2015-03741. Third-Party Provision of Primary Frequency Response Service

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) proposes to revise its regulations to foster competition in the sale of primary frequency response service. Specifically, the Commission proposes to amend its regulations to revise the regulations governing market-based rates for public utilities pursuant to the Federal Power Act (FPA) to permit the sale of primary frequency response service at market-based rates by sellers with market-based rate authority for energy and capacity.

DATES:

Comments are due April 27, 2015.

ADDRESSES:

Comments, identified by docket number, may be filed in the following ways:

• Electronic Filing through http://www.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: Those unable to file electronically may mail or hand-deliver comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426.

Instructions: For detailed instructions on submitting comments and additional information on the rulemaking process, see the Comment Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT:

Rahim Amerkhail (General Information), Federal Energy Regulatory Commission, Office of Energy Policy and Innovation, 888 First Street NE., Washington, DC 20426, [phone].

Gregory Basheda (Market Power Screening Information), Federal Energy Regulatory Commission, Office of Energy Market Regulation, 888 First Street NE., Washington, DC 20426, [phone].

Lina Naik (Legal Information), Federal Energy Regulatory Commission, Office of the General Counsel, 888 First Street NE., Washington, DC 20426, [phone].

SUPPLEMENTARY INFORMATION:

1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy Regulatory Commission (Commission) proposes to revise its regulations to foster competition in the sale of primary frequency response service.^[1] Specifically, the Commission proposes to amend its regulations to revise Subpart H to Part 35 of Title 18 of the Code of Federal Regulations governing market-based rates for public utilities pursuant to the Federal Power Act (FPA) ^[2] to permit the sale of primary frequency response service at market-based rates by sellers with market-based rate authority for energy and capacity.

2. This NOPR is an extension of the policy reforms the Commission started with Order No. 784,^[3] in which, among other things, the Commission revised Part 35 of its regulations to reflect reforms to its policy governing the sale of ancillary services at market-based rates to public utility transmission providers. As discussed in more detail below, the reforms proposed herein are in anticipation of the potential interest in purchase of primary frequency response service from third-parties as a result of a new reliability standard that requires a Balancing Authority to maintain a minimum frequency response obligation.

I. Background

3. The Commission in Order No. 888 ^[4] delineated two categories of ancillary services: those that the transmission provider is required to provide to all of its basic transmission customers ^[5] and those that the transmission provider is only required to offer to provide to transmission customers serving load in the transmission provider's control area.^[6] With respect to the second category, the Commission reasoned that the transmission provider is not always uniquely qualified to provide the services, and customers may be able to more cost-effectively self-supply them or procure them from other entities. The Commission contemplated that third parties (i.e., parties other than a transmission provider supplying ancillary services pursuant to its Open Access Transmission Tariff (OATT) obligation) could provide these ancillary services on other than a cost-of-service basis if such pricing was supported, on a case-by-case basis, by analyses that demonstrated that the seller lacks market power in the relevant product market.^[7]

4. Subsequently, in Avista,^[8] the Commission adopted a policy allowing third-party ancillary service providers that could not perform a market power study to sell certain ancillary services at market-based rates with certain restrictions.^[9]

5. The instant proceeding derives from Order No. 784 in which the Commission found that when appropriate intra-hour transmission scheduling practices are in place, the Avista restrictions need not apply to the sale of Energy Imbalance, Generator Imbalance, Operating Reserve-Spinning and Operating Reserve-Supplemental services, because with those practices in place, the results of the existing market power screens for sales of energy and capacity can also be applied to sales of these ancillary services.^[10]

6. However, the Commission also found in Order No. 784 that the record developed to that point did not support expanding these market-based rate authorizations to include sales of Reactive Supply and Voltage Control (under OATT Schedule 2) (Schedule 2 service) and Regulation and Frequency Response (under OATT Schedule 3) services (Schedule 3 service).^[11] Instead, the Commission allowed market-based rate sales of Schedule 2 and Schedule 3 services to a public utility that is purchasing ancillary services to satisfy its OATT requirements, provided the sale is made pursuant to a competitive solicitation that meets certain specified requirements ^[12] or the sale is made at or below the buying public utility transmission provider's own Schedule 2 or 3 rate, as applicable.^[13] The Commission further stated its intention to gather more information regarding the technical, economic and market issues concerning the provision of these services in a separate proceeding that considers, among other things, the ease and cost-effectiveness of relevant equipment upgrades, the need for and availability of appropriate special arrangements such as dynamic scheduling or pseudo-tie arrangements, and other technical requirements related to the provision of Schedule 2 and Schedule 3 services.^[14]

7. Pursuant to that directive, Commission staff held a workshop on April 22, 2014 to obtain input from interested persons regarding the technical, economic and market issues concerning the provision of Schedule 2 and Schedule 3 services.^[15] Among other things, the workshop explored issues surrounding the sale of these services at market-based rates. Comments submitted in response to the workshop that discussed the characteristics associated with a primary frequency response product indicated that market-based rate sales of such a product are feasible.^[16]

8. Separately, the Commission on January 16, 2014 issued a Final Rule approving reliability standard BAL-003-1 ^[17] under which a Balancing Authority ^[18] must maintain a minimum frequency response obligation.^[19] While most Balancing Authorities should be able to meet the new reliability standard using their own resources,^[20] some may nevertheless be interested in purchasing primary frequency response service from others if doing so would be economically beneficial. Accordingly, the Commission concludes that there could be interest in the near future in voluntary purchases of a primary frequency response product.

9. For the reasons described more fully below, the Commission finds that sales of primary frequency response service at market-based rates should be authorized for entities granted market-based rate authority for sales of energy and capacity.

10. With respect to the remainder of the issues discussed at the workshop and in written comments, the Commission does not see sufficient evidence to support pursuing additional reforms on a generic basis.

II. Discussion

A. Primary Frequency Response Service

11. As explained in Order No. 794, reliable operation of a power system depends on maintaining frequency within predetermined boundaries above and below a scheduled value, which is 60 Hertz (Hz) in North America.^[21] In order to do that, sufficient amounts of primary and secondary frequency response reserves must be maintained to stabilize frequency within an interconnection immediately following the sudden loss of generation or load.

12. Primary frequency response involves the autonomous, automatic, and rapid action of a generator, or other resource, to change its output (within seconds) to rapidly dampen large changes in frequency. Regulation, also known as secondary frequency response, is produced from either manual or automated dispatch from a centralized control system, generally using the communications and control system known as automatic generation control (AGC). In both cases, capacity must be set aside to provide the responses described above.

13. Mechanically, the BAL-003-1 reliability standard provides interconnection-wide primary frequency response obligations for each of the Eastern, Western, Electric Reliability Council of Texas, and Hydro Quebec Interconnections. The interconnection-wide frequency response obligation is then allocated among all of the Balancing Authorities (or Frequency Response Sharing Groups made up of multiple Balancing Authorities) within each interconnection based on the ratio of the Balancing Authority's generation and load to the total interconnection-wide generation and load times the interconnection-wide frequency response obligation, and this value is called the Balancing Authority's Frequency Response Obligation. However, Balancing Authorities are not limited in how they meet the requirements of BAL-003-1; the standard neither prohibits purchases nor requires self-supply.

14. In Order No. 784, the Commission evaluated, among other things, whether the existing market power screens for sales of energy and capacity could be applied to the sale of Schedule 3 service without significant modification.^[22] In Order No. 784, the Commission discussed Schedule 3 without making a distinction between primary frequency response and regulation.

15. However, as noted above, primary frequency response is distinct from regulation; and the April 22, 2014 workshop distinguished between these two services for the purpose of discussing market power issues. While the Commission, in Order No. 888, found that primary frequency response did not merit a separate ancillary service given then-standard industry practices,^[23] we preliminarily find that we can distinguish between primary frequency response and regulation for the purposes of considering how the transmission provider may procure the services it must offer under OATT Schedule 3.

16. Specifically, following the approval of the new BAL-003-1 Frequency Response and Frequency Bias Setting Reliability Standard, it is now appropriate to consider the possibility that entities may wish to undertake voluntary sales of primary frequency response service as a stand-alone product distinct from regulation service. The Commission anticipates that sales of such a product would involve bilateral transactions by sellers and, while such sales could be made at cost-based rates, many sellers may prefer the administrative ease of market-based rates. Accordingly, provision would need to be made for sales of primary frequency response within the Commission's market-based rate program.

17. The Commission analyzes below the horizontal market power issues relevant to a primary frequency response product.

B. The Existing Market Power Analyses

18. The Commission analyzes horizontal market power ^[24] for sales of energy and capacity using two indicative screens, the wholesale market share screen and the pivotal supplier screen, to identify sellers that raise no horizontal market power concerns and can otherwise be considered for market-based rate authority.^[25] The wholesale market share screen measures whether a seller has a dominant position in the relevant geographic market in terms of the number of megawatts of uncommitted capacity owned or controlled by the seller, as compared to the uncommitted capacity of the entire market.^[26] A seller whose share of the relevant market is less than 20 percent during all seasons passes the wholesale market share screen.^[27] The pivotal supplier screen evaluates the seller's potential to exercise horizontal market power based on the seller's uncommitted capacity at the time of annual peak demand in the relevant market.^[28] A seller satisfies the pivotal supplier screen if its uncommitted capacity is less than the net uncommitted supply in the relevant market.^[29]

19. Passing both the wholesale market share screen and the pivotal supplier screen creates a rebuttable presumption that the seller does not possess horizontal market power; failing either screen creates a rebuttable presumption that the seller possesses horizontal market power.^[30] A seller that fails one of the screens may present evidence, such as a delivered price test, to rebut the presumption of horizontal market power.^[31] In the alternative, a seller may accept the presumption of horizontal market power and adopt some form of cost-based mitigation.^[32]

20. Three of the key components of the analysis of horizontal market power are the definition of products, the determination of appropriate geographic scope of the relevant market for each product, and the identification of the uncommitted generation supply within the relevant geographic market. In Order No. 697, the Commission adopted a default relevant geographic market for sales of energy and capacity.^[33] Specifically, the Commission generally uses a seller's Balancing Authority area plus directly interconnected Balancing Authority areas, or the RTO/ISO market as applicable, as the default relevant geographic market. However, where the Commission has made a specific finding that there is a submarket within an RTO, that submarket becomes the default relevant geographic market for sellers located within the submarket for purposes of the market-based rate analysis. The Commission also provided guidance as to the factors the Commission will consider in evaluating whether, in a particular case, to adopt an alternative larger or smaller geographic market instead of relying on the default geographic market.^[34]

C. Applicability of Existing Indicative Screens to Primary Frequency Response Service

21. The Commission has considered whether passing the market-based rate screens for energy and capacity described above should create a rebuttable presumption that the seller lacks horizontal market power for sales of primary frequency response service. As discussed below, the Commission believes it should.

22. As described above, primary frequency response service involves the autonomous, automatic, and rapid reaction of an individual turbine-generator or other resource to change its output to rapidly dampen changes in interconnection-wide frequency. With respect to the technical capability of resources to provide such response, essentially all synchronous resources and some non-synchronous resources have governors or equivalent control equipment capable of autonomous and automatic responses such as those necessary for primary frequency response.^[35] The only real difference among resources in this regard involves the choice of settings applied to that equipment, where settings can range from those that result in appropriate levels of primary frequency response to those that result in no response at all, or even responses that worsen the situation. However, such settings can be changed on short notice, thus enabling resources that have never provided primary frequency response in the past to quickly begin providing it if there is some reason and incentive to do so. Accordingly, the set of resources technically capable of providing primary frequency response service does not differ significantly from the set of resources represented in the existing market power screens.

23. With respect to the geographic market, the frequency of an interconnection is uniform throughout that interconnection and is determined largely by the dynamic interconnection-wide balance of supply with demand. Large contingency events, such as the unexpected loss of large amounts of generation or load, which happen anywhere within a given interconnection, cause deviations from the target 60Hz frequency that propagate throughout that interconnection. Accordingly, primary frequency response service can be effectively supplied by any resource throughout an interconnection and have the same ability to dampen harmful changes in interconnection-wide frequency.^[36] Therefore, the geographic market for a primary frequency response product could be the entire interconnection within which the buyer resides, and in any event would be no smaller than the geographic market represented in the existing market power screens.

24. With respect to potential barriers related to transmission scheduling or reservation, while information sharing arrangements will certainly be necessary between buyers and sellers to enable the buyers to rely on purchased resources to meet their frequency response obligations under BAL-003-1, primary frequency response service should not require any transmission reservation or scheduling, even for sales from resources in a different Balancing Authority area. This is because individual frequency responses, by definition,^[37] would not be sustained for long enough periods to trigger a need for transmission service or schedule changes. Rather, regulation resources dispatched by balancing authorities would be expected to assume responsibility for returning the system to the target 60Hz frequency as soon as the central dispatch system is able to send appropriate dispatch signals and the dispatched resources are able to respond.

25. The AGC signals used for that dispatch are generally issued every 2-6 seconds, and actual response from dispatched resources is a gradual process on a scale of minutes due to the inherent ramping constraints of each resource; for example, PJM Interconnection, L.L.C. requires a maximum response time of 5 minutes, and certain regions may allow up to 10 minutes. Accordingly, the expectation would be for primary frequency response to gradually decline over a span of 1 to 10 minutes as regulation resources ramp up to their designated output.^[38] As such, this short period of time means that transmission scheduling and reservation should not be needed in connection with the provision of the temporary, autonomous changes in output associated with primary frequency response service that would in all normal cases be quickly replaced by regulation service.^[39]

26. Accordingly, there should be no barriers related to transmission scheduling or reservation preventing sellers anywhere within the same interconnection as the buyer from providing effective primary frequency response service to that buyer.

III. Proposal

27. For the reasons discussed above, the Commission concludes that passage of the existing market-based rate screens for sales of energy and capacity can adequately demonstrate lack of market power for sales of primary frequency response service.

28. The Commission, therefore, proposes that sellers passing the existing market power screens should be permitted to sell primary frequency response service at market-based rates. As a result, we propose to revise our regulations governing market-based rate authorizations to provide that sellers passing the existing market-based rate screens in a given geographic market should be granted a rebuttable presumption that they lack horizontal market power for sales of primary frequency response service in that market. Specifically, section 35.37 of the Commission's regulations would be revised to state that a seller would have a rebuttable presumption it lacks market power with respect to sales of energy, capacity, energy imbalance service, generator imbalance service, and primary frequency response service if the seller passes the indicative screens for that geographic market. The Commission preliminarily concludes that expanding the rebuttable presumption adopted in Order No. 697 for energy and capacity to include primary frequency response service provides adequate protection that market-based rates charged by public utilities will be just and reasonable and not unduly discriminatory or preferential.

29. Any entity selling primary frequency response service, either at market-based or cost-based rates, will be required to report such sales in the Electric Quarterly Report. Accordingly, the Commission proposes to update its Electric Quarterly Report system to include a specific product name option for primary frequency response service.

30. The Commission seeks comment on this proposal, including the proposed revisions to section 35.37(c)(1) of our regulations. Comments may address, among other things, any unique technical requirements or limitations that might apply to the provision of primary frequency response service, and the Commission's proposal to extend the rebuttable presumption to primary frequency response service.

IV. Summary of Compliance and Implementation

31. In Order No. 697, the Commission provided standard tariff provisions that sellers must include in their market-based rate tariffs to the extent they are applicable based on the services provided by the seller,^[40] including a provision for sales of ancillary services as a third-party provider.^[41] The Commission proposes to revise the “Third Party Provider” ancillary services provision filed by utilities in their market-based rate tariffs to change the reference to “Regulation and Frequency Response Service” to “Regulation Service” and to add a reference to “Primary Frequency Response Service.” The proposed new language is as follows:

Third-party ancillary services: Seller offers [include all of the following that the seller is offering: Regulation Service, Reactive Supply and Voltage Control Service, Energy and Generator Imbalance Service, Operating Reserve-Spinning, Operating Reserve-Supplemental, and Primary Frequency Response Service]. Sales will not include the following: (1) Sales to an RTO or an ISO, i.e., where that entity has no ability to self-supply ancillary services but instead depends on third parties; and (2) sales to a traditional, franchised public utility affiliated with the third-party supplier, or sales where the underlying transmission service is on the system of the public utility affiliated with the third-party supplier. Sales of Operating Reserve-Spinning and Operating Reserve-Supplemental will not include sales to a public utility that is purchasing ancillary services to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers, except where the Commission has granted authorization. Sales of Regulation Service and Reactive Supply and Voltage Control Service will not include sales to a public utility that is purchasing ancillary services to satisfy its own open access transmission tariff requirements to offer ancillary services to its own customers, except at rates not to exceed the buying public utility transmission provider's OATT rate for the same service or where the Commission has granted authorization.

32. The Commission proposes that a seller that already has market-based rate authority as of the effective date of the Final Rule issued in this proceeding would be authorized as of the effective date of the Final Rule to make sales of primary frequency response service at market-based rates. Such a seller would be required to revise the third-party provider ancillary services provision of its market-based rate tariff to reflect that it wishes to make sales of primary frequency response service at market-based rates. However, while this authorization would be effective for sellers with existing market-based rate authority as of the date specified in a Final Rule in this proceeding, the Commission proposes that such sellers may wait to file this tariff revision until the next time they make a market-based rate filing with the Commission, such as a notice of change in status filing or a triennial update.

V. Information Collection Statement

33. The Paperwork Reduction Act (PRA) ^[42] requires each federal agency to seek and obtain Office of Management and Budget (OMB) approval before undertaking a collection of information directed to ten or more persons or contained in a rule of general applicability. OMB regulations require approval of certain information collection requirements imposed by agency rules.^[43] Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of an agency rule will not be penalized for failing to respond to the collection of information unless the collection of information displays a valid OMB control number.

34. The Commission will submit the proposed revised information collection requirements to OMB for its review and approval. The Commission solicits public comments on its need for this information, whether the information will have practical utility, the accuracy of burden and cost estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques.

35. Burden Estimate and Information Collection Costs: While, to the Commission's knowledge, no entity currently sells primary frequency response service on an unbundled basis,^[44] there is no reason why primary frequency response service could not be sold today under cost-based rates. Such cost-based sales, if they occurred, would face all of the burdens associated with cost-of-service regulation, including a variety of requirements from which market-based rate sellers frequently seek and are granted waiver.^[45] Furthermore, just like market-based rate sellers, cost-based rate sellers must report all transactions in the Electric Quarterly Report. Accordingly, the Commission views this NOPR as providing potential market-based rate sellers of primary frequency response service with the opportunity to avoid cost-of-service regulation for such sales and the associated substantial reporting burdens.

36. Below, we discuss the expected increases in burdens as a result of the proposals in this NOPR, which we expect to be greatly outweighed by the reduction in burden from avoiding cost-of-service regulation. The additional estimated annual public reporting burdens and costs for the requirements in this proposed rule are as follows.

Changes Proposed in NOPR in RM15-2 ⁴⁶

Number of respondents	Annual number of responses per respondent	Total number of responses	Average burden & cost per response	Total annual burden hours & total annual cost	Cost per response
(a)	(b)	(a) × (b) = (c)	(d)	(c) × (d) = (e)	(e)/(c)
FERC-516 (Electric Rate Schedules and Tariff Filings) (one time, phased in)
1,551 47	48 0.166	258	6, $432	1,548, $111,456	$432
FERC-920 (Electric Quarterly Report) (one-time, phased in)
1,551	49 0.166	258	2, $144	516, $37,152	144

Action: Proposed changes.

OMB Control Nos.: 1902-0096 (FERC-516) and 1902-0255 (FERC-920).

Respondents: Public utilities, FERC licensees.

Frequency of responses: One-time (FERC-516) and (FERC-920).

Necessity of the Information: Regarding FERC-516, section 205(c) of the Federal Power Act requires public utilities to file with the Commission schedules showing all rates and charges for any transmission or sale subject to the Commission's jurisdiction. Accordingly, entities wishing to sell primary frequency response service at market-based rates must amend their market-based rate tariffs to include the language included in this NOPR. Regarding FERC-920, the Commission is revising the EQR to ensure that public utilities that may sell primary frequency response service at market-based rates report those sales in the EQR, consistent with their filing obligations under section 205(c).

Internal Review: The Commission has reviewed the requirements associated with the proposed revisions to the information collections and determined they are necessary to ensure that rates remain just, reasonable, and not unduly discriminatory.

37. These requirements conform to the Commission's need for efficient information collection, communication, and management within the energy industry. The Commission has assured itself, through internal review, that there is specific, objective support for the burden estimates associated with the information collection requirements.

38. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director], email: [e-mail], Phone [phone], fax: [phone]. Comments on the collections of information and associated burden estimates in the proposed rule should be sent to the Commission in this docket and may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments to OMB should be submitted by email to: [e-mail]. Please refer to OMB Control No. 1902-0096 (FERC-516) and OMB Control No. 1902-0255 (FERC-920).

VI. Environmental Analysis

39. 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.^[50] The Commission concludes that neither an Environmental Assessment nor an Environmental Impact Statement is required for this Final Rule under section 380.4(a)(15) of the Commission's regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale subject to the Commission's jurisdiction, plus the classification, practices, contracts, and regulations that affect rates, charges, classifications, and services.^[51]

VII. Regulatory Flexibility Act

40. The Regulatory Flexibility Act of 1980 (RFA) ^[52] generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities.

41. The Small Business Administration's (SBA) Office of Size Standards develops the numerical definition of a small business.^[53] The SBA recently revised its size standard for electric utilities (effective January 22, 2014) from a standard based on megawatt hours to a standard based on the number of employees, including affiliates.^[54] Under SBA's current size standards, the entities with market-based rates which are affected by this NOPR likely come under the following categories ^[55] with the indicated thresholds (in terms of number of employees ^[56] ):

• Hydroelectric Power Generation, 500 employees
• Fossil Fuel Electric Power Generation, 750 employees
• Nuclear Electric Power Generation, 750 employees
• Solar Electric Power Generation, 250 employees
• Wind Electric Power Generation, 250 employees
• Geothermal Electric Power Generation, 250 employees
• Biomass Electric Power Generation, 250 employees
• Other Electric Power Generation, 250 employees

42. The categories for the applicable entities have a size threshold ranging from 250 employees to 750 employees. For the analysis in this proposed rule, we are using the threshold of 750 employees for all categories. We anticipate that a maximum of 82 percent of the entities potentially affected by this NOPR are small. In addition, we expect that not all of those entities will be able to or will choose to offer primary frequency response service.

43. Based on the estimates above in the Information Collection section, we expect a one-time cost of $576 (including the burden cost related to filing both the tariff and the EQR) for each entity that decides to offer primary frequency response service.

44. The Commission does not consider the estimated cost per small entity to impose a significant economic impact on a substantial number of small entities. Accordingly, the Commission certifies that this NOPR will not have a significant economic impact on a substantial number of small entities.

VIII. Comment Procedures

45. 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 April 27, 2015. Comments must refer to Docket No. RM15-2-000, and must include the commenter's name, the organization they represent, if applicable, and their address in their comments.

46. 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 in a scanned format. Commenters filing electronically do not need to make a paper filing.

47. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE., Washington, DC 20426.

48. 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.

IX. Document Availability

49. 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 the Commission's Home Page (http://www.ferc.gov) and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A, Washington, DC 20426.

50. From the Commission'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.

51. User assistance is available for eLibrary and the Commission's Web site during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at [e-mail], or the Public Reference Room at [phone], TTY [phone]. Email the Public Reference Room at [e-mail].

List of Subjects in 18 CFR Part 35

• Electric power rates; Electric utilities; Reporting and recordkeeping requirements

Issued: February 19, 2015.

By direction of the Commission.

Nathaniel J. Davis, Sr.,

Deputy Secretary.

In consideration of the foregoing, the Commission proposes to amend Part 35, Chapter I, Title 18, Code of Federal Regulations, as follows.

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

2. Revise § 35.37(c)(1) to read as follows:

§ 35.37

Market power analysis required.

* * * * *

(c)(1) There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of energy, capacity, energy imbalance service, generation imbalance service, and primary frequency response service if it passes two indicative market power screens: a pivotal supplier analysis based on annual peak demand of the relevant market, and a market share analysis applied on a seasonal basis. There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of operating reserve-spinning and operating reserve-supplemental services if the Seller passes these two indicative market power screens and demonstrates in its market-based rate application how the scheduling practices in its region support the delivery of operating reserve resources from one balancing authority area to another. There will be a rebuttable presumption that a Seller possesses horizontal market power with respect to sales of energy, capacity, energy imbalance service, generation imbalance service, operating reserve-spinning service, operating reserve-supplemental service, and primary frequency response service if it fails either screen.

* * * * *

Footnotes

1.  As envisioned in this NOPR, primary frequency response service would be a reserve product that involves dedicating capacity on a generator or other resource for autonomous, automatic, and rapid action to change its output (within seconds) to rapidly dampen large changes in frequency.

2.  16 U.S.C. 824d, 824e (2012).

3.  Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, 78 FR 46,178 (July 30, 2013), FERC Stats. & Regs. ¶ 31,349, at PP 6-7 (2013), order on clarification, Order No. 784-A, 146 FERC ¶ 61,114 (2014).

4.  See 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, FERC Stats. & Regs. ¶ 31,036 (1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, 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 in relevant 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).

5.  The first category consists of Scheduling, System Control and Dispatch service and Reactive Supply and Voltage Control from Generation Sources service.

6.  The second category consists of Regulation and Frequency Response service, Energy Imbalance service, Operating Reserve-Spinning service, and Operating Reserve-Supplemental service. Order No. 890 later added an additional ancillary service to this category: Generator Imbalance service. See Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 85, order on reh'g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC ¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).

7.  Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,720-21.

8.  Avista Corp., 87 FERC ¶ 61,223, at 61,882, order on reh'g, 89 FERC ¶ 61,136 (1999) (Avista). Outside the markets operated by regional transmission organizations and independent system operators, Avista authorizes suppliers who cannot show a lack of market power with respect to certain ancillary services to nevertheless sell such services, subject to certain restrictions. One such restriction is that the authorization provided by Avista does not apply to sales to a public utility that is purchasing ancillary services to satisfy its own OATT requirements to offer ancillary services to its own customers.

9.  These ancillary services included: Regulation and Frequency Response, Energy Imbalance, Operating Reserve-Spinning, and Operating Reserve-Supplemental. The Commission did not extend this Avista policy to Reactive Supply and Voltage Control from Generation Sources service, which means that third parties wishing to sell this ancillary service at market-based rates would be required to present specific evidence of a lack of market power in the provision of this specific product before the Commission would authorize sales of this service at market-based rates. The Commission also did not extend the Avista policy to Scheduling, System Control and Dispatch service. Because only balancing area operators can provide this ancillary service, it does not lend itself to competitive supply.

10.  Because energy and generator imbalance services merely require the ability to respond to dispatch within the hour, the Commission found that any sub-hourly transmission scheduling interval would be sufficient. Order No. 784-A, 146 FERC ¶ 61,114 at P 12. Because the operating reserve services require more rapid response within the hour (spinning reserves must be available immediately and supplemental reserves must be available within a short period of time), the Commission required potential sellers of operating reserve services to satisfactorily explain, in their market-based rate applications, how the particular intra-hour transmission scheduling practices or other protocols in their regions permit resources in one balancing area to respond to contingencies in a neighboring balancing area within these tight time frames. Order No. 784-A, 146 FERC ¶ 61,114 at PP 13-15.

11.  Order No. 784, FERC Stats. & Regs. ¶ 31,349 at PP 59-61.

12.  Id. PP 99-101.

13.  Id. PP 82-85.

14.  Id. P 61.

15.  See Third-Party Provision of Reactive Supply and Voltage Control and Regulation and Frequency Response Services, Final Agenda, Docket No. AD14-7-000 (Apr. 22, 2014).

16.  For example, most commenters echoed EEI's arguments that virtually all generators can provide primary frequency response, and because it is provided at the interconnection level, balancing authority areas have more flexibility on the location of the resource than they would for other products. See, e.g., Edison Electric Institute Post-Workshop Comments, Docket No. AD14-7-000, at 7-8 (filed June 3, 2014).

17.  Reliability standards proposed by the North American Electric Reliability Corporation (NERC) are subject to the Commission's jurisdiction under section 215 of the Federal Power Act; 16 U.S.C. 824o(d). The Commission has authority to approve or reject such standards, and to enforce those that are approved.

18.  The NERC Glossary defines a Balancing Authority as “(t)he responsible entity that integrates resource plans ahead of time, maintains load-interchange-generation balance within a Balancing Authority Area, and supports Interconnection frequency in real time.” See http://www.nerc.com/​pa/​Stand/​Glossary%20of%20Terms/​Glossary_​of_​Terms.pdf.

19.  See Frequency Response and Frequency Bias Setting Reliability Standard, Order No. 794, 146 FERC ¶ 61,024 (2014).

20.  Id. PP 62-63.

21.  Id. P 6.

22.  Order No. 784, FERC Stats. & Regs. ¶ 31,349 at PP 59-61.

23.  Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,707.

24.  18 CFR 35.37(b) (2014).

25.  See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at PP 13, 62. See also 18 CFR 35.37(b), (c)(1) (2014).

26.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 43.

27.  Id. PP 43-44, 80, 89.

28.  18 CFR 35.37(c)(1) (2014).

29.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 42.

30.  18 CFR 35.37(c)(1) (2014).

31.  18 CFR 35.37(c)(2) (2014). For purposes of rebutting the presumption of horizontal market power, sellers may use the results of the delivered price test to perform pivotal supplier and market share analyses and market concentration analyses using the Herfindahl-Hirschman Index (HHI). The HHI is a widely accepted measure of market concentration, calculated by squaring the market share of each firm competing in the market and summing the results. The Commission has stated that a showing of an HHI less than 2,500 in the relevant market for all season/load periods for sellers that have also shown that they are not pivotal and do not possess a market share of 20 percent or greater in any of the season/load periods would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from intervenors. Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 111.

32.  18 CFR 35.37(c)(3) (2014).

33.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 15.

34.  A necessary condition that must be satisfied to justify an alternative market is a demonstration regarding whether there are frequently binding transmission constraints during historical peak seasons examined in the screens and at other competitively significant times that prevent competing supply from reaching customers within the proposed alternative geographic market. Id. P 268.

35.  See, e.g., Kosterev Statement, Docket No. AD14-7-000 Workshop Transcript, at 180 (Apr. 22, 2014) (“. . . every synchronous machine has a governor”).

36.  See, e.g., Edison Electric Institute Post-Workshop Comments, Docket No. AD14-7-000, at 8 (filed June 3, 2014).

37.  Primary frequency response service would entail the setting aside of some amount of capacity dedicated to providing autonomous frequency response, and the actual autonomous responses to predefined levels of frequency deviation. While the capacity would be set aside for extended periods, the actual autonomous responses would be of very short duration, as explained in the next section of the text.

38.  When some event causes a sudden and large drop (or increase) in system frequency across the interconnection in question, all of the frequency-responsive resources maintained by Balancing Authorities in that interconnection will automatically and autonomously begin to respond within fractions of a second to try to arrest the deviation in frequency. Within 2-6 seconds after that, each Balancing Authority's AGC system will begin issuing dispatch instructions to regulation resources to try to reverse the deviation in frequency and return the interconnection-wide system frequency to 60Hz, and those regulation resources, depending upon their ramping capabilities, may take up to 10 minutes or so to reach their full dispatched levels. At this point, they should have fully displaced the autonomous primary frequency response resources that initially reacted to slow and arrest the frequency deviation.

39.  As relevant to the topic of this order, such frequency responsive reserves (resources set aside to provide primary frequency response) may include both resources owned by the Balancing Authorities and resources purchased from other entities anywhere within the same interconnection. For remote resources within the same interconnection, arrangements will have to be made for sharing telemetry data from the resources in order to allow the host Balancing Authority to demonstrate that it met its frequency response obligation, and for ACE accounting purposes, but such telemetry sharing should not pose any significant barrier to the use of remote resources for the purposes of market-based rates here.

40.  Order No. 697, FERC Stats. & Regs. ¶ 31,252 at Appendix C.

41.  In Order No. 784, the Commission revised the standard third party provider provision to reflect the changes adopted in Order No. 784. Order No. 784, FERC Stats. & Regs. ¶ 31,349 at P 200.

42.  44 U.S.C. 3501-3520.

43.  See 5 CFR 1320.10 (2014).

44.  It is likely that some customers purchase primary frequency response service along with other services on a bundled basis, such as through full requirements contracts, but this NOPR is focused on unbundled sales of primary frequency response service.

45.  For example, the need to maintain Open Access Transmission Tariffs and Open Access Same-Time Information Systems related to any jurisdictional transmission facilities owned by the entity, the need to adhere to the Commission's standards of conduct, the need to adhere to the detailed cost-of-service related requirements of subparts B and C of Part 35 of the Commission's regulations, the need to adhere to the accounting and reporting requirements of Parts 41, 101, and 141 of the Commission's regulations, and the need to seek separate authorizations for issuances of securities and assumptions of liabilities under FPA section 204 and Part 34 of the Commission's regulations.

46.  We think that industry staff members are similarly situated to FERC, in terms of hourly cost per full time employee. Therefore, the estimated average hourly cost (salary plus benefits) is $72.00.

47.  The 1,551 respondent universe includes existing sellers (1,965 total market-based rate sellers—697 Category 1 sellers + 70 Category 1 sellers = 1,338 sellers estimated to sell primary frequency response services) plus 213 new market-based rate applicants (as estimated in Docket No. RM14-14). (We estimate that ten percent (or 70, as indicated above) of the Category 1 sellers may choose to sell primary frequency response services.)

48.  We expect respondents to enter the primary frequency response market gradually. For each of the next three years, we expect all 213 new market-based rate applicants per year (or 639 total during Years 1-3), to include the primary frequency response language in their tariffs.

Additionally, during the three-year period, we expect a total of ten percent of the existing 1,338 respondents (or 134 respondents), to decide to sell primary frequency response services and to make the corresponding FERC-516 rate filing. The corresponding annual estimate is 45 of the existing respondents (an average of 3.3% annually). Therefore, the annual estimate, including both new respondents and existing respondents, is an average of 258 (213 + 45) respondents and responses per year.

49.  As respondents decide to sell primary frequency response services, they would report the new offering in their Electric Quarterly Report (FERC-920), and would continue to report in subsequent EQRs. When a filer adds the new service, we estimate the one-time burden to be two hours. We expect any additional burden associated with reporting the new service in the EQR to be negligible after the first implementation as it would become part of the respondent's normal reporting practice in the EQR and would only involve selecting the `primary frequency response' option from a list of product names. On average, we expect filers of the new primary frequency response service to phase in:

• Year 1, 258 respondents or 16.6 percent of EQR filers.
• Year 2, 258 respondents or 16.6 percent of EQR filers.
• Year 3, 258 respondents or 16.6 percent of EQR filers.

50.  Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 1986-1990 ¶ 30,783 (1987).

51.  18 CFR 380.4(a)(15) (2014).

52.  5 U.S.C. 601-612 (2012).

53.  13 CFR 121.101 (2014).

54.  SBA Final Rule on “Small Business Size Standards: Utilities,” 78 FR 77,343 (Dec. 23, 2013).

55.  13 CFR 121.201, Sector 22, Utilities.

56.  SBA's regulations at 13 CFR 121.201 state that “[t]he number of employees . . . indicates the maximum allowed for a concern and its affiliates to be considered small.”