the total transfer capability calculations can be validated; a description of the manner in

which the transmission operator will account for interchange schedules in the calculation

of total transfer capability; any contractual obligations for allocation of total transfer

capability; a description of the manner in which contingencies are identified for use in the

total transfer capability process; and information on how sources and sinks for

transmission service are accounted for in available transfer capability calculations.

56. Pursuant to Requirement R2, each transmission operator must calculate total

transfer capability using a model that meets the scope specified in the requirement and

includes rating information specified by generator owners and transmission owners

whose equipment is represented in the model.

57. Requirement R3 details the information the transmission operator must include in

its determination of total transfer capability for the on-peak and off-peak intra-day and

next day time periods, as well as days two through 31 and for months two through 13.52

Requirement R4 requires each transmission operator to determine total transfer capability

while modeling contingencies and reservations consistently, and respect any contractual

allocations of total transfer capability.

58. Requirement R5 provides that each transmission operator must determine total

transfer capability on a periodic basis (as specified in the requirement) or upon certain

operating conditions significantly affecting bulk electric system topology.

52 This information includes: expected generation and transmission outages,additions, and retirements; load forecasts; and unit commitment and dispatch order.



59. Requirement R6 provides the detailed process by which each transmission

operator must establish total transfer capability, which must be provided to the

transmission service provider within the time frames specified in Requirement R7.

60. Requirements R8 through R11 specify the formulas and detailed specifications of

the variables for calculating firm and non-firm existing transmission commitments and

firm and non-firm available transfer capability.

2. Rated System Path Methodology, MOD-029-1

61. NERC states that the rated system path methodology is characterized by an initial

total transfer capability, determined via simulation. As with the area interchange

methodology, capacity benefit margin, transmission reliability margin, and existing

transmission commitments are subtracted from the total transfer capability, and postbacks

and counterflows are added, to derive available transfer capability. NERC also states

that, under the rated system path methodology, total transfer capability results are

generally reported as specific transmission path capabilities.

62. MOD-029-1 describes the rated system path methodology for determining

available transfer capability. NERC intends to use this Reliability Standard to increase

consistency and reliability in the development and documentation of transfer capability

calculations for short-term use performed by entities using the rated system path

methodology to support analysis and system operations.


transmission service providers that have elected to implement rated system path

methodology as part of their compliance with MOD-001-1 Requirement R1. To



implement this calculation, this Reliability Standard consists of eight requirements.

Under Requirement R1, a transmission operator must calculate total transfer capability

using a model that meets the scope and criteria specified in the requirement.

Requirement R2 lists a detailed process by which the transmission operator must

establish total transfer capability. Pursuant to Requirement R3, the transmission operator

must establish total transfer capability as the lesser of the system operating limit or the

value determined in Requirement R2. The transmission operator must then provide a

transmission service provider with the appropriate total transfer capability values and

study report within seven days of finalization of the study report required in Requirement

R4.

64. Requirements R5 through R8 provide that each applicable transmission service

provider must calculate firm and non-firm existing transmission commitments and firm

and non-firm available transfer capability using a specified formula and detailed

specification of the variables.

3. Flowgate Methodology, MOD-030-2

65. NERC states that the flowgate methodology is characterized by identification of

key facilities as flowgates. Total flowgate capabilities are determined based on facility

ratings and voltage and stability limits. The impacts of existing transmission

commitments are determined by simulation. To determine the available flowgate

commitments, the transmission service provider or operator must subtract the impacts of

existing transmission commitments, capacity benefit margin, and transmission reliability



margin, and add the impacts of postbacks and counterflows. Available flowgate

capability can be used to determine available transfer capability.

66. MOD-030-2 describes the flowgate methodology (previously referred to as the

flowgate network response available transfer capability methodology) for determining

available transfer capability. NERC states that the purpose of the Flowgate Methodology

Reliability Standard is to increase consistency and reliability in the development and

documentation of transfer capability calculations for short-term use performed by entities

using the flowgate methodology to support analysis and system operations.


transmission service providers that have elected to implement this particular methodology

as part of their compliance with MOD-001-2. As proposed, the Flowgate Methodology

consists of eleven requirements. Requirement R1 states that a transmission service

provider implementing this methodology must include the following information in its

available transfer capability implementation document in addition to that already required

in the Available Transmission System Capability Reliability Standard (MOD-001-1): the

criteria used by the transmission operator to identify sets of transmission facilities as

flowgates that are to be considered in available flowgate capability calculations, and

information on how sources and sinks for transmission service are accounted for in

available flowgate capability calculations.

68. Under Requirement R2, each applicable transmission operator must determine and

manage the flowgates used in the methodology based on the criteria listed in the

requirement, establish its total flowgate capability based on the criteria listed in the



requirement, and provide total flowgate capability to the transmission service provider

within seven days of their determination.53 To achieve consistency in each component of

the available transfer capability calculation, the Commission, in Order No. 890, directed

public utilities, working through NERC, to develop an available flowgate capability

definition and requirements used to identify a particular set of transmission facilities in a

flowgate.54 As part of the development of the Flowgate Methodology, NERC states that

the Reliability Standard drafting team developed a definition of available flowgate

capability. In addition, NERC states that Requirement R2 of this Reliability Standard

contains a list of minimum characteristics that are to be used to identify a particular set of

transmission facilities as a flowgate.

69. Requirement R3 requires the transmission operator to provide the transmission

service provider with a transmission model that meets a specified criteria and

Requirement R4 provides that the transmission service provider must evaluate

reservations consistently when determining available flowgate capability. When

53 MOD-030-2 is identical to MOD-030-1 except for certain modifications toRequirements R2 and R11. First, NERC added new sub-requirements R2.1.1.3 andR2.1.2.3. to clarify that, if any limiting element is kept within its limit for its associatedworst contingency by operating within the limits of another flowgate, then no newflowgate needs to be established for such limiting elements or contingencies. Second,NERC modified sub-requirement R2.1.3. to state that the list of flowgates does not needto include any flowgates created to address temporary operating conditions. Finally,NERC modified Requirement R11 to eliminate the obligation to convert total flowgatecapability to total transfer capability. The Commission notes that the modification toRequirement R11 does not alter the posting requirements of 18 CFR 37.6(b)(3).




determining available flowgate capability, Requirement R5 provides that each

transmission service provider must use the models given to it as described in

Requirement R3, include appropriate outages, and use the available flowgate capability

on external flowgates as provided by the transmission service provider calculating

available flowgate capability for those flowgates.

70. Requirements R6 and R7 require each transmission service provider to calculate

the impact of firm and non-firm existing transmission commitments using a specified

process. The transmission service provider must calculate firm and non-firm available

flowgate capability using the formula and detailed specification of the variables found in

Requirements R8 and R9.

71. Under Requirement R10, each transmission service provider shall recalculate

available flowgate capability at a certain specified interval (hourly once per hour, daily

once per day, monthly once per week) unless the input values specified in the available

flowgate capability calculation have not changed. NERC contends that this requirement

satisfies the requirement in Order No. 890 and Order No. 693 that transmission service

providers recalculate available transfer capability on a consistent time interval. Finally,

Requirement R11 provides the formula and variables that a transmission service provider

must use if it desires to convert available flowgate capability to available transfer

capability.55

55 Requirement R11 of MOD-030-1 would have directed transmission serviceproviders to use the same formula to convert total flowgate capability to total transfercapability. The formula provided in Requirement R11 of MOD-030-2 eliminates this

(continued…)



F. Implementation Plan

72. NERC proposes that the Available Transmission System Capability Reliability

Standard and the three methodology Reliability Standards become effective the first day

of the first quarter no sooner than one calendar year after approval of all of these four

Reliability Standards by all appropriate regulatory authorities where approval is required

or is otherwise effective in those jurisdictions where approval is not explicitly required.

According to NERC, since the three methodology Reliability Standards require

information from neighboring reliability entities for use in the development of its

available transfer capability and available flowgate capability values that is compulsory

under Requirement R9 of the Available Transmission System Capability Reliability

Standard (MOD-001-1), none of the methodology Reliability Standards can be

effectively implemented unless and until that Reliability Standard has been implemented

by all entities in all jurisdictions.

73. NERC states that, although some entities may already be implementing the

requirements in the Reliability Standards, many others are not, especially with regard to

the data exchange requirements listed in Requirement R9 of MOD-001-1. Accordingly,

software changes, associated testing, and possible tariff filings will be required to comply

with the proposed Reliability Standards. Therefore, NERC maintains that a minimum of

one year from regulatory approval should be allowed for entities to comply.

obligation. As noted above, this modification does not alter the posting requirements of18 CFR 37.6(b)(3).



74. NERC proposes that each of the Capacity Benefit Margin (MOD-004-1) and

Transmission Reliability Margin (MOD-008-1) Reliability Standards require compliance

on the first day of the first quarter no sooner than one calendar year after approval of the

Reliability Standard by appropriate regulatory authorities where approval is required or,

where approval is not explicitly required, when the Reliability Standard is otherwise

effective. According to NERC, unlike the other four proposed Reliability Standards

included in this filing, the Transmission Reliability Margin Reliability Standard replaces

the existing Reliability Standard MOD-008-0 and the Capacity Benefit Margin Reliability

Standard replaces MOD-004-0. As such, they do not require coordinated

implementation, as entities may rely on the previous version of the Reliability Standards

if any delay in implementing the Reliability Standards occurs. NERC states that,

although many entities already use transmission reliability margin and capacity benefit

margin, compliance with these Reliability Standards may require software changes,

software regression testing, and possible tariff changes. To accommodate these needs,

NERC believes a one-year implementation period is appropriate.

III. Discussion

75. The Commission proposes to approve the revised MOD Reliability Standards and

related additions to the glossary of terms, to be effective as proposed by NERC, as just,

reasonable, not unduly discriminatory or preferential, and in the public interest. These

Reliability Standards represent a step forward in eliminating the broad discretion

previously afforded transmission service providers in the calculation of available transfer

capability. As the Commission explained in Order No. 890, excessive discretion in the



calculation of available transfer capability gives transmission service providers the

opportunity to discriminate in subtle ways in the provision of open access transmission

service.56 On systems where transmission capacity is constrained, a lack of transparency

and consistency in the calculation of available transfer capability has led to recurring

disputes over whether transmission service providers have performed those calculations

in a way that discriminates against competitors.

76. The Commission acted in Order No. 890 to limit this remaining opportunity for

discrimination by directing public utilities, working through NERC, to develop

Reliability Standards to govern the consistent and transparent calculation of available

transfer capability by transmission service providers. In Order No. 693, the Commission

implemented that directive by requiring NERC to prospectively modify the MOD

Reliability Standards it filed in April 2006 to address the requirements of Order No. 890.

The proposed Reliability Standards satisfy these requirements by enhancing transparency

and consistency in the calculation of available transfer capability, mandating that

transmission service providers and transmission operators perform their calculations in

accordance with methodologies that are both explicitly documented and available to

reliability entities who request them. The proposed Reliability Standards also require

documentation of the detailed representations of the various components that comprise

the available transfer capability equation, and require transmission service providers and

transmission operators to specify modeling and risk assumptions and disclosure of outage




processing rules to other reliability entities. These actions will make the processes to

calculate available transfer capability and its various components more transparent

which, in turn, will allow the Commission and others to ensure that those calculations are

performed consistently.

77. Although the Commission believes that the proposed Reliability Standards

generally comply with the requirements of Order No. 890 and related directives of Order

No. 693, the Commission is concerned that the implementation documents used by each

transmission service provider to implement the Reliability Standards could provide

continuing opportunities to discriminate in the provision of transmission service. As

discussed in further detail below, the Commission proposes to direct the ERO to perform

an audit of the implementation documents to determine if they provide sufficient

transparency to enable the Commission and others to replicate and verify each

transmission service provider’s calculations. Without adequate transparency, it will be

impossible for the Commission to ensure that transmission service providers are

consistently performing their available transfer capability calculations when responding

to requests for transmission service. Ensuring adequate transparency also will enable the

Commission and others to verify that data and modeling assumptions used to calculate

available transfer capability are being used consistently during relevant timeframes, such

as in the calculation of short-term available transfer capability and the planning of

operations, as required by the proposed Reliability Standards.57

57 MOD-001-1, Requirements R6 and R7.



78. The Commission also has concern regarding several of the substantive

requirements of the proposed Reliability Standards. To address these concerns, the

Commission proposes to direct the ERO to develop modifications to the Reliability

Standards to address the discrete issues involving: the availability of each transmission

service provider’s implementation documents; the consistent treatment of assumptions in

the calculation of available transfer capability; the calculation, allocation, and use of

capacity benefit margin; the calculation of total transfer capability under the Rated

System Path Methodology; and, the treatment of network resource designations in the

calculation of available transfer capability.

79. Finally, we note that the Commission in this proceeding addresses only those

revisions to the Reliability Standards filed to comply with the available transfer

capability-related requirements of Order No. 890, as implemented by Order No. 693. In

Order No. 693, the Commission also directed the ERO to develop modifications to a

number of other Reliability Standards. The Commission expects the ERO to comply in a

timely and complete manner with those directives, to the extent it has not already done

so.

A. Implementation of the Reliability Standards

80. The Available Transmission System Capability Reliability Standard (MOD-001-1)

serves as an “umbrella” Reliability Standard that requires each applicable entity to select

and implement one or more of the three available transfer capability methodologies found

in MOD-028-1, MOD-029-1, or MOD-030-2. MOD-004-1 and MOD-008-1 provide for

the calculation of capacity benefit margin and transmission reliability margin, which are



inputs into the available transfer capability calculation. Together, these Reliability

Standards require transmission service providers and transmission operators to prepare

and keep current implementation documents that contain certain information specified in

the Reliability Standards. The available transfer capability implementation documents

must describe the available transfer capability methodology in such detail that the results

of their calculations can be validated when given the same information used by the

transmission service provider or transmission operator.58

81. The Commission is concerned that the proposed Reliability Standards could be

implemented by a particular transmission service provider or transmission operator in a

way that enables them to retain the ability to unduly discriminate in the provision of open

access transmission service. Although the Reliability Standards require transmission

service providers to include certain minimum information in each of the implementation

documents, transmission service providers are also permitted to include additional,

undefined parameters and assumptions in those documents. This could include criteria

that are themselves not sufficiently transparent to allow the Commission and others to

determine whether they have been consistently applied by the transmission service

provider in particular circumstances. This discretion appears in the three available

transfer capability methodologies (MOD-028-1, MOD029-1, and MOD-030-2), as well

as the Reliability Standards governing the calculation of capacity benefit margin (MOD-

004-1) and transmission reliability margin (MOD-008-1).

58 MOD-001-1, Requirement R3.



82. It is appropriate for transmission service providers to retain some level of

discretion in the calculation of available transfer capability. Requiring absolute

uniformity in criteria and assumptions across all transmission service providers would

preclude transmission service providers from calculating available transfer capability in a

way that accommodates the operation of their particular systems. The Reliability

Standards need not be so specific that they address every unique system difference or

differences in risk assumptions when modeling expected flows. Each transmission

service provider should retain some discretion to reflect unique system conditions or

modeling assumptions in its available transmission capability methodology.59 Any such

system conditions or modeling assumptions, however, must be made sufficiently

transparent and be implemented consistently for all transmission customers.

83. In order to ensure that this occurs, the Commission proposes to direct the ERO to

conduct an audit of the various implementation documents developed by transmission

service providers to confirm that the complete available transfer capability methodologies

reflected therein, including the calculation of each component of available transfer

capability, are sufficiently transparent to allow the Commission and others to replicate

and verify those calculations and thereby ensure that they are being implemented

consistently for all transmission customers. This audit would review the additional

parameters and assumptions included by transmission service providers in their

implementation documents as of the date the Reliability Standards become effective,

59 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 51.



analyzing all parameters and assumptions to determine if they are detailed enough to

enable replication and verification of calculations. Upon review of this analysis, the

Commission may direct the ERO to develop a modification to one or more of the

Reliability Standards to address any lack of transparency that may exist in the calculation

of available transfer capability and each of its components.

84. The Commission proposes to direct the ERO to complete this audit no later than

180 days after the effective date of the Reliability Standards, as approved by a final rule

in this docket.60 The Commission also proposes to direct NERC to submit a timeline for

the completion of this audit within 30 days of the issuance of the final rule in this docket.

The Commission discusses below the specific issues to be analyzed by NERC in its audit.

85. Before turning to those issues, the Commission reiterates that our intent is not to

require the development of a single, uniform methodology for calculating available

transfer capability or its components. In Order No. 890, the Commission found that the

potential for discrimination does not lie primarily in the choice of an available transfer

capability calculation methodology, but rather in the consistent application of its

components.61 The Commission acknowledged that NERC was developing standards for

three available transfer capability calculation methodologies. The Commission

concluded that, if all of the available transfer capability components and certain data

60 The audit should be prepared and submitted by NERC staff (or any consultantsit may choose to employ), rather than the drafting teams that developed the proposedReliability Standards.




inputs and assumptions are consistent, the three available transfer capability calculation

methodologies being developed by NERC would produce predictable and sufficiently

accurate, consistent, equivalent and replicable results.62

86. As the Commission explains in Order No. 890-C, issued concurrently with this

order, this does not mean that the results of available transfer capability calculations on

either side of an interface must be identical in every instance. There are fundamental

differences in the three available transfer capability methodologies set forth in the

proposed Reliability Standards that may keep them from producing identical results.

Even where the same methodology is used by transmission service providers on either

side of an interface, unique system differences or differences in risk assumptions can lead

to variations in available transfer capability values. The central goal of the available

transfer capability reforms adopted in Order No. 890 was to limit remaining opportunities

for discrimination by requiring each transmission service provider’s available capability

transfer methodology to be sufficiently transparent to allow for independent validation

that it has been consistently applied. Subject to confirmation by NERC through its audit,

the Commission believes that the Reliability Standards will provide the necessary level of

transparency and, therefore, the results of available transfer capability calculations will be

sufficiently accurate, consistent, equivalent and replicable.

62 Id. P 210.



1. Available Transfer Capability Implementation Documents

87. First, the Commission proposes to direct the ERO to study whether each available

transfer capability implementation document developed by each transmission service

provider under the Reliability Standards contains a level of specificity sufficient to allow

the Commission and others to replicate and verify calculations of available transfer

capability and available flowgate capability. Although MOD-028-1, MOD-029-1, and

MOD-030-2 each improves transparency and consistency by requiring transmission

service providers to use certain specified data and variables in their calculations, they also

allow transmission service providers to use additional parameters and assumptions as

long as they are specified in their implementation documents. Other than their inclusion

in the available transfer capability implementation document, there do not appear to be

any appreciable factors limiting a transmission service provider’s discretion to use

particular parameters and assumptions.

88. For example, in the Area Interchange Methodology (MOD-028-1), Requirement

R3.1 establishes variables to be used when calculating on-peak and off-peak intra-day

and next-day total transfer capabilities. The requirement also allows transmission

operators to use “any other values and additional parameters as specified in the [available

transfer capability implementation document].”63 The requirement does not provide any

further limitation on the other values and additional parameters. Thus, although the

requirement promotes transparency and consistency, it could allow an entity to adopt

63 MOD-028-1, Requirement R3.1.



values and parameters that are not sufficiently transparent to ensure that the transmission

service provider is not discriminating in the provision of transmission service through its

calculation of available transfer capability.

89. Similarly, Requirement R1 of the Rated System Path Methodology (MOD-029-1)

requires a transmission operator, when calculating total transfer capabilities for available

transfer capability, to use a transmission model that meets the criteria set forth in the sub-

requirements. Requirement R1.1.9 allows a transmission operator to use a model that

“models series compensation for each line at the expected operating level unless specified

otherwise in the [available transfer capability implementation document].”64

Requirement R1.1.10 allows a transmission operator to use a model that “includes any

other modeling requirements or criteria specified in the [available transfer capability

implementation document].”65

90. The same unrestrained discretion is found in the Flowgate Methodology (MOD-

030-2). Requirement R2.1 requires transmission operators to include flowgates used in

the available flowgate capability based, at a minimum, on specified criteria. This criteria

includes, at Requirement R2.1.3, any limiting element/contingency combination at least

within the transmission model identified in Requirement R3.466 and R3.567 that has been

64 MOD-029-1, Requirement R1.1.9.

65 MOD-029-1, Requirement R1.1.10.

66 Requirement R3.4 requires the transmission operator to make available to thetransmission service provider a transmission model to determine available flowgatecapability that contains modeling data and system topology for the facilities within its

(continued…)



subjected to an interconnection-wide congestion management procedure within the last

12 months, unless the limiting element/contingency combination is accounted for using

another available transmission capability methodology. Requirement R2.1.4 allows

transmission operators to consider any limiting element/contingency combination within

the transmission model that has been requested to be included by any other transmission

service provider using the flowgate methodology or area interchange methodology under

certain circumstances.

91. In Order No. 890, the Commission expressed particular concern regarding

consistency in the use of counterflow assumptions in short-term and long-term

calculations of available transfer capability.68 The Reliability Standards achieve

consistency by requiring each transmission service provider to identify in its available

transfer capability implementation document how it accounts for counterflows and to

calculate available transfer capability using assumptions no more limiting than those used

in the planning of operations for the corresponding time period.69 However, the

reliability coordinator’s area. Equivalent representation of radial lines and facilities161kv or below is allowed.

67 Requirement R3.5 requires the transmission operator to make available to thetransmission service provider a transmission model to determine available flowgatecapability that contains modeling data and system topology (or equivalent representation)for immediately adjacent and beyond reliability coordination areas.

68 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 292-93; Order 693, FERCStats. & Regs. ¶ 31,242 at P 1039.

69 MOD-001-1, Requirements R3.2, R7. NERC states in its filing that additionalguidance from the Commission would be necessary in order to specify in greater detail a

(continued…)



Reliability Standards again place no limit on the parameters the transmission service

provider can use to account for counterflows. Under MOD-028-1, MOD-029-1, and

MOD-030-2, transmission service providers are permitted to make adjustments to

available transfer capability or available flowgate capability to reflect counterflows so

long as such adjustments are allowed under the counterflow methodology identified in

the available transfer capability implementation document.70

92. The Commission also expressed concern in Order No. 890 regarding the treatment

of reservations with the same point of receipt (generator), but multiple points of delivery

(load), in setting aside existing transmission capacity.71 The Commission found that such

reservations should not be modeled in the existing transmission commitments calculation

simultaneously if their combined reserved transmission capacity exceeds the generator’s

nameplate capacity at the point of receipt. The Commission required the development of

single “best” approach for treating counterflows. See NERC Filing at 101. TheCommission did not require the development of a single approach for the treatment ofcounterflows. Rather, the Commission required the development of Reliability Standardsthat result in the use of counterflow assumptions for short-term and long-term availabletransfer capability calculations that are consistent with those used for the planning ofoperations and system expansion. See Order No. 890, FERC Stats. & Regs. ¶ 31,241 atP 292-93; Order 693, FERC Stats. & Regs. ¶ 31,242 at P 1039. The proposed ReliabilityStandards adequately address that requirement by directing each transmission serviceprovider to identify in its implementation document how it will address counterflows inits calculation of available transfer capability and available flowgate capacity.

70 MOD-028-1, Requirement R10; MOD-029-1, Requirement R7; MOD-030-2,Requirement R8.

71 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 245; Order 693, FERC Stats.& Regs. ¶ 31,242 at P 1033.



Reliability Standards that lay out clear instructions on how these reservations should be

accounted for by the transmission service provider. The proposed Reliability Standards

achieve this by requiring transmission service providers to identify in their

implementation documents how they have implemented MOD-028-1, MOD-029-1, or

MOD-030-2, including the calculation of existing transmission commitments.72

However, the Reliability Standards again place no limits on the parameters that each

transmission service provider can use.

93. The proposed Reliability Standards thus provide each transmission service

provider with substantial discretion when implementing various aspects of its available

transfer capability methodology. The Commission recognizes that there are aspects of

calculations that require the use of parameters and assumptions tailored to the particular

needs of a transmission service provider. In certain instances, however, this discretion

could be used by a transmission service provider to include criteria that allow for

discrimination in the provision of transmission service through inconsistent calculation of

available transfer capability. For example, the use of parameters, modeling requirements,

72 MOD-001-1, Requirement R3.1. In its filing, NERC discusses several optionsshould the Commission desire to impose a uniform approach regarding the treatment ofreservations with the same point of receipt, but multiple points of delivery. See NERCFiling at 90-92. Neither Order No. 890 nor Order No. 693 directed that a single approachbe adopted to account for such reservations and, instead, required only that instructionson how these reservations are accounted for by the transmission service provider beclearly laid out. See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 245; Order 693,FERC Stats. & Regs. ¶ 31,242 at P 1033. The obligation of each transmission serviceprovider to identify in its implementation document how they have implemented MOD-028-1, MOD-029-1, or MOD-030-2, including the calculation of existing transmissioncapacity, satisfies this requirement.



criteria, or assumptions that are undefined or “black box” in nature would provide the

transmission service provider with the opportunity and ability to vary its calculations

depending on the customer seeking service. Such discretion undermines the ability of the

Commission and others to replicate and verify the results of a transmission service

provider’s calculations.

94. In order to ensure that remaining opportunities for undue discrimination are

identified and eliminated, the Commission proposes to direct the ERO to conduct a

review of the additional parameters and assumptions included by each transmission

service provider in its available transfer capability implementation document as of the

date the Reliability Standards become effective. Based on its review, NERC would

identify in the audit required above those instances in which parameters and assumptions

are not sufficiently specific or transparent to allow the Commission and others to

replicate and verify the results of the transmission service provider’s calculation of

available transfer capability or available flowgate capacity. Upon review of NERC’s

analysis, the Commission may direct the ERO to develop a modification to MOD-001-1

to address any lack of transparency. The Commission seeks comment whether additional

requirements should be directed in this proceeding to ensure that the discretion provided

under the available transfer capability implementation documents cannot be used to

unduly discriminate in the provision of transmission service.

2. Capacity Benefit Margin Implementation Documents

95. Second, the Commission proposes to direct the ERO to study whether the capacity

benefit margin implementation documents developed by transmission service providers



under MOD-004-1 contain a level of specificity sufficient to allow the Commission and

others to replicate and verify the calculation, allocation, and use of capacity benefit

margin by transmission service providers. As explained above, capacity benefit margin is

the amount of firm transmission capability preserved by the transmission service provider

for load-serving entities, whose loads are located on that transmission service provider’s

system, to enable access by the load-serving entities to generation from interconnected

systems to meet generation reliability requirements. As NERC explained in its filing,

various entities have already developed methodologies for determining capacity benefit

margin. Accordingly, NERC proposed a Reliability Standard that allows transmission

service providers flexibility in choosing an appropriate methodology for calculating,

allocating and using capacity benefit margins. Although MOD-004-1 specifies core

elements that should be consistent among all methodologies, the transmission service

provider has discretion to use any methodology to calculate, allocate, and use capacity

benefit margins, provided that it is identified and described in the implementation

document.

96. For example, Requirements R5.1 and R6.1 of MOD-004-1 require the

transmission service provider to establish capacity benefit margin values for each path

and flowgate reflecting consideration of studies provided by load-serving entities and

resource planners demonstrating a need for capacity benefit margin and applicable

reserve margin or resource adequacy requirements. Although Requirement R1.2 requires

the transmission service provider to identify in its capacity benefit margin

implementation document the procedures and assumptions for establishing these path and



flowgate values, the Reliability Standard places no limitations or parameters on those

procedures or assumptions. As with MOD-001-1, MOD-004-1 would permit the

transmission service provider to adopt procedures and assumptions that are not

sufficiently transparent to ensure that the transmission provider is similarly treating

similarly-situated customers. The Commission is therefore concerned that the Reliability

Standard could be implemented by a transmission service provider in a way that allows

for undue discretion in the provision of transmission service.



review of the procedures and assumptions included by each transmission service provider

in its capacity benefit margin implementation document as of the date the Reliability

Standards become effective. Based on its review, NERC would identify in the audit

required above those instances in which additional procedures and assumptions are not

sufficiently specific or transparent to allow the Commission and others to replicate and

verify the calculation, allocation and use of capacity benefit margin by the transmission

service provider.73 Upon review of NERC’s analysis, the Commission may direct the

73 The scope of this audit should not include review of the studies supportingrequests for capacity benefit margin. The Commission agrees with NERC that it wouldbe inappropriate to place a functional entity, such as the transmission service provider, inthe position of having to judge the quality of a study supporting a customer’s request forcapacity benefit margin. Requirements R3 and R4 of MOD-004-1 identify the specifickinds of studies that must be performed and supporting information that is to bemaintained when determining a need for capacity benefit margin. Compliance with theserequirements can be audited by NERC and the regional entities in the normal course of

(continued…)



ERO to develop a modification to MOD-004-1 to address any lack of transparency. The

Commission seeks comment whether additional requirements should be directed in this

proceeding to ensure that the discretion provided under the capacity benefit margin

implementation documents cannot be used to unduly discriminate in the provision of

transmission service.

3. Transmission Reliability Margin Implementation Documents

98. Finally, the Commission proposes to direct the ERO to study whether the

transmission reliability margin implementation documents developed by each

transmission operator under the Reliability Standards contain a level of specificity

sufficient to allow the Commission and others to replicate and verify the calculation and

use of transmission reliability margin. Transmission reliability margin is transmission

transfer capability set aside to mitigate risks to operations, such as deviations in dispatch,

load forecast, outages, and similar such conditions. As NERC explains in its filing,

transmission reliability margin is a subjective quantity as it is almost entirely based on the

principles of risk management and risk tolerance, which vary from entity to entity.74

Therefore, although MOD-008-1 identifies the particular categories of uncertainty that

transmission operators may consider when establishing transmission reliability margin,

the transmission operator is permitted to use any methodology to calculate, allocate, and

their compliance review. See Guidance Order on Compliance Audits Conducted by theElectric Reliability Organization and Regional Entities, 126 FERC ¶ 61,038 (2009).

74 NERC Filing at 97.



use transmission reliability margins, provided that it is identified and described in the

implementation document.

99. NERC states in its filing that guidance from the Commission would be necessary

in order to specify in greater detail a single “best” methodology to govern the calculation

of a maximum transmission reliability margin.75 The Commission does not believe that it

is necessary to establish a single methodology for calculating, allocating and using

transmission reliability margin. In Order Nos. 890 and 693, the Commission directed

NERC to clarify how transmission reliability margin should be calculated and allocated

across paths or flowgates and how to establish an appropriate maximum transmission

reliability margin.76 The Commission directed NERC to specify the parameters for

entities to use in determining uncertainties for which transmission reliability margin can

be set aside and used. The Commission also directed the ERO to modify its Reliability

Standards to prevent the use of capacity benefit margin and transmission reserve margin

for the same purposes (i.e. double counting). The proposed Reliability Standard

accomplishes these directives by requiring each transmission operator to identify in its

transmission reliability margin implementation document the components that will be

used to calculate transmission reliability margin, how those components will be used, and

how resulting transmission reliability margin values will be allocated across paths or

75 Id.

76 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 275; Order No. 693, FERCStats. & Regs. ¶ 31,242 at P 1122-23, 1126.



flowgates.77 This level of detail satisfies the requirements of Order No. 890 and related

directives of Order No. 693 by making each transmission operator’s transmission

reliability margin methodologies transparent.

100. However, as with MOD-001-1 and MOD-004-1, the Commission is concerned

that MOD-008-1 could be implemented by a transmission operator in a way that allows

for undue discrimination in the provision of transmission service. For example,

Requirements R1.1 and R1.2 of MOD-008-1 require each transmission operator to

include in its transmission reliability margin implementation document the components

of uncertainty used in establishing a transmission reliability margin, a description of how

those components are used in the calculation of transmission reliability margin, and a

description of how transmission reliability margin is allocated across paths or flowgates.

The transmission reliability margin implementation document developed by transmission

operators could include parameters, modeling requirements, criteria or assumptions that

are insufficiently transparent, providing the transmission operator the opportunity and

ability to vary its calculations depending on the customer requesting transmission service.



review of the procedures identified in each transmission operator’s transmission reserve

margin implementation document as of the date the Reliability Standards become

effective. Based on its review, NERC would identify in the audit required above those

77 MOD-008-1, Requirement R1.



instances in which procedures, criteria, or assumptions are not sufficiently specific or

transparent to allow the Commission and others to replicate and verify the results of the

transmission operator’s calculation of transmission reserve margin. Upon review of

NERC’s analysis, the Commission may direct the ERO to develop a modification to

MOD-008-1 to address any lack of transparency. The Commission seeks comment

whether additional requirements should be directed in this proceeding to ensure that the

discretion provided under the transmission reserve margin implementation documents

cannot be used to unduly discriminate in the provision of transmission service.

B. Proposed Modifications of the Reliability Standards

102. While the Commission generally proposes to approve the Reliability Standards as

in compliance with Order No. 890 and the related directives of Order No. 693, the

Commission also proposes to direct the ERO to develop modifications of the Reliability

Standards to comply with the following discrete issues: the availability of each

transmission service provider’s implementation documents; the consistent treatment of

assumptions in the calculation of available transfer capability; the calculation, allocation

and use of capacity benefit margin; the calculation of total transfer capability under the

Rated System Path Methodology; and, the treatment of network resource designations in

the calculation of available transfer capability. Each of these issues is discussed below.

1. Availability of Implementation Documents

a. NERC Proposal

103. The proposed Reliability Standards require that the available transfer capacity,

capacity benefit margin, and transmission reliability margin implementation documents



be made available to specified entities. Requirement R4 of MOD-001-1 requires that the

following entities have access to the available transfer capability implementation

document: each planning coordinator, reliability coordinator, and transmission operator

associated with the transmission service provider’s area; and each planning coordinator,

reliability coordinator, and transmission service provider adjacent to the transmission

service provider’s area. Requirement R2 of MOD-004-1 requires each transmission

service provider to make its capacity benefit margin implementation document available

to transmission operators, transmission service providers, reliability coordinators,

transmission planners, resource planners, and planning coordinators that are within or

adjacent to the transmission service provider’s area, and to load-serving entities and

balancing authorities within the transmission service provider’s area. Requirement R3 of

MOD-008-1 requires each transmission operator to provide its transmission reliability

implementation document upon request by transmission service providers, reliability

coordinators, transmission planners, and transmission operators. NERC states that it and

NAESB have agreed that requirements for making information available to other entities

are more appropriately addressed through the NAESB process.

b. Commission Proposal

104. The Commission is concerned that the proposed Reliability Standards potentially

restrict the disclosure of the available transfer capability, capacity benefit margin, and

transmission reliability margin implementation documents. NERC does not explain in its

filings why only certain entities would have access to these materials, nor why the

specified list of recipients varies for each document. While the Commission notes that



the proposed NAESB standards accompanying the Reliability Standards would require

transmission service providers to post a link to the implementation documents on their

OASIS, which would result in disclosure beyond the specified entities listed in the

Reliability Standards, the Commission believes that it is important for reliability purposes

to require disclosure of the implementation documents to a broader audience than

provided in the Reliability Standards. The Commission’s jurisdiction under section 215

of the FPA is broader than our jurisdiction to require compliance with the NAESB

standards under sections 205 and 206 of the FPA. These documents will describe how the

transmission provider will implement the Reliability Standards and, therefore, should be

disclosed by all transmission service providers, not only those who are also public

utilities.

105. Therefore, to ensure sufficient transparency, the Commission proposes to direct

the ERO, pursuant to section 215(d)(5) of the FPA and section 35.19(f) of our

regulations, to modify the proposed Reliability Standards to make the available transfer

capability, capacity benefit margin, and transmission reliability margin implementation

documents available to all customers eligible for transmission service in a manner that is

consistent with relevant NAESB standards. The Commission seeks comment on any

improvements that may be necessary to improve access by transmission customers to the

implementation documents.



2. Consistent Treatment of Assumptions

a. NERC Proposal

106. Under each of the methodologies contained in the proposed Reliability Standards,

available transfer capability is calculated as total transfer capability minus existing

transmission commitments, capacity benefit margin, and transmission reliability margin,

plus postbacks and counterflows. NERC contends that the Reliability Standards work

together to ensure that similar risks will not be double counted in the calculation of

capacity benefit margin and transmission reliability margin. Specifically, Requirement

R2 of MOD-008-1 prohibits a transmission operator from including any of the

components of capacity benefit margin in the components of uncertainty used to calculate

transmission reliability margin. NERC contends that MOD-004-1 addresses this

prohibition by describing the specific type of studies and requirements that may be used

to determine a need for capacity benefit margin.


107. The Commission is concerned that proposed Reliability Standards do not preclude

a transmission service provider from using data and assumptions in a way that double

counts their impact on available transfer capability and thereby skews the amount of

capacity made available to others. NERC states that MOD-004-1 and MOD-008-1 have

been drafted to preclude the double counting of similar risks in the calculation of capacity

benefit margin and transmission reliability margin. However, other components of the

available transfer capability calculation could be affected by the same data or

assumptions, and there is no apparent restriction in the Reliability Standards from such



data or assumptions in a way that double counts their impact on available transfer

capability.

108. For example, the Reliability Standards would appear to allow the transmission

service provider to factor a reserve margin for facility outages into more than one of the

components of the available transfer capability calculation. If the effect of the reserve

margin were to appear in multiple components of the available transfer capability

calculation in a similar way, under certain modeling approaches the results of that

calculation would be skewed. While it may be appropriate for some variables to be

factored into multiple components of the available transfer capability calculation, such as

facility ratings, the Reliability Standards do not require that assumptions affecting

multiple components of the available transfer capability calculation are implemented in a

way that is consistent with their actual effect on available transfer capability. The

Commission proposes to direct the ERO, pursuant to section 215(d)(5) of the FPA and

section 35.19(f) of our regulations, to modify the proposed Reliability Standards to

ensure that the proposed Reliability Standards preclude a transmission service provider

from using data and assumptions in a way that double counts their impact on available

transfer capability and thereby skews the amount of capacity made available to others.

3. Capacity Benefit Margin (MOD-004-1)

a. NERC Proposal

109. As noted above, Requirements R5.1 and R6.1 of MOD-004-1 require transmission

service providers to establish capacity benefit margin values for each path and flowgate

“reflect[ing] consideration of” both (i) studies provided by load-serving entities and



resource planners demonstrating a need for capacity benefit margin and (ii) applicable

reserve margin or resource adequacy requirements. In preparing their studies,

Requirements R3.1 and R4.1 direct load-serving entities and resource planners to use one

or more of the following to determine the generation capability import requirement:

(i) loss of load expectation studies, (ii) loss of load probability studies, (iii) deterministic

risk-analysis studies, and (iv) applicable reserve margin or resource adequacy

requirements. With regard to the allocation and use of transmission capacity set aside as

capacity benefit margin, Requirement R1.3 requires the transmission service provider to

include in its capacity benefit margin implementation document the procedure for a load-

serving entity or balancing authority to use transmission capacity set aside as capacity

benefit margin, including the manner in which the transmission service provider “will

manage” situations where the requested use of capacity benefit margin exceeds the

capacity benefit margin available.


110. In Order Nos. 890 and 693, the Commission emphasized that each load-serving

entity has the right to request that capacity benefit margin be set aside, and to use

transmission capacity set aside for that purpose, to meet its verifiable generation

reliability criteria requirement.78 The Commission is concerned that, as proposed, the

Reliability Standard would allow a transmission service provider to calculate, allocate,

78 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1080; see also Order No.890, FERC Stats. & Regs. ¶ 31,241 at P 259; Order No. 890-A, FERC Stats. & Regs.¶ 31,261 at P 82.



and use capacity benefit margin in a way that impairs the reliable operation of the Bulk-

Power System. Under the Reliability Standard, the transmission service provider is to

“reflect consideration” of studies provided by load-serving entities and resource planners

demonstrating a need for capacity benefit margin and “manage” situations where the

requested use of capacity benefit margin exceeds the capacity benefit margin available.

The Reliability Standard places no bounds on this “consideration” and “management”

and, for example, would permit a transmission service provider to make decisions

regarding the use of capacity benefit margin based solely on economic considerations

notwithstanding a demonstration of need for capacity benefit margin by a load-serving

entity or resource planner. The Commission proposes, pursuant to section 215(d)(5) of

the FPA and section 39.5(f) of our regulations, to direct the ERO to develop a

modification to the Capacity Benefit Margin Methodology (MOD-004-1) to ensure that

the Reliability Standard would not allow a transmission service provider to calculate,

allocate, and use capacity benefit margin in a way that impairs the reliable operation of

the Bulk-Power System.

111. In addition, the Commission has concern regarding references to applicable

reserve margin and resource adequacy requirements in the determination of the

generation capability import requirements by load-serving entities and resource planners

under Requirements R3.1 and R4.1. Under the phrasing of those provisions, load-serving

entities and resource planners must determine their generation capability import

requirement by using one or more of loss of load expectation studies, loss of load

probability studies, deterministic risk-analysis studies, and applicable reserve margin or



resource adequacy requirements. As a result, a load-serving entity or resource planner

could rely solely on reserve margin and resource adequacy requirements to demonstrate a

need for capacity benefit margin without any analysis of loss of load expectations, loss of

load probabilities, or deterministic risk. In comparison, Requirements 5.1 and 6.1

obligate the transmission service provider to consider both the studies provided by load-

serving entities and resource planners and applicable reserve margin and resource

adequacy requirements when calculating capacity benefit margin and allocating it to

particular paths or flowgates. The Commission proposes, pursuant to section 215(d)(5)

of the FPA and section 39.5(f) of our regulations, to direct the ERO to develop a

modification to MOD-004-1 to require load-serving entities and resource planners to

determine generation capability import requirements by reference to relevant studies and

applicable reserve margin or resource adequacy requirements, as relevant.

4. Calculation of Total Transfer Capability under the RatedSystem Path Methodology (MOD-029-1)

a. NERC Proposal

112. Requirement R2 of the Rated System Path Methodology (MOD-029-1) provides

the process a transmission operator must use to determine total transfer capability.

Requirement R2.7 of that Reliability Standard requires the transmission operator to set

the total transfer capability of an available transfer capability path to a value determined

prior to 1994 in certain instances:

R2.7. For available transfer capability Paths whose pathrating, adjusted for seasonal variance, was established, knownand used in operation since January 1, 1994, and no action



has been taken to have the path rated using a differentmethod, set the total transfer capability at that previouslyestablished amount.


113. In Order No. 890, the Commission required the use of consistent practices to

calculate total transfer capability.79 In Order No. 890-A, the Commission clarified that,

while total transfer capability need not be recalculated at consistent time intervals, the

transmission operator should consider whether any changes in system topology,

contingency outages, or other factors are substantial enough to merit recalculation of total

transfer capability.80

114. NERC has not explained the inclusion of Requirement R2.7 in the Rated System

Path Methodology. It is not clear to the Commission why certain applicable entities

would be required to use pre-1994 total transfer capability values. The Commission is

concerned that requiring pre-1994 total transfer capability values to remain in place

without adequate explanation essentially exempts certain paths from the total transfer

capability requirements in the Rated System Path Methodology and may result in total

transfer capability values that are incorrectly based on stale assumptions and criteria.

115. While the Commission proposes to approve the proposed Reliability Standard

overall as just and reasonable and an improvement on available transfer capability

transparency, as discussed above, pursuant to section 215(d)(5) of the FPA and section


80 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 105.



39.5(f) of our regulations, the Commission seeks comment on whether it should direct the

ERO to develop a modification to the Rated System Path Methodology (MOD-029-1) to

remove Requirement R2.7 as unsupported.

5. Treatment of Network Resource Designations

a. NERC Proposal

116. In each of the proposed Reliability Standards, transmission service providers are

required to identify as part of their calculation of existing transmission commitments the

amount of capacity that is set aside for network integration transmission service.81

However, the specificity of that requirement varies among the proposed Reliability

Standards.

117. Under the Flowgate Methodology (MOD-030-2), Requirements R6.1 and 6.2

provide for calculation of the impact of network integration transmission service based on

a modeling of load forecasts for the time period being calculated and unit commitment

and dispatch order, including all designated network resources and other resources that

are committed or have the legal obligation to run as specified in the transmission service

provider’s implementation document. Requirement R8 of the Area Interchange

Methodology (MOD-028-1) and Requirement R5 of the Rated System Path Methodology

(MOD-029-1) provide for the inclusion of firm capacity reserved for network integration

81 See MOD-028-001, Requirement R8; MOD-029-1, Requirement R5; MOD-030-2, Requirement R6.1.



transmission service, but do not describe how the transmission service provider is to

identify that amount of capacity.

118. With regard to the frequency of these calculations, Requirement R8 of MOD-001-

1 would require every transmission service provider calculating available transfer

capability to perform recalculations of available transfer capability at specified

frequencies, unless none of the calculated values identified in the available transfer

capability equation have changed.


119. In Order No. 693, the Commission directed the ERO to develop requirements

specifying how transmission service providers should determine which generators should

be modeled in service when calculating available transfer capability.82 Among other

things, the Commission directed the ERO to revise the Reliability Standards to specify

that base generation dispatch schedules will reflect the modeling of all designated

network resources and other resources that are committed to or have the legal obligation

to run, as they are expected to run. The Commission also directed transmission service

providers to address the effect on available transfer capability of designating and

undesignating a network resource.

120. NERC has not explained the failure to include in each of the available transfer

capability methodologies a requirement that base generation dispatch schedules will

reflect the modeling of all designated network resources and other resources that are




committed to or have the legal obligation to run, as they are expected to run. It is

therefore unclear whether the proposed Reliability Standards address the effect on

available transfer capability of designating and undesignating a network resource. While

the Commission proposes to approve the proposed Reliability Standards as just and

reasonable and an improvement on available transfer capability transparency, pursuant to

section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission

proposes to direct the ERO to develop a modification to the Reliability Standards to

address these requirements.

C. Violation Risk Factors and Violation Severity Levels

121. To determine a base penalty amount for a violation of a requirement within a

Reliability Standard, NERC must first determine an initial range for the base penalty

amount. To do so, NERC will assign a violation risk factor for each requirement of a

Reliability Standard that relates to the expected or potential impact of a violation of the

requirement on the reliability of the Bulk-Power System. For that requirement, the ERO

assigns a lower, medium or high violation risk factor for each mandatory Reliability

Standard requirement.83 The Commission has established guidelines for evaluating the

validity of each violation risk factor assignment.84

83 The specific definitions of high, medium and lower are provided in NorthAmerican Electric Reliability Corp., 119 FERC ¶ 61,145 at P 9, order on reh’g,120 FERC ¶ 61,145 (2007) (Violation Risk Factor Rehearing Order).

84 The guidelines are: (1) consistency with the conclusions of the blackout report;(2) consistency within a Reliability Standard; (3) consistency among ReliabilityStandards; (4) consistency with NERC’s definition of the violation risk factor level; and

(continued…)



122. NERC will also define up to four violation severity levels – lower, moderate, high

and severe – as measurements for the degree to which the requirement was violated in a

specific circumstance. For a specific violation of a particular requirement, NERC or the

Regional Entity will establish the initial value range for the base penalty amount by

finding the intersection of the applicable violation risk factor and violation severity level

in the base penalty amount table in appendix A of its sanction guidelines.

123. On June 19, 2008, the Commission issued an order establishing four guidelines for

the development of violation severity levels.85 First, the violation severity level

assignments should not have the unintended consequence of lowering the current level of

compliance. Second, the violation severity levels should ensure uniformity and

consistency in the determination of penalties. Third, a violation severity level assignment

should be consistent with the corresponding requirement. Fourth, a violation severity

level assignment should be based on a single violation, not on a cumulative number of

violations.

(5) treatment of requirements that co-mingle more than one obligation. The Commissionalso explained that this list was not necessarily all-inclusive and that it retained theflexibility to consider additional guidelines in the future. A detailed explanation isprovided in the Violation Risk Factor Rehearing Order, 120 FERC ¶ 61,145 at P 8-13.

85 North American Electric Reliability Corp., 123 FERC ¶ 61,284, at P 20-35(Violation Severity Level Order), order on reh’g & compliance, 125 FERC ¶ 61,212(2008).



1. NERC Proposal

124. In its August 29, 2008 filing, NERC proposes violation severity levels that are

specific to the individual requirements of the proposed Reliability Standards. NERC

states that it developed violation severity level assignments for MOD-001-1, MOD-008-

1, MOD-028-1, MOD-029-1, and MOD-030-1 prior to issuance of the Violation Severity

Level Order. As a result, NERC states that it has not analyzed the proposed violation

severity levels relative to the Commission’s guidelines established in the Violation

Severity Level Order.

125. In addition, NERC states that it is not filing the associated violation risk factors

with these Reliability Standards. While violation risk factors have been developed and

balloted for each of the five proposed Reliability Standards, NERC states that its Board

believes further review of the violation risk factors is warranted given recent Commission

actions in general and the development history of these violation risk factors in particular.

In accordance with its Rules of Procedure, NERC states that it will submit violation risk

factors for these proposed Reliability Standards in a future filing.

126. NERC states that each balloted Reliability Standard included a violation risk

factor for each main requirement in the Reliability Standard. For all the requirements in

the balloted MOD Reliability Standards, the applicable violation risk factors were

“lower.” In developing the violation risk factor assignments, NERC states that there

were opposing viewpoints with respect to the appropriate assignments. According to

NERC, one view offered that available transfer capability and its associated

methodologies do not directly affect the electrical state of the system or the ability to



monitor or control it as would be required under the “medium” violation risk factor

assignment. NERC states that an incorrect available transfer capability calculation may

lead to oversubscribing or undersubscribing the system. According to NERC,

undersubscribing, while affecting the potential for commercial activity, actually benefits

reliability. Oversubscribing the system as a result of an optimistic available transfer

capability value, while somewhat beneficial to commercial activity, may lead to a

reliability concern that if realized can be managed by the operator’s adherence to system

limits, to the extent that the operator has options to implement some measure of

transmission loading relief to reduce flows due to transactions. NERC states that for an

incorrect available transfer capability to become a reliability issue requires an optimistic

available transfer capability value, coupled with the sale of that available transfer

capability, and an operator who is not mindful to the system limits, the last of which is

governed by other transmission operator and interconnection operating Reliability

Standards. On this argument, according to NERC, assigning a “medium” violation risk

factor due to the “direct” impact is questionable.

127. On this basis, the drafting team evaluated the scope of the remaining work to meet

the Commission deadline and focused its attention to the technical issues, adjusting the

violation risk factors to “lower” based on the industry comments and the arguments

presented above. However, NERC states that its Board believes that a more thorough

review of the violation risk factors is warranted given recent Commission actions in

general and the development history of these violation risk factors in particular. NERC’s

board has asked NERC staff to review these violation risk factors through an open



stakeholder process to ensure that they are consistent with the intent of the violation risk

factor definitions and prior Commission decisions on violation risk factors. Accordingly,

NERC states that it is not filing the associated violation risk factors with these Reliability

Standards at this time. NERC states that it will submit violation risk factors for these

proposed Reliability Standards in a future filing.

128. In its November 21, 2008 and March 6, 2009 filings, NERC proposes violations

severity levels for MOD-004-1 and MOD-030-2, respectively. Similar to the violation

severity levels proposed for MOD-001-1, MOD-008-1, MOD-028-1, MOD-029-1, and

MOD-030-1, NERC does not propose any violation severity levels for the sub-

requirements. In addition, NERC states that its board of trustees deferred action on the

violation risk factors associated with these Reliability Standards and asked that they be

reviewed through an open stakeholder process, with a report back to the board, to ensure

that they are consistent with the intent of the violation risk factor definitions and

Commission precedent. NERC states that it will submit violation risk factors for these

Reliability Standards in a future filing.

2. Commission Proposal

129. The Commission proposes to accept NERC’s commitment to file violation

severity levels and violation risk factors at a later time. The Violation Severity Level

Order was issued after NERC developed the violation severity level assignments for the

Reliability Standards at issue in this proceeding. As a result, NERC was unable to

evaluate and modify the proposed violation severity levels to comply with our guidelines

prior to filing the proposed Reliability Standards. The Commission proposes to direct the



ERO to reevaluate the violation severity levels associated with all of the proposed

Reliability Standards based on the Commission’s guidelines outlined in the Violation

Severity Level Order and prepare appropriate revisions. In addition, the Commission

proposes to accept NERC’s proposal to allow NERC staff to review the violation risk

factors through an open stakeholder process to ensure that they are consistent with the

intent of the violation risk factor definitions and guidance provided in the Violation Risk

Factor Order and the Violation Risk Factor Rehearing Order. The Commission proposes

to direct NERC to file revised violation severity levels and violation risk factors no later

than 120 days before the Reliability Standards become effective.

D. Disposition of Other Reliability Standards

1. MOD-010-1 through MOD-025-1

130. Order No. 890 directed public utilities, working through NERC, to modify the

reliability standards MOD-010 through MOD-02586 to incorporate a requirement for the

periodic review and modification of models for (1) load flow base cases with

contingency, subsystem, and monitoring files, (2) short circuit data, and (3) transient and

dynamic stability simulation data, in order to ensure that they are up to date. The

Commission found that this requirement is essential in order to have an accurate

simulation of the performance of the grid and from which to comparably calculate

86 The MOD-010 through MOD-025 Reliability Standards establish datarequirements, reporting procedures, and system model development and validation foruse in the reliability analysis of the interconnected transmission systems.



available transfer capability, therefore increasing transparency and decreasing the

potential for undue discrimination by transmission service providers.87

a. NERC Proposal

131. NERC states that this modeling activity is outside the scope of the available

transfer capability Reliability Standards drafting team effort because it requires a

different skill set and expertise than that required for developing available transfer

capability and should be addressed by a separate drafting team. NERC states that these

Reliability Standards are part of its Reliability Standards Development Plan. NERC

states that this is consistent with Order No. 693, which identified nine Reliability

Standards, none of which were MOD-010 through MOD-025, as the core of the available

transfer capability initiative directed in Order No. 890.88


132. The Commission proposes to allow NERC to address revisions to MOD-010

through MOD-025 through a separate project. Those Reliability Standards are generally

intended to establish consistent data requirements, reporting procedures and system

models for use in reliability analysis. As such, the Commission proposes to find that

NERC is correct that they were not a part of the available transfer capability

modifications required in Order Nos. 890 and 693.





2. Reliability Standards Proposed to be Retired or Withdrawn

a. NERC proposal

133. NERC requests that FAC-013-1, MOD-006-0, and MOD-007-0 be retired when

the available transfer capability-related Reliability Standards become effective. In

addition, NERC requests to withdraw its request for approval of the following Reliability

Standards that were neither approved nor remanded in Order No. 693, effective upon

approval of the available transfer capability-related MOD Reliability Standards in this

proceeding: FAC-012-1, MOD-001-0, MOD-002-0, MOD-003-0, MOD-004-0, MOD-

005-0, MOD-008-0, and MOD-009-0. According to NERC, these Reliability Standards

are wholly superseded by the MOD Reliability Standards addressed in this proceeding.


134. The Commission proposes to approve NERC’s request to retire MOD-006-0 and

MOD-007-0 and to withdraw its request for approval of MOD-001-0, MOD-002-0,

MOD-003-0, MOD-004-0, MOD-005-0, MOD-008-0, and MOD-009-0. The

Commission also proposes to find that MOD-001-0, MOD-002-0, MOD-003-0, MOD-

004-0, MOD-005-0, MOD-008-0, and MOD-009-0 are all superseded by the available

transfer capability calculations required by the proposed MOD Reliability Standards in

this proceeding and are, upon the effectiveness of the proposed MOD Reliability

Standards, no longer necessary.

135. With regard to FAC-012-1 and FAC-013-1, the Commission disagrees with NERC

that these Reliability Standards are wholly superseded by the MOD Reliability Standards

addressed in this proceeding. Under FAC-012-1, reliability coordinators and planning



authorities would be required to document the methodology used to establish inter-

regional and intra-regional transfer capabilities and to state whether the methodology is

applicable to the planning horizon or the operating horizon. Under FAC-013-1,

reliability coordinators and planning authorities are required to establish a set of inter-

regional and intra-regional transfer capabilities that are consistent with the methodology

documented under FAC-012-1, which could require the calculation of transfer

capabilities for both the planning horizon and the operating horizon. In comparison, the

proposed MOD Reliability Standards provide only for the calculation of available

transfer capability and its components, including total transfer capability, in the operating

horizon.89 The proposed MOD Reliability Standards do not govern the calculation of

transfer capabilities in the planning horizon, i.e., beyond 13 months in the future.

136. In Order No. 693, the Commission approved FAC-013-1, but declined to approve

or remand FAC-012-1. The Commission expressed concern that FAC-012-1 merely

required the documentation of a transfer capability methodology without providing a

framework for that methodology including data inputs and modeling assumptions.90 The

Commission also expressed concern that the criteria used to calculate transfer capabilities

for use in determining available transfer capability must be identical to those used in

planning and operating the system.91 The Commission directed the ERO to modify FAC-

89 See MOD-001-1, Requirement R2.3.


91 Id. P 782.



012-1 to provide a framework for the transfer capability calculation methodology that

takes account of the need for consistency in the criteria used to calculate transfer

capabilities.92

137. The available transfer capability methodologies set forth in MOD-028-1, MOD-

029-1, and MOD-030-2 each provide a framework for the calculation of total transfer

capability and total flowgate capability that specifies certain data inputs and modeling

assumptions to be used.93 Requirement R7 of MOD-001-1 also provides that, when

calculating available transfer capability or available flowgate capability, the transmission

provider shall use assumptions no more limiting than those used in the planning of

operations for the corresponding time period studied. It therefore appears that the MOD

Reliability Standards provide a framework for the consistent calculation of total transfer

capability for the operating horizon. However, NERC has not addressed the requirements

of Order No. 693 with regard to the calculation of transfer capabilities in the planning

horizon.

138. The Commission therefore proposes not to grant NERC’s request to withdraw

FAC-012-1, nor approve the retirement of FAC-013-1. Instead, the Commission

proposes, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our regulations,

to direct the ERO to submit a revised FAC-012-1 and a modification to FAC-013-1 to

92 Id. P 779, 782.

93 See MOD-028-1, Requirements R3 and R4; MOD-029-1, Requirements R2 andR3; MOD-030-2, Requirement R2.4.



comply with the relevant directives of Order No. 693 and as otherwise necessary to make

the requirements of those Reliability Standards consistent with those of the proposed

MOD Reliability Standards and the final rule in this proceeding. The Commission

proposes to direct the ERO to submit a revised FAC-012-1 and a modification to FAC-

013-1, as well as violation severity levels and violation risk factors for FAC-012-1 and

FAC-013-1, no later than 120 days before the MOD Reliability Standards become

effective.

E. Definitions

139. In Order Nos. 890 and 693, the Commission noted that there was not a definition

of available flowgate capability/total flowgate capability in the ERO’s glossary and

directed the ERO to develop available flowgate capability/total flowgate capability

definitions used to identify a particular set of transmission facilities as flowgates.

1. NERC Proposal

140. NERC proposes to modify its Glossary of Terms to add the following twenty

definitions that are used in the five proposed Reliability Standards, two of which wholly

replace existing terms in the Commission-approved NERC Glossary:94

Area Interchange Methodology: The Area InterchangeMethodology is characterized by determination ofincremental transfer capability via simulation, from whichTotal Transfer Capability (TTC) can be mathematicallyderived. Capacity Benefit Margin (CBM), TransmissionReliability Margin (TRM), and Existing TransmissionCommitments (ETC) are subtracted from the TTC, and

94 These include Available Transfer Capability and Flowgate.



Postbacks and counterflows are added, to derive AvailableTransfer Capability (ATC). Under the Area InterchangeMethodology, TTC results are generally reported on an areato area basis.

ATC Path: Any combination of Point of Receipt (POR) andPoint of Delivery (POD) for which Available TransferCapability (ATC) is calculated; and any Posted Path.95

Available Flowgate Capability (AFC): A measure of theflow capability remaining on a Flowgate for furthercommercial activity over and above already committed uses.It is defined as Total Flowgate Capability (TFC) less ExistingTransmission Commitments (ETC), less a Capacity BenefitMargin (CBM), less a Transmission Reliability Margin(TRM), plus Postbacks, and plus counterflows.

Available Transfer Capability (ATC): A measure of thetransfer capability remaining in the physical transmissionnetwork for further commercial activity over and abovealready committed uses. It is defined as Total TransferCapability (TTC) less Existing Transmission Commitments(ETC) (including retail customer service), less a CapacityBenefit Margin (CBM), less a Transmission ReliabilityMargin (TRM), plus Postbacks, plus counterflows.

Available Transfer Capability Implementation Document(ATCID): A document that describes the implementation ofa methodology for calculating Available Transfer Capability(ATC) or Available Flowgate Capability (AFC), and providesinformation related to a Transmission Service Provider’scalculation of ATC or AFC.

Block Dispatch: A set of dispatch rules such that given aspecific amount of load to serve, an approximate generationdispatch can be determined. To accomplish this, the capacityof a given generator is segmented into loadable “blocks,”each of which is grouped and ordered relative to other blocks

95 See 18 CFR 37.6(b)(1) (2008).



(based on characteristics including, but not limited to,efficiency, run of river or fuel supply considerations, and/or“must-run” status).

Business Practices: Those business rules contained in theTransmission Service Provider’s applicable tariff, rules, orprocedures; associated Regional Reliability Organization orRegional Entity business practices; or North AmericanEnergy Standards Board (NAESB) Business Practices.

Capacity Benefit Margin Implementation Document(CBMID): A document that describes the implementation ofa Capacity Benefit Margin methodology.

Dispatch Order: A set of dispatch rules such that given aspecific amount of load to serve, an approximate generationdispatch can be determined. To accomplish this, eachgenerator is ranked by priority.

Existing Transmission Commitments (ETC): Committeduses of a Transmission Service Provider’s Transmissionsystem considered when determining Available TransferCapability (ATC) or Available Flowgate Capability (AFC).

Flowgate:

1.) A portion of the Transmission system through which theInterchange Distribution Calculator calculates the power flowfrom Interchange Transactions.

2.) A mathematical construct, comprised of one or moremonitored transmission Facilities and optionally one or morecontingency Facilities, used to analyze the impact of powerflows upon the Bulk Electric System.

Flowgate Methodology: The Flowgate methodology ischaracterized by identification of key Facilities as Flowgates.Total Flowgate Capabilities (TFC) are determined based onFacility Ratings and voltage and stability limits. The impactsof Existing Transmission Commitments (ETCs) aredetermined by simulation. The impacts of ETC, CapacityBenefit Margin (CBM) and Transmission Reliability Margin(TRM) are subtracted from the TFC, and Postbacks andcounterflows are added, to determine the Available Flowgate



Capability (AFC) value for that Flowgate. AFCs can be usedto determine Available Transfer Capability (ATC).

Generation Capability Import Requirement (GCIR): Theamount of generation capability from external sourcesidentified by a Load-Serving Entity (LSE) or ResourcePlanner (RP) to meet its generation reliability or resourceadequacy requirements as an alternative to internal resources.

Outage Transfer Distribution Factor (OTDF): In the post-contingency configuration of a system under study, theelectric Power Transfer Distribution Factor (PTDF) with oneor more system Facilities removed from service (outaged).

Participation Factors: A set of dispatch rules such thatgiven a specific amount of load to serve, an approximategeneration dispatch can be determined. To accomplish this,generators are assigned a percentage that they will contributeto serve load.

Planning Coordinator: See Planning Authority.

Postback: Positive adjustments to Available TransferCapability (ATC) or Available Flowgate Capability (AFC) asdefined in Business Practices. Such Business Practices mayinclude processing of redirects and unscheduled service.

Power Transfer Distribution Factor (PTDF): In the pre-contingency configuration of a system under study, a measureof the responsiveness or change in electrical loadings ontransmission system Facilities due to a change in electricpower transfer from one area to another, expressed in percent(up to 100%) of the change in power transfer .

Rated System Path Methodology: The Rated System PathMethodology is characterized by an initial Total TransferCapability (TTC), determined via simulation. CapacityBenefit Margin (CBM), Transmission Reliability Margin(TRM), and Existing Transmission Commitments (ETC) aresubtracted from TTC, and Postbacks and counterflows areadded as applicable, to derive Available Transfer Capability(ATC). Under the Rated System Path Methodology, TTCresults are generally reported as specific transmission pathcapabilities.



Total Flowgate Capability (TFC): The maximum flowcapability on a Flowgate, is not to exceed its thermal rating,or in the case of a flowgate used to represent a specificoperating constraint (such as a voltage or stability limit), isnot to exceed the associated System Operating Limit.

Transmission Operator Area: The collection ofTransmission assets over which the Transmission Operator isresponsible for operating.

Transmission Reliability Margin ImplementationDocument (TRMID): A document that describes theimplementation of a Transmission Reliability Margin (TRM)methodology, and provides information related to aTransmission Operator’s calculation of TRM.

2. Commission Proposal

141. The Commission proposes to approve the addition of these terms to the NERC

Glossary with minor modification. The Commission believes that the definition of

Postback is not fully determinative. NERC should be able to define this term without

reference to Business Practices, another defined term. The Commission therefore

proposes to direct NERC to modify the definition of Postback.

142. The definition of Business Practices includes a reference to the “regional

reliability organization.” In Order No. 693, the Commission directed NERC to eliminate

references to regional reliability organizations as responsible entities in the Reliability

Standards because such entities are not users, owners or operators of the Bulk-Power

System.96 Accordingly, the Commission proposes to direct NERC to remove from the

proposed definition of Business Practices, the reference to regional reliability




organizations and replace it with the term Regional Entity. However, Regional Entity is

not currently defined in the NERC Glossary. The Commission therefore proposes to

direct NERC to develop a definition of Regional Entity consistent with section 215(a) of

the FPA97 and 18 CFR 39.1 (2008), to be included in the NERC Glossary.

IV. Information Collection Statement

143. The following collections of information contained in this proposed rule have been

submitted to the Office of Management and Budget (OMB) for review under section

3507(d) of the Paperwork Reduction Act of 1995.98 OMB’s regulations require OMB to

approve certain information collection requirements imposed by agency rule.99

144. Comments are solicited on the need for this information, whether the information

will have practical utility, ways to enhance the quality, utility, and clarity of the

information to be collected, and any suggested methods for minimizing respondents’

burden, including the use of automated information techniques.

Burden Estimate: The public reporting and records retention burdens for the proposed

reporting requirements and the records retention requirement are as follows.100

97 16 U.S.C. 824o.

98 44 U.S.C. 3507(d).

99 5 CFR 1320.11.

100 These burden estimates apply only to this NOPR and do not reflect upon all ofFERC-516 or FERC-717.



DataCollection

Number ofRespondents

Number ofResponses

Hours perResponse

Total AnnualHours

Mandatory dataexchanges

137 1 80 10,960

Explanation ofchange of ATCvalues

137 1 100 13,700

Recordkeeping 137 1 30 3,480

Total Annual Hours for Collection:

Reporting + recordkeeping hours = 3,480 + 24,660 = 28,140 hours.

Cost to Comply:Reporting = $2,811,240

24,660 hours @ $114 an hour (average cost of attorney ($200 per hour),consultant ($150), technical ($80), and administrative support ($25))

Recordkeeping = $185,875 (same as below)Labor (file/record clerk @ $17 an hour) 3,480 hours @ $17/hour = $59,150Storage 137 respondents @ 8,000 sq. ft. x $925 (off site storage) = $126,725

Total costs = $2,997,115Labor $ ($2,811,240+ $59,150) + Recordkeeping Storage Costs ($126,725)

OMB’s regulations require it to approve certain information collection requirements

imposed by an agency rule. The Commission is submitting notification of this proposed

rule to OMB. If the proposed requirements are adopted they will be mandatory

requirements.

Title: Mandatory Reliability Standards for the Calculation of Available TransferCapability, Capacity Benefit Margins, Transmission Reliability Margins, Total TransferCapability, and Existing Transmission Commitments and Mandatory ReliabilityStandards for the Bulk-Power System

Action: Proposed Collections

OMB Control Nos. [to be determined]

Respondents: Business or other for profit



Frequency of responses: On occasion.

Necessity of the Information:

145. Internal Review: The Commission has reviewed the proposed reliability standards

and made a determination that these requirements are necessary to implement section 215

of the Energy Policy Act of 2005. These requirements conform to the Commission’s

plan for efficient information collection, communication and management within the

energy industry. The Commission has to assure itself, by means of internal review, that

there is specific, objective support for the burden estimates associated with the

information requirements.

146. Interested persons may obtain information on the reporting requirements by

contacting the following: Federal Energy Regulatory Commission, 888 First Street, N.E.

Washington, D.C. 20426 [Attention: Michael Miller, Office of the Executive Director,

Phone: (202)502-8415, fax: (202) 273-0873, e-mail: [email protected].]

147. For submitting comments concerning the collection(s) of information and the

associated burden estimate(s), please send your comments to the contact listed above and

to the Office of Information and Regulatory Affairs, Office of Information and

Regulatory Affairs, Washington, D.C. 20503 [Attention: desk Officer for the Federal

Energy Regulatory Commission, phone (202) 395-4650, fax: (202)395-7285, e-mail:

[email protected].]

V. Environmental Analysis

148. The Commission is required to prepare an Environmental Assessment or an

Environmental Impact Statement for any action that may have a significant adverse effect



on the human environment.101 The actions proposed here fall within the categorical

exclusion in the Commission's regulations for rules that are clarifying, corrective or

procedural, for information gathering, analysis, and dissemination.102

VI. Regulatory Flexibility Act Certification

149. The Regulatory Flexibility Act of 1980 (RFA)103 generally requires a description

and analysis of final rules that will have significant economic impact on a substantial

number of small entities. The MOD Reliability Standards apply to transmission service

providers and transmission operators, most of which do not fall within the definition of

small entities.104

150. As indicated above, approximately 137 entities will be responsible for compliance

with the three new Reliability Standards. Of these only six, or less than five percent,

have output of four million MWh or less per year.105 The Commission does not consider

this a substantial number.106 Based on this understanding, the Commission certifies that

101 Regulations Implementing the National Environmental Policy Act, OrderNo. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

102 18 CFR 380.4(a)(5).

103 5 U.S.C. 601-612.

104 The definition of “small entity” under the Regulatory Flexibility Act refers tothe definition provided in the Small Business Act, which defines a “small businessconcern” as a business that is independently owned and operated and that is not dominantin its field of operation. See 15 U.S.C. 632 (2000).

105 Id.

106 The Regulatory Flexibility Act defines a “small entity” as “one which isindependently owned and operated and which is not dominant in its field of operation.”

(continued…)



this rule will not have a significant economic impact on a substantial number of small

entities. Accordingly, no regulatory flexibility analysis is required.

VII. Comment Procedures

151. The Commission invites interested persons to submit comments on the matters and

issues proposed in this notice to be adopted, including any related matters or alternative

proposals that commenters may wish to discuss. Comments are due [insert date that is 60

days from publication in the FEDERAL REGISTER]. Comments must refer to Docket

Nos. RM08-19-000, RM08-19-001, RM09-5-000 and RM06-16-005, and must include

the commenter's name, the organization they represent, if applicable, and their address in

their comments.

152. The Commission encourages comments to be filed electronically via the eFiling

link on the Commission's web site at http://www.ferc.gov. The Commission accepts

most standard word processing formats. Documents created electronically using word

processing software should be filed in native applications or print-to-PDF format and not

See 5 U.S.C. 601(3) and 601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. v. FERC,773 F.2d 327, 340-43 (D.C. Cir. 1985), the court accepted the Commission's conclusionthat, since virtually all of the public utilities that it regulates do not fall within themeaning of the term “small entities” as defined in the Regulatory Flexibility Act, theCommission did not need to prepare a regulatory flexibility analysis in connection withits proposed rule governing the allocation of costs for construction work in progress(CWIP). The CWIP rules applied to all public utilities. The revised pro forma OATTwill apply only to those public utilities that own, control or operate interstate transmissionfacilities. These entities are a subset of the group of public utilities found not to requirepreparation of a regulatory flexibility analysis for the CWIP rule.



in a scanned format. Commenters filing electronically do not need to make a paper

filing.

153. Commenters that are not able to file comments electronically must send an

original and 14 copies of their comments to: Federal Energy Regulatory Commission,

Secretary of the Commission, 888 First Street N.E., Washington, D.C. 20426.

154. All comments will be placed in the Commission's public files and may be viewed,

printed, or downloaded remotely as described in the Document Availability section

below. Commenters on this proposal are not required to serve copies of their comments

on other commenters.

VIII. Document Availability

155. In addition to publishing the full text of this document in the Federal Register, the

Commission provides all interested persons an opportunity to view and/or print the

contents of this document via the Internet through FERC's Home Page

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A,

Washington D.C. 20426.

156. From FERC's Home Page on the Internet, this information is available on

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft

Word format for viewing, printing, and/or downloading. To access this document in

eLibrary, type the docket number excluding the last three digits of this document in the

docket number field.



157. User assistance is available for eLibrary and the FERC’s website during normal

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676)

or email at [email protected], or the Public Reference Room at (202) 502-

8371, TTY (202)502-8659. E-mail the Public Reference Room at

[email protected].

By direction of the Commission.

( S E A L )

Kimberly D. Bose,Secretary.


Document Content(s)

20134431.DOC..........................................................1-98


Tab 13

115 FERC ¶61,350UNITED STATES OF AMERICA


Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead Brownell, and Suedeen G. Kelly.

Oklahoma Gas and Electric Company and Docket Nos. EC03-131-003NRG McClain LLC EC03-131-004

ORDER ON COMPLIANCE

(Issued June 20, 2006)

1. This order addresses the mitigation the Commission relied upon in authorizing, under section 203 of the Federal Power Act,1 Oklahoma Gas and Electric Company’s (OG&E) acquisition of 400 megawatts (MWs) of the McClain generating facility (McClain Facility) from NRG McClain (the Transaction). In this Order, we find that OG&E has met its obligation to create at least 400 MWs of available transfer capability (ATC) into the OG&E control area by constructing certain transmission upgrades, as required in the Commission’s order conditionally accepting OG&E’s Offer of Settlement(Settlement Order).2

I. Background

A. Commission Order Authorizing Disposition of Facilities

2. On December 18, 2003, the Commission issued an order (Hearing Order) finding that the Transaction (without further mitigation) could harm competition in OG&E’s

1 16 U.S.C. § 824b (2000), amended by Energy Policy Act of 2005, Pub. L. No. 109-58, § 1289, 119 Stat. 594, 982-93 (2005).

2 Oklahoma Gas and Electric Co., 108 FERC ¶ 61,004, reh’g denied, 111 FERC ¶ 61,075 (2005) (Settlement Order).

20060621-3016 Issued by FERC OSEC 06/20/2006 in Docket#: EC03-131-003

Docket Nos. EC03-131-003 and EC03-131-004 2

market due to increases in OG&E’s horizontal and vertical market power3 and thus, was not consistent with the public interest.4 The Commission found that was insufficientevidence in the record to determine the mitigation measures it should impose asconditions to permit approval of the Transaction. Accordingly, the Commission set theapplication for hearing to address those issues.

3. On April 8, 2004, OG&E filed an Offer of Settlement intended to resolve the issues, offering the following permanent and interim mitigation measures. First, as a permanent mitigation measure, OG&E proposed to construct a 600 MW “bridge” (600 MW Bridge) between the Redbud Energy Project (Redbud Facility)5 and OG&E's control area.6 Redbud would be eligible to obtain that additional ATC, as would other suppliers,

3 Horizontal market power is exercised when in order to increase profits, a firm drives up prices through its control of a single activity, such as electricity generation, and it controls a significant share of the total capacity available in that market. Vertical market power is exercised when a firm involved in two related activities, such as electricity generation and transmission, uses its dominance in one area to raise prices and increase profits for the overall enterprise.

4 Inquiry Concerning the Commission’s Merger Policy Under the Federal Power Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68,595 (1996), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,044 (1996), reconsideration denied, Order No. 592-A, 62 Fed. Reg. 33,341 (1997), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement); see also Revised Filing Requirements Under Part 33 of the Commission’s Regulations, Order No. 642, 65 Fed. Reg. 70,983 (2000), FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 ¶ 31,111 (2000) (Order No. 642), order on reh’g, Order No. 642-A, 66 Fed. Reg. 16,121 (2001), 94 FERC ¶ 61,289 (2001). The Merger Policy Statement and Order No. 642 provide that the Commission will generally take account of three factors in its section 203 analysis: (1) the effect on competition; (2) the effect on rates; and (3) the effect on regulation.

5 The Redbud Facility is a 1,200 MW combined cycle generating facility in Luther, Oklahoma.

6 According to OG&E, the 600 MW Bridge would consist primarily of an upgradeto OG&E's Draper Substation. OG&E stated that it would begin construction of the 600 MW Bridge as soon as the Commission approved the Transaction, and estimated that the 600 MW Bridge could be completed within eleven months.



under OG&E’s Open Access Transmission Tariff (OATT).7 Second, as a permanent mitigation measure, OG&E would construct a transmission upgrade at OG&E’s Ft. Smith interconnection with Entergy Corporation’s transmission system. Third, as an interim mitigation measure to apply during the period between the Commission’s approval of the Transaction and the completion of the 600 MW Bridge, OG&E would redispatch (at no cost to Redbud) OG&E’s generating units to enable the Redbud Facility to sell power (not to exceed 600 MWs in the aggregate and subject to reliability constraints) to any wholesale customer in the OG&E control area. Fourth, as an interim mitigation measure, OG&E would establish an Independent Market Monitor to address vertical market power concerns until Southwest Power Pool’s (SPP) Regional Transmission Organization (RTO) starts calculating and posting ATC. Finally, OG&E proposed that theIndependent Market Monitor would oversee OG&E's calculation of ATC and total transmission capacity, and provide that data to the SPP, until the SPP was approved by the Commission as an RTO.8

4. In support of its Offer of Settlement and proposed upgrades, OG&E provided the results from several First Contingency Incremental Transfer Capability studies (First Contingency Transfer Studies). These studies modeled a hypothetical 1,200 MW transaction from Redbud to OG&E’s control area under a first contingency analysis using the SPP 2004 base cases for the summer and winter peak and assuming the McClain unit was not running. The studies identified the Draper substation and Memorial-Skyline 138kV line as limiting elements for the transaction, and indicated that the transfer capability from Redbud to OG&E might be increased to 649 MWs (summer) and 1,035 MWs (winter) if these limitations were removed.

5. In its initial testimony on OG&E’s Offer of Settlement, Trial Staff relied on the SPP System Impact Study dated April 6, 2004 (SPP-2003-271-1) to support the OG&E

7 OG&E explained that its offer to upgrade its system to create 600 MWs of ATC did not mean that Redbud (or any other supplier) would be guaranteed 600 MWs of ATC, or that Redbud would have guaranteed firm transmission service under the OATT to sell to customers, because those customers and any wholesale seller that sells power to them were not guaranteed either ATC or firm transmission service from OG&E’s McClain facility at that time.

8 Commission Trial Staff (Trial Staff) proposed eight modifications to the OG&E market monitoring plan in ¶ 36 of its Reply to OG&E’s Offer of Settlement. On April 6, 2004, OG&E agreed to all of these modifications (Exhibit OGE-Sett-2 at ¶ 25).



proposed upgrades. That SPP system impact study was performed at the request of Redbud and modeled a transaction from Redbud to OG&E’s control area for the period May 1, 2004 to May 1, 2007. The SPP study identified the Draper substation, the Memorial-Skyline 138kV line, and the Morgan-Mustang line as limiting elements for a Redbud-to-OG&E 1,200-MW transfer. Trial Staff also performed an independent analysis that demonstrated that adding a third transformer at the Draper Substation resulted in it no longer being the limiting facility for a 400-MW transfer from Redbud to OG&E’s control area.

6. In its affidavits supporting OG&E’s Offer of Settlement, Trial Staff performed additional studies, and concluded that the Draper Substation upgrade would allow for up to 600 MWs of ATC from Redbud to OG&E’s control area with or without the McClain facility running.

7. The Commission accepted the Offer of Settlement, subject to modification, because the mitigation would prevent harm to competition in OG&E’s market from the Transaction. The Commission found that the Offer of Settlement, as modified, would resolve the concerns about increases in OG&E’s horizontal and vertical market power from the Transaction and would not unduly burden OG&E or harm the reliability of OG&E’s system. Accordingly, the Commission approved the Transaction, as modified, as consistent with the public interest.

8. In May 2005, OG&E performed another First Contingency Transfer study with the upgrades modeled to confirm that the upgrades had their intended effect. This study again modeled a hypothetical 1,200 MW transaction from Redbud to OG&E’s control area under a first contingency analysis using an updated SPP 2005 base case and assuming that the McClain Facility was not running. The results of this study indicate that the upgraded facilities were no longer limiting facilities and that the resulting ATC is greater than 600 MWs.

9. On May 31, 2005, OG&E filed a letter informing the Commission that all of the facilities that OG&E had committed to construct were in commercial operation. As a result, OG&E concluded that its interim obligation to redispatch on its system wasterminated; in other words, it said that the permanent mitigation should replace the interim mitigation.

B. Subsequent Requests for Service by Redbud

10. In response to Redbud’s request for service for 1,200 MWs of firm transmission service from Redbud to OG&E’s control area for the period May 1, 2004, through May 1, 2007, SPP performed a system impact study. It was a long-term planning study using



SPP 2004 base cases. The initial study (SPP-2003-271-1) was dated April 6, 2004, with a revised version (SPP-2003-271-2) dated August 2, 2004. The study was modeled based on the assumption that OG&E’s proposed upgrades were in place as of June 1, 2005, with the McClain facility running. Based on this study, SPP was able to offer 600 MWs of ATC to Redbud through May 1, 2007.

11. In June 2005, the Oklahoma Corporation Commission required OG&E to issue a Request for Proposals for 440 MWs of firm power for the period June 28, 2005, to September 2, 2005. Redbud notified Commission Staff that, while it was the winning bidder, when it sought to acquire the ATC needed to provide the firm power to OG&E, SPP informed Redbud that there was no ATC available.

12. In response to the Redbud request for service for 440 MWs of ATC from Redbud to OG&E’s control area for the period of June 30, 2005, to September 2, 2005, SPP performed a study using operational and planning models for the period. That study also was modeled based on the assumption that OG&E’s upgrades were in place with the McClain facility running. This study indicated that the facilities upgraded by OG&E were no longer limiting facilities and, instead, Redbud-Arcadia and Silver Lake-Division were constraining flowgates. As a result, SPP did not approve Redbud’s request for service.

C. Data Requests and Responses

13. In September 2005, Staff issued a letter to OG&E and SPP requesting OG&E to demonstrate that the 600 MW Bridge provided 600 MWs of ATC. Staff requestedOG&E and SPP to provide information regarding: (1) the additional level of ATC for import into OG&E’s control area from the transmission upgrades; (2) the level of ATC for the OG&E control area posted on SPP’s OASIS beginning May 19, 2005, up to the present; (3) any transmission service requests (and refusals) for all or some of the additional ATC from the date that OG&E filed its Offer of Settlement; and (4) the processes for determining ATC for the OG&E control area.

14. In its October 3, 2005, response, OG&E states that it had completed the upgrades that it committed to build, but that system conditions must have changed between early 2004, when OG&E had estimated the amount of additional ATC that the upgrades would create, and June 2005, when Redbud made its transmission service request. OG&E points out that Redbud could have secured the firm transmission earlier. It points out, further, that Commission Trial Staff had verified OG&E’s 2004 First Contingency Incremental Transfer Capability studies (First Contingency Studies) that showed an additional 600 MWs of ATC and a separate SPP system impact study performed in August 2004, both showing at least 600 MWs of ATC into the OG&E control area.



15. In its October 3, 2005, response, SPP acknowledges that that its estimate of zero firm ATC was incorrect and that it needed to update the method for forecasting Redbud’s output in order to more accurately represent the amount of available ATC at the Redbud-to-Arcadia flowgate. SPP explains that, based on its subsequent analysis, between 300 and 400 MWs of ATC were actually available during the period of June 30, 2005, to September 2, 2005. SPP also states that it did not conduct any study that quantified the additional ATC created by the upgrades in OG&E’s Offer of Settlement.

16. OG&E’s Independent Market Monitor, Potomac Economics, questioned whether OG&E’s Offer of Settlement committed it to create incremental ATC over the amount created when OG&E’s McClain facility was running.9 According to OG&E’s Independent Market Monitor, the Offer of Settlement was not clear on this issue. OG&E’s Independent Market Monitor reported that the upgrades provided 600 MWs of incremental firm ATC without OG&E’s McClain facility running and approximately 200 MWs of incremental firm ATC with OG&E’s McClain Facility running. He explainedthat simply running the McClain Facility provides approximately 400 MWs of ATC by creating counterflows, and the combination of the upgrades and the counterflows create approximately 600 MWs of ATC, so the incremental ATC provided by the upgrades could be considered to be only 200 MWs, depending on whether running the McClain Facility should be included in the base case of the transmission model. He stated that because the issue was not clearly resolved in the Settlement Offer, it is outside the scope of the market monitoring plan.10

17. SPP’s Independent Market Monitor, Boston Pacific, reviewed SPP’s denial of Redbud’s June 2005 request for short-term firm service. SPP’s Independent Market Monitor determined that it was not clear that 600 MWs of ATC was available on OG&E’s system. It concluded that: (1) an additional 303 MWs of ATC was available atthe Redbud-to-Arcadia flowgate and 920 MWs at the Silver Lake-Division flowgate, over and above Redbud’s existing firm transmission reservations during July 2005; and (2) the Redbud-to-Arcadia flowgate was the limiting factor for transmission service for Redbud into OG&E’s control area.

18. In its October 25, 2005, response, Redbud argued that OG&E committed to upgrades that would provide an additional 600 MWs of ATC, regardless of whether or

9 See OG&E’s October 18, 2005, Quarterly Market Monitoring Report.

10 Id at 33-34.



not OG&E was running the McClain facility. It criticized OG&E’s explanation that system conditions must have changed between the time OG&E estimated the amount of additional ATC that the upgrades would create and the time when Redbud made its transmission service request (which was denied by SPP), Redbud concluded that OG&E had not fulfilled its commitment. Therefore, Redbud requested the Commission to direct SPP to treat OG&E as if it were a transmission owner requesting the firm service from Redbud into its control area and to direct SPP to perform a forward-looking study identifying the additional upgrades needed to provide 600 MWs of ATC. Redbud argued that OG&E should be required to pay for this study.

D. Technical Conference and Subsequent Comments

19. Commission Staff convened a technical conference on December 1, 2005. Participants discussed whether the upgrades completed by OG&E had created an additional 600 MWs of ATC, as required in the Settlement Order. Following the technical conference, Staff requested additional information and comments from the technical conference participants.

20. In its initial comments, OG&E states that it constructed the upgrades to offset the effects on the market of its acquisition of a portion of the McClain Facility. According toOG&E, the Commission said that the market effect of the Transaction was a result of OG&E removing 400 MWs of ATC from the OG&E control area. OG&E says the record shows that, after construction of the mitigation facilities, there would be 600 MWsof ATC from Redbud to OG&E’s control area when the McClain facility was running.

21. OG&E explains that the upgrades were selected to achieve a particular result usingthe SPP planning model, comparing “before” and “after” facility addition scenarios in First Contingency Studies.11 It emphasizes that its planning model studies differed from the operational studies that SPP performed to analyze Redbud’s transmission service request in June 2005 for short-term firm service. According to OG&E, such operational studies are based on the seven calendar days immediately preceding commencement of the requested service. Moreover, OG&E says that its commitment to install the mitigation facilities did not mean that such facilities would add 600 MWs of ATC “on top of” the ATC created by running the McClain Facility; rather, the upgrades were

11 OG&E stated that it used SPP’s long-range planning models in its base case analyses.



intended to ensure up to 600 MWs of ATC even if the McClain Facility was running. OG&E declares that SPP erred in modeling Redbud’s non-firm output and that this partly caused its denial of Redbud’s June 2005 request for service.

22. In its initial comments, Redbud contends that OG&E’s base case analyses were flawed because they did not reflect realistic system conditions after the acquisition of the McClain Facility. Redbud states, further, that the availability of 650 MWs of ATCidentified in SPP’s 2004 system impact study, does not mean that OG&E met its commitment to provide 600 MWs of additional ATC, especially since Redbud’s June 2005 request for service was denied. Moreover, Redbud argues that, when SPP fixed itsmodeling error in SPP’s subsequent June 2005 system impact study, the study showed that only 200 MWs of additional ATC were created. According to Redbud, neither OG&E nor SPP identified specific firm reservations that reduced the available ATC for Redbud to OG&E’s control area. Moreover, Redbud states that its studies indicate that prior firm reservations did not account for the disappearance of approximately 450 MWsof ATC between the time SPP studied Redbud’s 2004 request for service and Redbud’s June 2005 request for service.12

23. In its initial comments, as clarified in its supplement filed on February 15, 2006, SPP explains that its operational models, which incorporate forecasts of generation commitments, generation dispatch patterns, load patterns, generation outages, transmission outages, transmission upgrades, and reservations in study, accepted, or confirmed states. In both its operational and planning models (extending 15 months beyond the operational model period of 31 days), SPP determines hourly available flowgate capacity for 139 flowgates. SPP explains that its August 2004 system impact study was based on the McClain facility running to serve Oklahoma Municipal Power Authority’s and OG&E’s load and prior firm reservations. According to SPP, it analyzedwhich reservations requested after the July 8 Order and before the June 24, 2005, Redbud service request affected load on the Redbud-to-Arcadia and Silver Lake-Division

12 Redbud states that, according to its estimates, existing firm reservations reduced firm ATC by approximately 180-280 MWs on June 24, 2005.



flowgates to determine the effect on ATC for Redbud to OG&E’s control area.13 For thatperiod, SPP concludes that there was slightly more than 800 MWs of ATC available, withreservations approved during the period for 400-500 MWs, leaving approximately 300-400 MWs of available ATC for Redbud to OG&E’s control area.

24. In response to OG&E’s and SPP’s initial comments, Redbud requests that the Commission reject OG&E’s post hoc rationalization of its Offer of Settlement and enforce the plain meaning of that offer. Redbud says that the settlement was intended to create 600 MWs of additional ATC for Redbud to the OG&E control area, using a base case that reflects system conditions assumed by SPP when studying actual transmission service requests, i.e., based on operational studies rather than planning studies. According to Redbud, the Commission did not approve the installation of particular facilities to fulfill OG&E’s commitment to provide 600 MWs of additional ATC.

25. In response, OG&E contends that Redbud ignores what the Commission directedin the Settlement Order. OG&E points out that the Commission accepted OG&E’s Offer of Settlement as modified in response to Trial Staff’s comments on the settlement. Itexplains that Trial Staff requested it to clarify the Offer of Settlement to identify the particular upgrades that OG&E was proposing to construct. OG&E states, further, that the Settlement Order approved the Offer of Settlement as clarified and modified by Trial Staff’s comments.

II. Commission Determination

26. The issue here is the proper base case to use in determining whether OG&E created the additional 600 MWs of ATC directed in the Settlement Order. As discussed below, we conclude that OG&E has complied with the Settlement Order. OG&E’s Offerof Settlement stated that, as a permanent mitigation measure, it would construct the 600 MW Bridge, consisting primarily of an upgrade to OG&E’s Draper Substation, which would provide an additional 600 MWs of ATC, whether or not the McClain Facility was running. The record shows that OG&E completed the upgrades and that the 600 MWs of additional ATC were created.

13 SPP states two reservations were renewals of annual transmission service impacting the Redbud-Arcadia flowgate firm AFC and seven reservations were approvals of redirected paths for previously-approved reservations having some net impact on firm AFC for one or both of the Redbud-Arcadia and Silver Lake-Division flowgates.



27. Redbud argues that the modifying clause “whether or not the McClain Facility was running” means that the upgrades should result in an increase of 600 MWs of ATC above both a base case where the McClain facility is not running and a base case where the McClain facility is running. The latter scenario would result in a total of approximately 1,200 MWs of ATC.14 OG&E argues that its commitment to install the upgrades did not mean that such facilities would add 600 MWs of ATC “on top of” the ATC created when the McClain Facility was running; rather, the mitigation facilities were intended to ensureup to 600 MWs of ATC even if the McClain Facility were running. We note that running the McClain Facility creates counterflow that increases ATC, but the total additional ATC from the upgrades and the additional ATC from running McClain is not the sum of the two, because systems conditions are different.15

28. We find that the purpose of the upgrades was to mitigate the harm to competition resulting from the acquisition of the McClain Facility acquisition by increasing ATC from the Redbud facility into OG&E’s control area. The record supports a finding that as a result of the upgrades, there were 600 MWs of ATC created from the Redbud facility into OG&E’s control area, under the planning studies used by SPP and OG&E.

29. We recognize that, in evaluating requests for transmission service, different modeling techniques can be used depending on the time frame or duration of the request. In general, for requests for long-term service, long-term planning models are used and for shorter-term requests, operational models are used. Planning models start with a base case that contains known system conditions at a given point of time. The model is then modified by incorporating changes that are known or anticipated over the period of time being studied, such as transmission upgrades, generation additions, outages, load growth, and firm transactions. Given the long-term nature of these studies, modeling is a “best guess” as to what the system will look like in the future. The studies are less accurate for time periods that are further out.

30. Operational models also are developed using a base case and incorporate changesthat are known or anticipated over the time period being studied. However, since they are closer to real time and the study period is shorter, they model the system more accurately during that time frame. Factors such as generation and transmission forced outages, weather volatility, and short-term firm transactions are reflected in operational

14 See Redbud’s reply comments at 6 and OG&E’s reply comments at 5.

15 See October 18, 2005, Independent Market Monitoring Report at 35.



models. As a result, operational studies can produce different results than do planning studies that cover the same period, as indicated by SPP’s 2004 and 2005 studies. In the short term, as the result of changing conditions, ATC values can differ from the values a longer-term planning study might have predicted.

31. In SPP’s initial post-technical conference comments, it clarified that, based on subsequent analysis, between 300 and 400 MWs of ATC were actually available during the period of June 30, 2005, to September 2, 2005. We would not expect 600 MWs of short-term ATC to be available, at all times under all actual system conditions, with reservations approved during the period for 400-500 MWs. Based on the planning studies and SPP’s corrected operational study, therefore, we conclude that OG&E fulfilled the conditions of its Offer of Settlement, because the upgrades created at least 600 MWs of ATC, whether or not the McClain facility was running.

32. Our analysis of the additional data provided by the SPP in response to the March 30, 2006 data request finds no evidence that OG&E Power Supply, a marketing affiliate of OG&E, reserved transmission capacity on the Redbud to O&GE path that would have otherwise been available for Redbud’s transaction for 440 MWs of ATC requested from June 28, 2005 through September 3, 2005. There were three OG&E Power Supply confirmed monthly reservations, all requested between April 26, 2005 and June 22, 2005, each for 31 MWs of ATC. These were monthly transactions, executed one at a time during three consecutive months, beginning May 3, 2005 and ending August 1, 2005. That means that the capacity was reserved by OG&E Power Supply for only 31 MWs and only flowed during May, June, and July. Further, the 800 MWs16 of remaining firm ATC on the path between Redbud and OG&E after the Settlement Order mainly was consumed by: (1) Redbud (identified as the transaction’s source) for confirmed transactions sinking into the Westar control area, and (2) various other users requesting redirects and

16 See Clarification to December 16, 2005, Initial Post-Technical Conference Comments of Southwest Power Pool, Inc., dated Feb. 15, 2006, at 4.



renewals.17 Moreover, our analysis of the use of the Redbud-to-Arcadia flowgate showsthat, despite SPP’s denial of service, there was, in fact, ATC into the OG&E service territory in the Summer 2005 time period that was used by competing suppliers, including Redbud.18 We conclude, therefore, that the actual transmission usage data do not indicate that OG&E or its marketing affiliate received any undue preference regarding access to the transmission capacity resulting from the upgrades.

In sum, the Commission finds that OG&E has fulfilled the conditions in the Commission’s Settlement Order, as discussed above.

By the Commission.

( S E A L )

Magalie R. Salas,Secretary.

17 Our analysis of transactions that flowed on two representative days --June 28, 2005, (the Redbud June 28, 2005, request start time), and August 14, 2005, (high loading conditions) -- shows similar results to those reported by SPP. For June 28, 2005, Redbud reservations consumed 344 MWs of firm ATC, while redirects and renewals consumed 247 MWs of ATC. The new requests (received between the Settlement Order, and Redbud’s June 24, 2005, request) totaled 75 MWs of ATC. As result, only 134 MWs of firm ATC was available on June 28, 2005. For August 14, 2005, Redbud reservations consumed 229 MWs of ATC, while redirects and renewals consumed 182 MWs of ATC. The new requests (received between the Settlement Order, and June 24, 2005, Redbud request submission) totaled 26 MWs of ATC. As a result, only 363 MWs of firm ATC was available on August 14, 2005, (data from Supplemental Comments of Southwest Power Pool, Inc., dated May 1, 2006, at 3).

18 See note 17, confirming that, when Redbud requested 440 MWs of ATC, there was a lack of sufficient firm ATC to approve the request because some of the ATC had been reserved by competing suppliers and OG&E Power Supply.


Tab 14

20020411-3019 Received by FERC OSEC 04/11/2002 in Docket#: ER02-1021-000

116 U.S.C. § 824d (1994).

99 FERC ¶ 61, 039 UNITED STATES OF AMERICA


Before Commissioners: Pat Wood, III, Chairman; William L. Massey, Linda Breathitt, and Nora Mead Brownell.

Ontario Energy Trading International Docket No. ER02-1021-000 Corporation

ORDER CONDITIONALLY GRANTING MARKET-BASED RATEAUTHORITY AND GRANTING WAIVERS

(Issued April 11, 2002)

In this order, the Commission grants Ontario Energy Trading International Corp.(Ontario Energy) authorization to sell capacity, energy, and ancillary services, and toresell transmission capacity, at market-based rates. This order also grants OntarioEnergy's requests for certain blanket waivers and authorizations, consistent withCommission precedent. This order will benefit customers in the bulk power marketplaceby expanding supply options while taking all necessary precautions against the abuse ofgeneration and/or transmission market power.

Background

On February 14, 2002, Ontario Energy filed an application under section 205 ofthe Federal Power Act (FPA)1 seeking authority to sell energy, capacity and ancillaryservices, and to resell transmission capacity, at market-based rates under the terms andconditions of its proposed FERC Electric Tariff, Original Volume No. 1. Ontario Energyrequests an effective date of May 1, 2002, consistent with the start-up of open accesscompetition in the Province of Ontario, Canada.

Ontario Energy states that under the Ontario Energy Competition Act of 1998(Ontario Energy Act), Ontario Hydro, a government-owned utility providing generation,transmission, and distribution services in Ontario, transferred its generation and

Docket No. ER02-1021-000 -2-

2Like OPG, all the shares of Hydro One are held in the name of the ProvincialGovernment of Ontario, which appoints the directors of Hydro One. However, there isno overlap of Hydro One's directors with those of OPG, and the "directors, officers andemployees [of OPG and Hydro One] are completely independent of each other." SeeApplication at 1-2. Ontario Energy also states that it is not affiliated with Hydro One andthat the Provincial Government of Ontario has announced its intention to privatize HydroOne through an Initial Public Offering by the end of 2002. Id. at 6.

367 Fed. Reg. 9,262 (2002).

4Promoting Wholesale Competition Through Open Access Non-DiscriminatoryTransmission Services by Pubic Utilities and Recovery of Stranded Costs by Public

(continued...)

transmission assets to Ontario Power Generation Inc. (OPG) and Hydro One, Inc. (HydroOne), respectively.2 Ontario Energy further states that Hydro One was required totransfer operational control over its transmission assets to the Ontario IndependentElectricity Market Operator (IMO), an independently-governed transmission and marketoperator whose duties and functions would be similar to a regional transmissionorganization (RTO) in the United States. Ontario Energy states that it was established asan affiliate of OPG, that it owns no power generation or transmission assets, and that itwill buy and sell electricity as a power marketer.

In support of its application, Ontario Energy submits that it satisfies each of thefactors considered by the Commission in evaluating requests for market-based rateauthority. Specifically, Ontario Energy states that it cannot exercise transmission orgeneration market power, erect barriers to entry, or engage in affiliate abuse or reciprocaldealing.

Notice of Filing and Responsive Pleadings

Notice of Ontario Energy's filing was published in the Federal Register,3 withinterventions and responsive pleadings due on or before March 7, 2002. Motions tointervene were timely filed by the IMO, Consumers Energy Company (Consumers), andthe Ontario Clean Air Alliance (OCAA). Protests were filed by Consumers and OCAA.

Consumers asserts that it is unclear whether Ontario Energy's application satisfiesthe Commission's requirements regarding the exercise of transmission market power,because it is unclear whether an open access transmission tariff satisfying therequirements of Order No. 8884 will be in place in Ontario by May 1, 2002. Consumers

Docket No. ER02-1021-000 -3-

4(...continued)Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. ¶ 31,036(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 (1997), order onreh'g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82FERC ¶ 61,046 (1998), aff'd in part and rev'd in part sub nom.Transmission AccessPolicy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New Yorkv. FERC, 70 U.S.L.W. 4166 (U.S. March 4, 2002).

518 C.F.R. § 385.214 (2001).

6Id. at § 385.213(a)(2).

notes in particular that the IMO's credit requirements are more onerous than those ofUnited States public utility transmission providers. OCAA requests that OntarioEnergy's application be denied, given the failure of OPG (Ontario Energy's parent) tosatisfy the requirements of the Ozone Annex to the 1991 Canada-United States AirQuality Agreement (Ozone Annex). OCAA notes that OPG operates five coal-firedpower plants and that permitting Ontario Energy to sell the power produced by theseplants would give these plants an unfair advantage over U.S. coal-fired facilities whichare, or will be, in compliance with the Ozone Annex. On March 22, 2002, OntarioEnergy filed an answer to Consumers' protest.

Discussion

A. Procedural Matters

Pursuant to Rule 214 of the Commission's Rules of Practice and Procedure,5 thetimely-filed motions to intervene submitted by the IMO, Consumers, and OCAA serve tomake these entities parties to this proceeding. Rule 213(a)(2) of the Commission's Rulesof Practice and Procedure,6 prohibits an answer to a protest, unless otherwise permittedby the decisional authority. We are not persuaded to accept Ontario Energy's answer andtherefore will reject it.

B. Market-Based Rates

The Commission allows power sales at market-based rates if the seller and itsaffiliates do not have, or have adequately mitigated, market power in generation andtransmission and cannot erect other barriers to entry. For an affiliate of a transmission-owning public utility to demonstrate the absence or mitigation of market power, thepublic utility must have on file with the Commission an open access transmission tariff

Docket No. ER02-1021-000 -4-

7E.g., Progress Power Marketing, Inc., 76 FERC ¶ 61,155 at 61,919 (1996), letterorder approving settlement, 79 FERC ¶ 61,149 (1997); Northwest Power MarketingCompany, L.L.C., 75 FERC ¶ 61,281 at 61,889 (1996); accord Heartland EnergyServices, Inc., et al., 68 FERC ¶ 61,223 at 62,060-063 (1994).

8Investigation of Terms and Conditions of Public Utility Market-Based RateAuthorizations, 97 FERC ¶ 61,220 (2001) (November 20 Order), reh'g pending.

997 FERC ¶ 61,219 (2001), reh'g pending.

for the provision of comparable services. The Commission also considers whether thereis evidence of affiliate abuse or reciprocal dealing.7 As we explain below, we find thatOntario Energy's proposed market-based rate tariff meets these standards. Accordingly,we will accept the proposed tariff for filing, without suspension or hearing, to becomeeffective May 1, 2002, as requested.

The Commission's acceptance of Ontario Energy's market-based rate tariff, here, issubject to any tariff condition adopted by the Commission in Docket No. EL01-118-000.8 Within 15 days of the date of issuance of an order adopting a tariff condition inDocket No. EL01-118-000, Ontario Energy is directed to make a compliance filing in theinstant proceeding to amend its tariff accordingly.

1. Generation Market Power

Ontario Energy states that it owns no generation facilities and that the generationmarket power studies it has performed in this case have therefore focused on thegeneration facilities owned by the subsidiaries of Ontario Energy's parent, OPG. OntarioEnergy states that the relevant first tier destination markets include the New York ISO,Michigan and Minnesota. In an order issued November 20, 2001, in AEP PowerMarketing, Inc., et al.,9 the Commission announced a new generation market powerscreen, the Supply Margin Assessment (SMA), to be applied to market-based rateapplications on an interim basis pending a generic review of the new analytical methodsfor analyzing market power. Ontario Energy has submitted an SMA demonstrating thatit cannot exercise generation market power in the destination markets it will serve.Accordingly, we find that Ontario Energy passes the SMA screen in these markets.

2. Transmission Market Power

Ontario Energy states that it owns no transmission facilities and has no affiliationwith any transmission-owning entity. Ontario Energy further states that in the soon-to-be

Docket No. ER02-1021-000 -5-

restructured Ontario energy market, the IMO will provide transmission service on anopen access basis. Consumers challenges these assertions, claiming that it is unclear atthis time whether the IMO will operate the transmission facilities formerly owned byOntario Hydro on a non-discriminatory basis, consistent with the principles enunciatedby the Commission in Order No. 888.

We will deny Consumers' protest. Ontario Energy does not own or operatetransmission facilities, nor is Ontario Energy affiliated with any transmission-owningpublic utilities. The IMO, moreover, is a not-for-profit corporation that will beindependent of any market participant, including OPG and Ontario Energy. Accordingly,we find that there are no transmission market power concerns at issue here.

3. Affiliate Abuse

Ontario Energy states that the Commission's requirements regarding the sale orpurchase of power by and between a market-based rate applicant and a utility affiliatewith a franchise service area does not apply here, where the sales of power to or from anaffiliated Canadian entity are not subject to the Commission's jurisdiction. We agree.

4. Other Barriers to Entry, Reciprocal Dealing, and OtherIsssues

Based on our review of the application, we are satisfied that there are no barriersto entry or reciprocal dealing considerations here since Ontario Energy does not controlsignificant energy resources in the United States.

OCAA asserts in its protest that Ontario Energy's application for market-basedrate authority should be denied due to the asserted failure of OPG to satisfy therequirements of the Ozone Annex. We will deny OCAA's protest. The Commission'sreview of market-based rate applications is made pursuant to the guidelines discussedabove, which do not encompass environmental impact or treaty obligations over whichwe have no jurisdiction.

5. Ancillary Services

Ontario Energy requests authority to engage in market-based sales of certainancillary services (listed in its tariff) in markets administered by PJM Interconnection,

Docket No. ER02-1021-000 -6-

10See, e.g., AES Redondo Beach, LLC, et al., 85 FERC ¶ 61,123 (1998), orderon reh'g, 87 FERC ¶ 61,208, order on reh'g, 88 FERC ¶ 61,096 (1999), order on reh'g, 90FERC ¶ 61,036 (2000); Conectiv Energy Supply, Inc., 91 FERC ¶ 61,076 (2000);Reliant Energy, Inc., et al., order on reh'g, 91 FERC ¶ 61,073 (2000).

1187 FERC ¶ 61,136 (Avista), order on reh'g, 89 FERC ¶ 61,136 (1999).

1218 C.F.R. § 35.1 (2001). See Calhoun Power Company, 96 FERC ¶ 61,056(2001).

13See Enron Power Marketing, Inc., 81 FERC ¶ 61,277 (1997); and SelectEnergy, Inc., 85 FERC ¶ 61,290 (1998).

L.L.C., the New York Independent System Operator, Inc., and ISO New England Inc. Consistent with Commission precedent, we will grant Ontario Energy's request.10

In addition, Ontario Energy requests authority to engage in market-based sales ofancillary services consistent with the requirements regarding optional third-partyancillary services, as set forth in Avista Corporation.11 Consistent with Avista, we willgrant Ontario Energy's request.

Ontario Energy also seeks authority to sell ancillary services in additional marketsas may be authorized by the Commission in the future and to those entities who may beauthorized to make market-based sales in such markets. We will grant Ontario Energy'srequest, subject to the Commission's filing requirements.12

6. Reassignment of Transmission Capacity

Ontario Energy seeks Commission authorization for the reassignment oftransmission capacity. This request is consistent with the Commission's requirementsand will therefore be granted.13

C. Waivers, Authorizations and Reporting Requirements

Ontario Energy is granted waivers and authorizations typically granted to othersellers of power at market-based rates. These waivers and authorizations are granted tothe extent specified in Appendix A. In addition, Ontario Energy must comply with the reporting requirements and other requirements specified in Appendix A.

Docket No. ER02-1021-000 -7-

Ontario Energy is hereby informed of the rate schedule designations, as set forthin the ordering paragraphs below.


(A) Ontario Energy's filing is hereby accepted for filing, as discussed in thebody of this order, to become effective May 1, 2002, as requested.

(B) Ontario Energy's request for waiver of Parts 41, 101 and 141 of theCommission's regulations is hereby granted, as discussed in the body of this order.

(C) Within 30 days of the date of issuance of this order, any person desiring tobe heard or to protest the Commission's blanket approval of issuances of securities orassumptions of liabilities by Ontario Energy should file a motion to intervene or protestwith the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, D.C.20426, in accordance with Rules 211 and 214 of the Commission's Rules of Practice andProcedure, 18 C.F.R. 385.211 and 385.214.

(D) Absent a request to be heard within the period set forth in Order ParagraphC above, Ontario Energy is hereby authorized to issue securities and assume obligationsor liabilities as guarantor, indorser, surety, or otherwise in respect of any security ofanother person; provided that such issue or assumption is for some lawful object withinthe corporate purposes of Ontario Energy, compatible with the public interest, andreasonably necessary or appropriate for such purposes.

(E) Until further order of this Commission, the full requirements of Part 45 ofthe Commission's regulations, except as noted below, are hereby waived with respect toany person now holding or who may hold an otherwise proscribed interlockingdirectorate involving Ontario Energy. Any such person instead shall file a swornapplication providing the following information:

(1) full name and business address; and

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

(F) The Commission reserves the right to modify this order to require a furthershowing that neither the public nor private interests will be adversely affected bycontinued Commission approval of Ontario Energy's issuances of securities orassumptions of liabilities, or by the continued holding of any affected interlocks.

Docket No. ER02-1021-000 -8-

(G) Ontario Energy's request for waiver of the provisions of Subparts B and Cof Part 35 of the Commission's regulations, is hereby granted, with the exception ofsections 35.12(a), 35.13(b), 35.15 and 35.16.

(H) Ontario Energy may file umbrella service agreements for short-term powersales (one year or less) within 30 days of the date of commencement of short-termservice, to be followed by quarterly transaction summaries of specific sales (includingrisk management transactions if they result in actual delivery of electricity). For long-term transactions (longer than one year), Ontario Energy must submit the actualindividual service agreement for each transaction within 30 days of the date ofcommencement of service.

(I) Ontario Energy is hereby directed to file an updated market analysis withinthree years of the date of this order and every three years thereafter.

(J) Ontario Energy is hereby directed to inform the Commission of any changein status that would reflect a departure from the characteristics the Commission has reliedupon in approving market-based pricing.

(K) Ontario Energy is hereby informed of the following rate scheduledesignation: FERC Electric Tariff, Original Volume No. 1, Original Sheet Nos. 1-3,effective May 1, 2002.

By the Commission.

( S E A L )

Linwood A. Watson, Jr., Deputy Secretary.

Docket No. ER02-1021-000 -9-

Appendix A

(1) If requested, waiver of Parts 41, 101, and 141 of the Commission's regulations,with the exception of 18 C.F.R. § 141.14, .15 (2001), is granted. Licensees remainobligated to file the Form No. 80 and the Annual Conveyance Report.

(2) Within 30 days of the date of this order, any person desiring to be heard or toprotest the Commission's blanket approval of issuances of securities or assumptions ofliabilities by those applicants who have sought such approval should file a motion tointervene or protest with the Federal Energy Regulatory Commission, 888 First Street,N.E., Washington, D.C. 20426, in accordance with Rules 211 and 214 of theCommission's Rules of Practice and Procedure, 18 C.F.R. §§ 385.211 and 385.214 (2001).

(3) Absent a request to be heard within the period set forth in Paragraph (2) above,if the applicants have requested such authorization, the applicants are hereby authorizedto issue securities and assume obligations or liabilities as guarantor, indorser, surety, orotherwise in respect of any security of another person; provided that such issue orassumption is for some lawful object within the corporate purposes of the applicants,compatible with the public interest, and reasonably necessary or appropriate for such purposes.

(4) If requested, until further order of this Commission, the full requirements ofPart 45 of the Commission's regulations, except as noted below, are hereby waived withrespect to any person now holding or who may hold an otherwise proscribed interlockingdirectorate involving the applicants. Any such person instead shall file a swornapplication providing the following information:

(a) full name and business address; and

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

(5) The Commission reserves the right to modify this order to require a furthershowing that neither the public nor private interests will be adversely affected bycontinued Commission approval of the applicant's issuances of securities or assumptionsof liabilities, or by the continued holding of any affected interlocks.

(6) If requested, waiver of the provisions of Subparts B and C of Part 35 of theCommission's regulations, with the exception of Sections 35.12(a), 35.13(b), 35.15 and35.16, is granted for transactions under the rate schedules at issue here.

Docket No. ER02-1021-000 -10-

(7) (a) Applicants who own generating facilities may file umbrella serviceagreements for short-term power sales (one year or less) within 30 days of the date ofcommencement of short-term service, to be followed by quarterly transaction summariesof specific sales (including risk management transactions if they result in actual deliveryof electricity). For long-term transactions (longer than one year), applicants must submitthe actual individual service agreement for each transaction within 30 days of the date ofcommencement of service. To ensure the clear identification of filings, and in order tofacilitate the orderly maintenance of the Commission's files and public access todocuments, long-term transaction service agreements should not be filed together withshort-term transaction summaries. For applicants who own, control or operate facilitiesused for the transmission of electric energy in interstate commerce, prices for generation,transmission and ancillary services must be stated separately in the quarterly reports andlong-term service agreements.

(b) Applicants who do not own generating facilities must file quarterly reportsdetailing the purchase and sale transactions undertaken in the prior quarter (includingrisk management transactions if they result in actual delivery of electricity). Applicantswho are power marketers should include in their quarterly reports only those riskmanagement transactions that result in the actual delivery of electricity.

(8) The first quarterly report filed by an applicant in response to Paragraph (7)above will be due within 30 days of the end of the quarter in which the rate schedule ismade effective.

(9) Each applicant must file an updated market analysis within three years of thedate of this order, and every three years thereafter. The Commission reserves the right torequire such an analysis at any time. The applicants must also inform the Commissionpromptly of any change in status that would reflect a departure from the characteristicsthe Commission has relied upon in approving market-based pricing. These include, butare not limited to: (a) ownership of generation or transmission supplies; or (b) affiliationwith any entity not disclosed in the applicant's filing that owns generation or transmissionfacilities or inputs to electric power production, or affiliation with any entity that has afranchised service area. Alternatively, the applicants may elect to report such changes inconjunction with the updated market analysis required above. Each applicant must notifythe Commission of which option it elects in the first quarterly report filed pursuant toParagraph (8) above.

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83 FEEC¶ 6],34 8

UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: James J. Hoecker, Chairman; Vicky A. Bailey, William L. Linda Breathitt,

Massey, ~ and Curt H~bert, Jr.

Ontario Hydro Interconnected ) Markets Inc. )

Docket No. ER97-852-001


(Issued June 30, 1998)

The Commission, in Ontario Hydro Interconnected Markets Inc., 78 FERC ~ 61,369 (1997) (March 31 Order) denied without prejudice Ontario Hydro Interconnected Markets Inc.'s (Ontario Markets) application for authorization to charge market-based rates. In this order, we deny Ontario Markets' request for rehearing of the March 31 Order.

On December 18, 1996, as amended on January 3, 1997 and January 30, 1997, Ontario Markets, a wholly-owned subsidiary of Ontario Hydro, applied to the Commission for authority to sell power at market-based rates. In support thereof, Ontario Markets stated that neither it nor bntario Hydro owns or controls any generation or transmission assets in the United States. Ontario Markets also stated that Ontario Hydro will implement an open access transmission tariff, upon Commission approval of Ontario Markets' market-based rate application, under which Ontario Hydro will provide open access transmission service on a comparable, non-discriminatory basis for wheeling through and out of the Province of Ontario, Canada.

More specifically, Ontario Markets stated that Ontario Hydro ham been unbundling its transmission and generation functions and had created "The Electricity Exchange" (Exchange) that operates a Provincial power pool under which most of the customers within Ontario are supplied. Ontario Markets stated that the Exchange makes purchase decisions based on the price from suppliers both inside and outside of Ontario, including United States suppliers.

In the March 31 Order, we noted that, under our precedent, we apply the same general standards for reviewing requests for market-based rates by United States public utilities to a proposed power marketer affiliated with a Canadian electric utility. In order to demonstrate that it has mitigated transmission market power, the power marketer must be able to show that its transmission-owning utility affiliate offers non-

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discriminatory access to its transmission system that can be used by competitors of the power marketer to reach United States loads, i/ The Commission emphasized, however, that it would consider a variety of approaches when evaluating the market power of foreign utility affiliates of United States power marketers.

The Commission found that Ontario Markets' market-based rate application did not meet the Commission's standards for granting market-based rates because Ontario Markets had not demonstrated that Ontario Hydro's transmission market power has been adequately mitigated. We noted that, inter alla, Ontario Hydro apparently retains day-to-day control over the Provincial power pool and its proposed transmission tariff fails to offer any transmission service into Ontario and only offers recallable "through*' transmission and recallable export transmission for one year or less. The Commission found that these limited services are inadequate to mitigate Ontario Hydro's transmission market power. 2~/ Therefore, the Commission rejected without prejudice Ontario Markets' request for market-based rates.

Ontario Markets raises three arguments on rehearing. First, Ontario Markets argues that the Commission lacks authority under the Federal Power Act (FPA) to require a foreign utility -- Ontario Hydro -- to provide open access transmission services in Canada to United States public utilities as a condition for Ontario Markets to sell power at market-based rates. Ontario Markets contends that section 201 of the FPA expressly limits the Commission's jurisdiction to the transmission of electric energy in interstate commerce and to the sale for resale of electric energy in interstate commerce, where such transmission takes place within the United States. // Ontario Markets contends that the Commission, by requiring open access transmission in a foreign country as a condition for market access in the United Sates, is improperly regulating foreign ("cross-border-) commerce.

The Commission addressed this argument in EJl~t~Lil~l~ ~ . r / ~ , 73 FERC I 61,019 (1995) (~I~_2L~L~). In that case, a power marketer seeking market-based rate authority argued

i/ 78 FERC at 62,528.

2/ Having denied Ontario Markets' application on this basis, the Commission did not reach the questions of generation market power or other barriers to entry/reciprocal dealing and affiliate abuse.

3/ Rehearing Request at 5 (9~i~ 16 U.S.C. § 824 (1994)).

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that the transmission facilities of its foreign utility affiliate (Hydro-Quebec) were beyond the scope of the Commission,s jurisdiction and that the Commission cannot require Hydro-Quebec to mitigate its transmission market power as a condition for granting market-based rate authority to the affiliate. We explained that Hydro-Quebec's transmission facilities were relevant to our analysis of transmission market power and that:

It]he fact that these transmission facilities are located in Canada does not diminish the possibility that Energy Alliance,s competitors may require transmission service from Hydro-Quebec to reach United States markets. The Commission,s concern is not transmission service to serve Canadian loads -- it is transmission to serve United States loads. Entities may wish to locate in Canada, but sell to United States utilities, or entities may wish to market Canadian power in the United States, and they may require Hydro Quebec's transmission service in order to do so. [~/]

Our rationale in ~ applies equally to the situation presented in the instant case. In order to grant Ontario Markets market-based rate authority, we must ensure that its Canadian affiliate does not give Ontario Markets market power in the United States by denying Ontario Markets' competitors market access in the United States, notwithstanding that the affiliate's transmission facilities are located in Canada. As we did in ~ J l ~ , we emphasize that our concern is with transmission access to serve United States loads, not Canadian loads.

We also note that Ontario Hydro raised a similar argument on rehearing of Order No. 888. 5/ It asserted that the Commission, in applying the reciprocity provision of section 6 of the Pro forma tariff to Canadian transmlssion-owning entities, was improperly attempting to regulate foreign entities. While the case before us involves an analysis of market power in the United States, and not application of Order No. 888's reciprocity

~/ 73 FERC at 61,030.

Promoting Wholesale Competition Through Open Access Non- discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (1996), FERC Stats. & Regs. ~ 31,036 at 31,656-57 (1996), ~-~JLJ~I_~, Order No. 888-A, 62 Fed. Reg. 12,274 (1997), FERC Stats. & Regs. ~ 31,048 (1997), ~-~ULJ~Ij~j~, Order No. 888-B, 81 FERC I 61,248 (1997) ~ , Order No. 888-C, 82 FERC ~ 61,046 (1998).

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condition, our legal response in many respects is similar. Order No. 888-A, we soundly rejected the claim that we were regulating foreign utilities:

In

Just as we [in section 6] are not asserting jurisdiction over domestic non-public utilities under sections 205-206 of the FPA, we also are not asserting jurisdiction over foreign entities. Rather, we are simply placing the same reasonable and fair condition on both types of entities' uses of the transmission ordered in the Final Rule. [f~/]

Here, too, we are not asserting jurisdiction over a foreign entity by denying market-based rates to a U.S. public utility whose foreign affiliate can exert market power by denying the marketing affiliate's competitors market access to serve United States loads. Rather, we are asserting jurisdiction over the US. marketing affiliate and we are applying the same standards to this U.S. public utility that we apply to all other U.S. public utilities that are affiliated with transmission owners. Regulation of the U.S. public utility and the conditions under which it is authorized to sell power at market-based rates in the United States clearly is within the scope of our authority under the FPA. It is not the regulation of foreign commerce, as Ontario Markets claims.

Second, Ontario Markets argues that the Commission's requirement that Ontario Hydro provide open access transmission services in Canada to United States public utilities violates the national treatment obligations under the North American Free Trade Agreement (NAFTA) 2/ and the General Agreement on Tariffs and Trade (GATT). ~/ Ontario Markets states that the principle of national treatment requires that the United States place no greater regulatory burden on Canadian companies selling in the United States than is placed on United States companies. Ontario Markets asserts that the Commission's reciprocal market access requirement will result in market access that is less favorable for Canada (unless it provides reciprocal open access) than that afforded the United States's own citizens.

As an initial matter, Ontario Markets again misstates what the Commission has done in the March 31 Order. We have not placed any "requirement" on Ontario Hydro. Instead, using the

l/

Order No. 888-A at 30,292.

32-3 Int'l Legal Materials 682 (1993); 19 U.S.C.A. § et ~9~. (1995 Supp.)(legislation implementing NAFTA).

61 Stat. A5, AI8-AI9 (1947).

3301

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same standards that apply to other U.S. affiliated power marketers that seek authority to sell power at market-based rates, the Commission has determined that the marketer's transmission-owning affiliate has not mitigated market power in the United States. It is up to the marketer and the transmission-owning affiliate to determine whether they want to mitigate market power in order for the marketer to obtain approval to sell power at market-based rates. (We note that the marketer always has the option to sell power at cost-based rates.)

Additionally, in its request for rehearing of Order No. 888 and its motion for stay pending judicial review, Ontario Hydro made a similar NAFTA argument that application of the reciprocity condition of section 6 of the Pro forma tariff to foreign transmission owners would violate NAFTA,s national treatment principle• We rejected this claim in Order No. 888-A:

NAFTA,s national treatment principle requires that each signatory "accord national treatment to the goods,, of other signatories in accordance with Article III of the General Agreement on Tariffs and Trade (GATT). National treatment means that the United States "must not discriminate between foreign and domestic energy on the basis of nationality . . ." and that Canadian electriclty must be treated "no less favorabl[y] than U.S. electricity, under all U.S. laws and rules respecting.the sale, . . • distrlbution, and use of . • electriclty.,, Thus, this Commlsslon must accord Canadian energy supplies treatment that is no less favorable than the treatment accorded United States supplies• Ontario Hydro's interpretation, however, would twist this principle into a requirement that Canadian entities be treated better than United States entities, including United States non-public utilities that are subject to the reciprocity condition.

• • • Under the reciprocity condition, non- public utilities do not have to offer an open access tariff (i.e., a tariff that offers transmission service to any eligible customer), but rather must offer comparable transmission services only to those transmission providers whose open access tariffs the non-public utility uses. The same condition applies to foreign utilities• Thus, Ontario Hydro is in plain error in arguing that application of the reciprocity condition to foreign entities would result in less favorable treatment than that accorded to United States citizens. Ontario Hydro's reading of NAFTA would place transmission-owning Canadian entities (or their corporate affiliates) in a hg~ position than any

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domestic entity; not only would Canadian entities not be subject to the open access requirement, but, unlike domestic non-public utilities, they would be able to use the open access tariffs we have mandated without providing ~ reciprocal service. Ontario Hydro has cited no precedent demonstrating that NAFTA imposes such an unreasonable requirement. [~/]

Here, too, Ontario Markets is in plain error when it argues that our "conditioning" market-based rate authorization on Ontario Hydro mitigating market power in the United States will result in treatment that is less favorable than that accorded to U.S. entities. Indeed, just the opposite is true: were we not to apply the same standards to Ontario Markets and its affiliate, Ontario Hydro, that we apply to all other U.S. utilities and their transmission-owning affiliates, we would place Canadian entities in a better position than comparable domestic entities. That is not what the national treatment principle requires.

Third, Ontario Markets argues that the Commission has failed to apply its own standards for approving the request of a foreign entity to sell power at market-based rates, as set forth in TransAlta Enterprise Corporation, 75 FERC ¶ 61,268 (1996) ( ~ ) . Ontario Markets states that in ~ , the Commission held that it would approve the market-based rate application of a United States affiliate of a Canadian utility, if the utility mitigates its trBnsmission market power through the establishment of a provincial power pool. Ontario Markets believes that its application meets the ~ standards because Ontario Hydro would adequately mitigate its transmission market power by: (1) adopting a tariff for the provision of transmission services through and out of Ontario; (2) agreeing to purchase power from United States entities on a non- discriminatory basis through the Exchange; and (3) adopting standards of conduct similar to those required for United States public utilities.

Ontario Markets is overlooking the significant factual distinctions between its situation and that presented in ~ . As we explained in the March 31 Order, the Commission in ~ found that transmission market power of the applicant's affiliate had been mitigated because, inter alia, the electric utility industry in the Province of Alberta had been restructured with a single-system transmission tariff applicable to virtually all transmission facilities and was administered by

Order No. 888-A at 30,291-92 (footnotes omitted and emphasis in original); see also Order Denying Motion for Stay, Docket Nos. RM95-8-004 and RM94-7-005, 79 FERC ~ 61,367 at 62,542 (1997).

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a newly-created entity (and not by the marketer's electric utility affiliate), and the rates, terms, and conditions of the tariff were independently regulated by a government agency.

In contrast, we found in our March 31 Order that the facts presented in Ontario Markets' application fail to show that Ontario Hydro's transmission market power has been adequately mitigated. We explained that, unlike in the Province of Alberta, there has been no legislative or regulatory restructuring of the electric utility industry in Ontario. Moreover, we noted that the Ontario Provincial power pool, which decides how to dispatch the resources available to Ontario Hydro, was created by and is a division of Ontario Hydro. Although Ontario Markets' application does not make clear the exact legal relationship between Ontario Hydro and the Exchange, Ontario Hydro apparently retains day-to- day control over the Exchange. Therefore, the Commission found that, unlike in ~ , there is no comparable independent regulatory oversight, i~/

On rehearing, Ontario Markets has not provided new information that would indicate that our conclusions as to the factual differences between its situation and that in ~ are in error. Accordingly, we reaffirm our earlier finding that Ontario Hydro's transmission market power has not been adequately mitigated.


Ontario Markets' request for rehearing is hereby denied, as discussed in the body of this order.

By the Commission.

(SEAL)

David P. Boergefs, Acting Secretary.

IQ/ 78 FERC at 62,528-29.

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