UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Hudson Transmission Partners, LLC)

v.)Docket No. EL12-98-000

New York Independent System Operator, Inc.)

ANSWER OF THE NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.
Pursuant to Rule 213 of the Commission’s Rules of Practice and Procedure,1 and the September 14, 2012 Notice of Extension of Time, the New York Independent System Operator, Inc. (“NYISO”) respectfully submits this answer to the August 3, 2012 Complaint of Hudson Transmission Partners, LLC (“Complaint”). The Complaint must be denied because Hudson Transmission Partners, LLC (“Complainant”) has not met its burden of proof under the Federal Power Act. Complainant has not shown that the NYISO violated or “improperly implemented”2 its tariff or otherwise acted unjustly or unreasonably, or in an unduly discriminatory manner. The NYISO correctly determined that Complainant’s merchant transmission project (“HTP
Project”) would be subject to Offer Floor3 mitigation upon entry.

The NYISO has not made any “arbitrary and unreasonable assumptions” or taken any
steps that are unreasonable, or unduly discriminatory,4 with respect to merchant transmission

1 18 C.F.R. § 385.213 (2012).

2 Complaint at 1.

3 Terms with initial capitalization that are not otherwise defined herein have the meaning set forth in the NYISO’s Market Administration and Control Area Services Tariff (Services Tariff), as modified by Commission’s June 22, 2012 Order (Astoria Generating Company, L.P., et al. v. New York Independent System Operator, Inc., 139 FERC ¶ 61,244 (2012)), and accordingly as described in the NYISO’s August 6, 2012 compliance filing in Docket No. ER12-2414-001 If not defined therein, the term shall have the meaning set forth in the Open Access Transmission Tariff (“OATT”).

4 Complaint at 3.

facilities. Nor is there any basis for Complainant’s allegations of systematic bias against the
HTP Project.5 Contrary to Complainant’s assertions,6 subjecting the HTP Project to an Offer
Floor7 is entirely consistent with the NYISO’s capacity market design and sound economic
theory.

Complainant likewise has not shown that it should be compensated in the NYISO-

administered markets for the “reliability benefits” that it claims might arise due to the existence of the HTP Project. This request is inherently inappropriate given the Commission’s clear policy that merchant transmission developers are to bear all of the risks of their investments. In
addition, such compensation would not be justified, is not legally required, and would be
inconsistent with both precedent and the design of the NYISO-administered markets. Granting
the request would substantially limit the effectiveness and possibly even defeat the purpose of
the New York City (“In-City”) buyer-side market power mitigation measures8 (“BSM Rules”),
i.e., to discourage uneconomic entry.9

The Complaint challenges the buyer-side mitigation determination that the NYISO made
for the HTP Project dated December 22, 2011.10 On June 22, 2012 the Commission issued an

5 Id. at 29.

6 Id. at 3.

7 As explained in Docket No. ER11-3017, the HTP Project will have to transfer rights to its

rightsholder(s) and cannot directly participate in the ICAP market. References in the Answer to the HTP Project participating in the ICAP market are not intended to suggest that its direct participation is
permissible. It is the NYISO’s understanding that the holder(s) of Unforced Capacity Deliverability Rights (“UDRs”) associated with the HTP Project will be participating in the market.

8 The BSM Rules are set forth at section 23.4.5.7 of Attachment H to the NYISO’s Market Administration and Control Area Services Tariff (“Services Tariff”).

9 See New York Independent System Operator, Inc., 122 FERC ¶ 61,211 at P 100 (2008) (“March 2008 Order”) (accepting NYISO’s proposed BSM Rules “in order to prevent uneconomic entry that
would reduce prices in the NYC capacity market below just and reasonable levels.”).

10 The Complaint also questions the preliminary determinations the NYISO made concurrent with the Class Year process, beginning on June 9, 2011.

order in Docket No. EL11-42-000 (“June 22 Order”)11 that generally denied a complaint

concerning the NYISO’s administration of the BSM Rules. The June 22 Order required the

NYISO to retest certain projects for which it had previously made determinations under the BSM
Rules.12

In general, the June 22 Order required that the NYISO utilize certain escalation factors and inflation rates in the retest.13 The NYISO also concluded that the Commission’s
September 10 order in Docket No. EL11-50 (“EL11-50 September 10 Order”),14 required it to apply to the HTP Project the financing assumption for the proxy unit used to establish the New York City ICAP Demand Curve in the analysis.15 Also as supported by the MMU,16 the NYISO adjusted net energy revenues to account for prices at the 345 kV level,17 which the EL11-50
September 10 Order had found to be reasonable.18

11 Astoria Generating Company, L.P., et al. v. New York Independent System Operator, Inc., 139 FERC ¶ 61,244 (2012) (“June 22 Order”).

12 See June 22 Order at P 132.

13 Except as noted below, no other inputs were revised in the examination of the HTP Project.

14 Astoria Generating Co., et al. v. New York Independent System Operator, Inc., 140 FERC

¶ 61,189 at PP 134-137 (2012) (“EL11-50 September 10 Order”). See Request for Rehearing, and

Request for Expedited Clarification and Request for Shortened Notice and Comment Period on Request for Clarification, of the New York Independent System Operator, Inc. Docket No. EL11-50-001 at 19-20 (October 10, 2012) (seeking confirmation that to the extent that other power purchase agreements have been, or may in the future be, awarded to projects under RFP processes that are “limited to new
resources” the NYISO would use an appropriate proxy cost of capital in its analysis.) The NYISO’s request is still pending before the Commission.

15 The report of the NYISO’s independent Market Monitoring Unit, Potomac Economics, Ltd.
(“MMU”) concurred that “that the use of the default financing assumptions is consistent with FERC’s
policy articulated in the September Order.” See Assessment of the Buyer-Side Mitigation Exemption Test
for the Hudson Transmission Partners Project, Potomac Economics, Ltd. at 6-7 (Nov. 6, 2012) at
<http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/HTP_Report_11-6-
12_Final.pdf>.(“MMU Report”).

16 See MMU Report at 10.

17 See Affidavit of Daniel A. Jerke at P 35. The Jerke Affidavit is Attachment 2 to this Answer.

18 See EL11-50 September 10 Order at P 100.

Finally, the NYISO revised the “Scaling Factor” inputs which resulted in reducing the

Scaling Factor used in the retest, from the approximately 50 percent level referenced in the

Complaint. As is discussed below in Section II.B., this adjustment had a de minimis effect on the HTP Project’s Unit Net CONE. The MMU previously supported the Scaling Factor used in the December 2011 determination. The MMU Report supports the adjusted Scaling Factor used in
the redetermination.

The NYISO issued its determination on November 6, 2012. The retesting confirmed that
the HTP Project will be subject to an Offer Floor when it enters the market.19
The June 22 Order also directed the MMU to issue a report “discussing its assessment of the buyer-side mitigation determinations” concurrent with the NYISO’s issuance of the retest results.20 The MMU issued its report for the HTP Project determination on November 6, 2012 (“MMU Report”).21 It confirmed that the NYISO had reasonably concluded that the HTP
Project should be subject to an Offer Floor.22 The MMU Report noted a few areas where
alternative assumptions could have been used, or in the case of mothballed units, where the
MMU favors a different tariff interpretation.23 The MMU Report concluded “that the overall
results of the [NYISO’s] analysis were reasonable and that, while it may be worthwhile to

19 Complainant was also informed of the HTP Project’s Offer Floor. The price level of the Offer
Floor is confidential. See June 22 Order at P 50. Stakeholders were notified of the NYISO’s November
6, 2012 determination that the HTP Project is non-exempt. This notification is posted at
<http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/NYISO_Notice_of_BSM_Deter
minations_Nov_6_2012.pdf>.

20 June 22 Order at PP 3, 130.

21 See Assessment of the Buyer-Side Mitigation Exemption Test for the Hudson Transmission Partners Project, Potomac Economics, Ltd. (Nov. 6, 2012) at

<http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/HTP_Report_11-6-
12_Final.pdf>.

22 See MMU Report at 4, 11-12.

23 Id. at 4.

improve the methodology for future [buyer-side mitigation examination tests (“METs”)], such improvements would be unlikely to affect the MET results for the HTP Project.24

I.BACKGROUND

A.The In-City Market Mitigation Measures

The NYISO-administered In-City capacity markets are organized around a series of
ICAP Auctions. In-City market power mitigation measures have been in place since the
NYISO’s inception in 1999.25 The current capacity mitigation regime was developed through multiple rounds of proceedings before the Commission beginning in 2007 and went into effect in 2008.26 The In-City ICAP mitigation measures include buyer-side mitigation measures (i.e., the BSM Rules) that are designed to deter uneconomic entry.27 The rules apply to generators and controllable transmission lines that are Installed Capacity Suppliers.28

Unless exempt from the BSM Rules, an In-City Installed Capacity Supplier’s offers of
UCAP can be at a price no lower than its Offer Floor. An Installed Capacity Supplier’s Offer

24 Id. at 12.

25 See Consol. Edison Co. of New York, Inc., 84 FERC ¶ 61,287 (1998) (accepting a $105/kW

year offer and revenue cap on ICAP sales by New York City generators divested by Consolidated Edison Company of New York, Inc.).

26 More recently, the existing mitigation structure was addressed by the Commission in its May 2010 Order, New York Independent System Operator, Inc., 131 FERC ¶ 61,170 (2010), and in subsequent orders addressing the NYISO’s proposed enhancements to the then-existing buyer-side mitigation
measures (“In-City Buyer Side Mitigation Measures”). See New York Independent System Operator, Inc., 133 FERC ¶ 61,178 (2010) (“November 2010 Order”); New York Independent System Operator, Inc., 134 FERC ¶ 61,083 (2011) (“February 2011 Order”); New York Independent System Operator, Inc., Letter
Order, Docket No. ER10-3043-003 (March 17, 2011); New York Independent System Operator, Inc., 136 FERC ¶ 61,077 (2011) and by the June 22 Order.

27 The In-City mitigation rules also contain supplier-side rules for Pivotal Suppliers. Those rules are not the subject of the Complaint and, accordingly, are not addressed here.

28 The buyer-side mitigation rules for Special Case Resources (“SCRs”) are not the subject of the Complaint and, accordingly, are not addressed here.

Floor is set at the lower of Unit Net CONE or 75 percent of Mitigation Net CONE.29 To prevent
circumvention of the Offer Floor, capacity that is subject to an Offer Floor can only be offered
into the ICAP Spot Market Auction.30 Mitigated capacity cannot be certified towards bilateral
capacity transactions or sales in a Capability Period or Monthly Auction. The Offer Floor is thus
a deterrent to uneconomic entry. An Installed Capacity Supplier that is subject to an Offer Floor
would only receive capacity revenue in months when its Offer Floor is below the ICAP Spot

Market Auction Market-Clearing Price. A new ICAP market entrant is exempt from the Offer
Floor if it passes either of the two exemption tests set forth in the BSM Rules.
The HTP Project is subject to the BSM Rules as accepted in Docket No. ER10-3043, et seq., effective November 27, 2010.31 The Commission directed the NYISO to modify a single element of the BSM Rules when applying them to the HTP Project.32 That one variation is that the HTP Project is subject to the “Reasonably Anticipated Entry Date Rule,” which was part of the buyer-side mitigation rules that existed before November 27, 2010, but has been replaced (for all other entrants) by the “Three-Year Rule.” The “Reasonably Anticipated Entry Date Rule” provides that the NYISO use the date that a project “is reasonably anticipated to offer supply” as

29 See June 22 Order at P 7, n. 11 (explaining that “Mitigation Net CONE” is a new term that the NYISO proposed which is still pending Commission review in Docket No. ER10-2371-000 and stating that it represents “the price equal to what the Commission defined as the ‘net CONE’ used to design the NYC demand curves”).

30 See Services Tariff at Attachment H § 23.4.5.7.1.

31 Contrary to Complainant’s assertions, the modifications accepted by the Commission in Docket No. ER10-3040, et seq. replaced the then-existing In-City Buyer-Side Mitigation Measures. See
Complaint at 17. It is clear from the record in that proceeding, including the blacklined tariff sheets filed in it, that the BSM Rules were more than just “additional revisions.”

32 See February 2011 Order at P 25. The Commission stated that the Reasonably Anticipated

Entry Date Rule is to be applied to Class Year 2008 projects. The HTP Project is the only one subject to this holding.

its entry date.33 By contrast, the “Three-Year Rule” requires that the NYISO use for the entry date the date that is three years from the beginning of the Summer Capability Period
commencing three years from the year of the Class Year (i.e., defined in the Services Tariff as the Starting Capability Period).34

B. The NYISO’s BSM Mitigation Determination for the HTP Project

The NYISO evaluated the HTP Project pursuant to the BSM Rules and the February 2011
Order.35 On June 9, 2011 the NYISO informed the HTP Project of the initial determination that
it would be subject to Offer Floor mitigation. On September 9, 2011 and October 5, 2011 the
NYISO issued updated determinations for the HTP Project. As required by the BSM Rules, and
as specified in those notices, the updated determinations were “based on the Examined Facilities
that remain in the Class Year for CRIS and the Examined Facilities that meet the definitions in
Attachment H §23.4.5.7.3(II) and (III).” A final determination was issued on December 22,
2011. The NYISO’s November 6, 2012 re-determination for the HTP Project reached the same
conclusion, i.e., that the HTP Project will be subject to an Offer Floor upon entry.

C. The HTP Project’s Unforced Capacity Deliverability Rights

Unforced Capacity Deliverability Rights (“UDRs”) are rights measured in MW

“associated with new incremental controllable transmission projects that provide a transmission
interface to an area of the NYCA … in which a minimum amount of Installed Capacity must be

33 Id. at P 3.

34 Id. at P 23.

35 The HTP Project is a Class Year 2008 project, thus it was “in the ISO Interconnection Queue, in a Class Year prior to 2009/10, and [had] not commenced commercial operation or been canceled, and … the ISO [had] not made an exemption or Unit Net CONE determination.” See Services Tariff at
§23.4.5.7.3(III)(i).

maintained.”36 UDRs allow Unforced Capacity located in an External Control Area, or non-

constrained NYCA region, that is deliverable to the NYCA interface with the UDR transmission facility to be treated as if it were located in the NYCA Locality. UDRs are assigned based on a controllable line’s “transmission capability, reliability, availability . . . , and appropriate NYSRC reliability studies.”37 Additionally, projects seeking UDRs are required to meet the NYISO
Deliverability Interconnection Standard.38 UDRs are awarded by the NYISO to projects upon a formal request and the provision of specified relevant information to the NYISO.39 UCAP offers associated with UDRs may be offered in NYISO-administered Installed Capacity Auctions or the UDRs may be returned to the NYISO on an annual basis “to be used in the NYSRC and NYISO reliability studies that determine the NYCA Installed Reserve Margin and the Locational
Minimum Installed Capacity Requirements, respectively, for the next Capability Year.”40
On August 1, 2012 the NYISO granted the Complainant’s request for 660 MW of UDRs, effective upon the commencement of Commercial Operation.41

36 Installed Capacity Manual at § 4.14 (January 2012) available at <

http://www.nyiso.com/public/webdocs/documents/manuals/operations/icap_mnl.pdf>.

37 Id. at Section 4.14.1.

38 Id.

39 See id. at Section 4.14.2.

40 Id. at 4.14.3.

41 “Commercial Operations” has the meaning set forth in Attachment X of the NYISO OATT.
HTP’s August 1, 2012 letter informed the NYISO that it expects that date to be on May 31, 2013.

II.THE NYISO COMPLIED WITH THE SERVICES TARIFF AND CORRECTLY

DETERMINED THAT THE HTP PROJECT WILL BE SUBJECT TO OFFER

FLOOR MITIGATION UPON ENTRY

A.The NYISO’s Examination of the HTP Project Concurrent with Other

Examined Facilities Was in Compliance with the Tariff and Commission

Precedent

1.It Is Well Settled that the HTP Project Is Subject to the BSM Rules

and that the BSM Rules Fully Satisfy the Commission’s Transparency

Requirements

Complainant suggests that the BSM Rules were “designed to deter uneconomic entry by new generators”42 and implies that there is some question as to whether they apply to merchant transmission facilities.43 Complainant’s suggestion is wrong. The Commission clearly held that buyer-side mitigation rules, including the BSM Rules, apply to merchant transmission facilities in general, and to the HTP Project in particular.44 Moreover, Complainant specifically
acknowledged that “[a]s a new controllable merchant transmission line into NYISO . . . the
Hudson Transmission project is subject to the [BSM Rule mitigation exemption test] process
being performed by the NYISO.”45

Similarly, Complainant’s assertions that the BSM Rules lack transparency, allow the NYISO to operate with “unfettered discretion,” and that the June 22 Order “condemned” the NYISO for a “selective and inconsistent application of unwritten rules”46 are inaccurate47 and must be rejected as a collateral attack on the June 22 Order.48

42 Complaint at 2.

43 Id. at 3.

44 See March 2008 Order at P 121; February 2011 Order at P 25.

45 Comments of Hudson Transmission Partners, LLC at 7, Docket No. EL11-42-000 (filed July 6, 2011); see also Motion to Intervene and Protest of Hudson Transmission Partners, LLC at 3, Docket No. ER10-3043-000 (filed October 22, 2010).

46 See Complaint at 29.

2.The HTP Project Was Properly Examined Concurrent with Class

Year 2010 Examined Facilities

The Complaint argues that the NYISO violated the BSM Rules by analyzing the HTP
Project, a Class Year 2008 project, “as part of” Class Year 2010, instead of before Class Years
2009 and 2010.49 Complainant asserts that the NYISO was not permitted to consider projects
from Class Years 2009 and 2010 in its analysis for the HTP Project.50 It also contends that, as a
result of this supposed “error,” the NYISO incorrectly used “information available (e.g., [ICAP]
Demand Curves, load forecasts, natural gas prices, etc.) in late 2011 . . .”51 rather than the

information available at the time that Complainant states that it committed to “go forward” with the HTP Project (i.e., December 2009 or January 2010).52

The Complainant’s claims should be denied. Even though the HTP Project is in Class Year 2008, the BSM Rules and the February 2011 Order required the NYISO to examine it based on existing capacity and concurrent with other Examined Facilities that shared the same Starting Capability Period, i.e., Summer 2013.

47 The June 22 Order rejected similar claims made by the complainants and HTP in that docket regarding the NYISO’s processes. See June 22 Order at P 46. HTP later sought to withdraw its
comments on the transparency issue, but the Commission rejected that request. It specifically found that HTP’s comments were “relevant to the issue of transparency.” See June 22 Order at P 26.

48 See, e.g., San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services, et al., 134 FERC ¶ 61,229 at P 15 (2011) (“collateral attacks on final orders and relitigation of applicable precedent by parties that were active in the earlier cases thwart the finality and repose that are essential to
administrative efficiency and are strongly discouraged”), citing Entergy Nuclear Operations, Inc. v.
Consolidated Edison Co., 112 FERC ¶ 61,117, at P 12 (2005); see also EPIC Merchant Energy NJ/PA,
LP v. PJM Interconnection, LLC, 131 FERC ¶ 61,130 (2010) (dismissing as an impermissible collateral attack a complaint that merely sought to re-litigate the same issues that were raised in the prior case citing no new evidence or changed circumstances).

49 Complaint at 32-33.

50 Id. at 38-44.

51 Id. at 4.

52 Id. at 33-38.

The HTP Project is an Examined Facility, whose entry date, for purposes of the BSM
Rules is to be determined using the “Reasonably Anticipated Entry Date Rule,” instead of the
“Three-Year Rule.” The February 2011 Order held that Class Year 2008 projects “should be
evaluated under the existing Reasonably Anticipated Entry Date Rule.”53 This is the exact
treatment that Complainant requested for the HTP Project.54 The HTP Project is an “Examined
Facility” under Services Tariff Section 23.4.5.7.3(III)(a)(i) because it is a Class Year 2008
project that had “not commenced commercial operation or been cancelled.”
Under the Reasonably Anticipated Entry Date Rule, the HTP Project’s entry date was May 2013. Complainant had expressly asked that the NYISO use the HTP Project’s “actual projected start date of 2013 under the existing rules” instead of applying the new rules using a projected start date of 2011.55 Complainant argued that it “[was] very concerned that [the Three Year Rule] will result in incorrect and erroneous analysis results for HTP” and “that the
proposed artificial and incorrect assumption by the NYISO that the [HTP Project] will start
operation in 2011 may distort the market mitigation and exemption analyses for all other
parties.”56 The Commission granted this request.57

Complainant is correct that under the Three-Year Rule the HTP Project’s entry date

would have been 2011 (i.e., three years after 2008). But it cannot plausibly argue now that the NYISO should have used that entry date given its past arguments and the Commission’s

53 February 2011 Order at P 25; see also Complaint at 19-21 and n. 48.

54 Complaint at 19-20 and n.47.

55 Limited Protest of Hudson Transmission Partners, LLC to Compliance Filing of New York Independent System Operator, Inc. and Request for Relief at 4, Docket No. ER10-3043-001 (filed Dec. 21, 2010) (“HTP ER10-3043 Protest”).

56 Id. at 10-11.

57 See February 2011 Order at P 25.

acceptance of them. In addition, based on information provided by HTP, the NYISO’s June

2011 Interconnection Queue stated May 2013 as the HTP Project’s “proposed in-service date.”
The May 2013 entry date placed the HTP Project in the same Mitigation Study Period as Class Year 2010 projects. Pursuant to Section 23.4.5.7.3.2 of the Services Tariff:

[w]hen the ISO is evaluating more than one Examined Facility concurrently, the ISO shall recognize in its computation of the anticipated ICAP Spot Market
Auction forecast price that Generators or UDR facilities will clear from lowest to highest, using for each Examined Facility the lower of (i) its Unit Net CONE or (ii) the numerical value equal to 75% of the Mitigation Net CONE.

Therefore, in accordance with the BSM Rules, the NYISO’s examination of the HTP
Project was performed concurrently58 with Class Year 2010 projects. That is, the NYISO
included Class Year 2009 Examined Facilities in the ICAP forecast used for the HTP Project
analysis. Under the Three Year Rule, Class Year 2009 projects are deemed to enter in 2012,
which is before the HTP Project’s 2013 entry date under the Reasonably Anticipated Entry Date
Rule. The NYISO’s approach was thus fully consistent with its tariff and the February 2011
Order and did not constitute an unauthorized “effective removal”59 of the HTP Project from
Class Year 2008.

The Affidavit of Daniel A. Jerke60 (“Jerke Affidavit”) confirms each of the points made above.61 It also explains that “the NYISO notified HTP of the facilities that would be

58 The Commission must also reject Complainant’s attempts to conflate the mitigation exemption
determination process under the BSM Rules under Services Tariff Attachment H and the Class Year
process under OATT Attachment S. See Complaint at 30-31, 39-40 (arguing that the NYISO misapplied
the OATT when making its determination for the HTP Project). Complainant confuses the fact that these
are separate processes. The BSM Rules provide that the initial and final determinations for Examined
Facilities be conducted concurrent with the Class Year Project Cost Allocation Process. The BSM Rules
explicitly provide for that timing even for Examined Facilities not in the Class Year going through the
Project Cost Allocation process.

59 Complaint at 11.

60 Attachment 2 to this Answer.

considered in the HTP Project analysis starting in November 2010.”62 The NYISO “identified the list of Examined Facilities in spreadsheets containing the relevant forecast inputs that were posted to its website.”63

The Jerke Affidavit also explains that Complainant has twice mischaracterized certain
communications from the NYISO to imply that the NYISO changed its approach to the HTP
Project analysis.64 The NYISO never suggested to Complainant that it would complete the
exemption determination for the HTP Project before it conducted the analyses for Class Year
2009 and 2010 projects. The data request referenced by Complainant was sent to the HTP
Project and to all other Class Year 2009 and 2010 projects to be examined under the BSM Rules
as part of an expedited information gathering effort that was expressly described in the NYISO’s
September 27, 2010 filing to establish the BSM Rules.65 The data request simply reflected
section 23.4.5.7.3.3 of the Services Tariff which requires that an initial informational
determination be provided to Examined Facilities “prior to the commencement of the Initial
Decision Period.”

61 See Jerke Affidavit at 16-23.

62 Id. at P 19.

63 Id.

64 See Complaint at 33 and n. 69; Jerke Affidavit at 21-22.

65 See New York Independent System Operator, Inc., Proposed Enhancements to In-City BuyerSide Mitigation Measures, Request for Expedited Commission Action, and Contingent Request for Waiver of Prior Notice Requirement at 18 and n.38 (September 27, 2010) (“Specifically, the NYISO intends to ask potential new entrants to submit the information required under the proposed tariff enhancements
shortly after it makes this filing.”)

The MMU Report concludes that it is appropriate as a substantive matter for the NYISO to analyze the HTP Project concurrent with other Class Year 2010 projects.66 It does not dispute the NYISO’s position that Commission precedent requires that treatment.67

B. The NYISO Properly Applied a “Scaling Factor” to Determine HTP’s

Projected Net Energy Revenues When Establishing Unit Net CONE

The Complaint notes that the NYISO applied a Scaling Factor to reduce the HTP

Project’s projected net energy revenues. It complains that this resulted in a commensurate

increase in the applicable Unit Net CONE.68 Complainant argues that there is no basis for the Scaling Factor in the NYISO’s tariffs, manuals, or other documents. It also contends that application of a Scaling Factor to the HTP Project is discriminatory because it has not been applied to generator entrants.69

These assertions are without merit. The use of a Scaling Factor is necessary to properly
implement the Services Tariff’s express requirement that the NYISO reasonably estimate the
projected net Energy revenues70 for new entrants, including merchant transmission entrants.
Commission policy and precedent establish a “rule of reason,”71 under which “general operating

66 See MMU Report at 13

67 Id.

68 June 22 Order at 44.

69 Id.

70 See Services Tariff §23.2.1 at definition of Unit Net CONE. The analysis also nets revenues for Ancillary Services if the ICAP Supplier is capable of providing them.

71 See, e.g., Southwest Power Pool, Inc., 136 FERC ¶ 61,050 at P 33 (2011) (internal citations

omitted); see also, Preventing Undue Discrimination and Preference in Transmission Service, Order No.
890, FERC Stats & Regs. ¶ 31,241, at PP 1650-1651 (2007), order on reh’g, Order No. 890-A, FERC
Stats. & Regs. ¶ 31,261, 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, order on clarification, 129 FERC ¶ 61,126 (2009) (finding that
only rules, standards and practices which significantly affect transmission service must be included in a
transmission provider’s OATT, although they must be posted on the transmission provider’s public

website); City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985).

procedures”72 and “implementation details”73 need not be specified in tariffs. Consistent with this authority, the rule of reason does not require that every element of the calculation the
NYISO might make to reasonably estimate a project’s projected net energy revenues, such as the application of a Scaling Factor, be specified in the tariff.

The June 22 Order found that the BSM Rules were sufficiently transparent and that the tariff contained “objective rules of how mitigation will be conducted and set forth criteria in Attachment H of its Services Tariff.”74 Further, the June 22 Order rejected assertions by other parties that implementation details similar to the Scaling Factor be included in the tariff. It instead directed that this type of implementation information be provided only in examples and detailed narratives to be posted on the NYISO’s website.75

The application of a Scaling Factor to the HTP Project is not unduly discriminatory. As
explained in the July 22, 2011 Supplemental Affidavit of Joshua A. Boles in Docket No. EL11-
42-000 (“2011 Boles Supplemental Affidavit”),76 the NYISO’s approach to calculating Unit Net
CONE for a UDR project is similar to its approach for generation in many significant ways.77

72 See, e.g., Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,163 at P
656 (2004), order on reh'g 109 FERC ¶ 61,157 (2004), order on reh'g, 111 FERC ¶ 61,043 (2005)
(indicating that the rule of reason dictates that the Business Practices Manuals did not have to be filed
under section 205, because while the manuals implicated the Commission’s jurisdiction they “mostly
involve[d] general operating procedures” and therefore no section 205 filing was required).

73 See, e.g., Midwest Independent Transmission System Operator, Inc., 122 FERC ¶ 61,283 at PP 398-399 (2008) (finding that “implementation details fall within the Commission's rule of reason” and do not have to be included in the tariff”).

74 June 22 Order at P 46.

75 Id. at P 50.

76 For ease of reference, the Boles Supplemental Affidavit is attached hereto as Attachment 3.

77 Answer of the New York Independent System Operator, Inc. to Comments, Docket No. EL11-
42-000 (filed July 22, 2011) at Supplemental Affidavit of Joshua A Boles at P 8 (“2011 Boles
Supplemental Affidavit”) (Attachment 3 to this Answer)

Both types of projects are evaluated based on reasonably anticipated costs minus reasonably

anticipated revenues to determine if they should be exempt or subject to an Offer Floor.78

A UDR project that is located in an External Control Area, however, will have costs and
revenues that are different from those for a generator located in the NYCA.79 Application of the
Scaling Factor to the HTP Project was necessary in order to compute the Unit Net CONE of the
project, because the NYISO must consider project specific characteristics. One of the main
differences between a UDR project and a generator is the need to use, in the forecast net energy
revenue calculation, the energy price spread between the NYISO (New York City) and the
neighboring Control Area.

Because this price spread is not known at the time that transactions are scheduled, it is
impossible for the operator of such a transmission line to fully utilize it. In some hours when
transactions are not fully scheduled, a profitable price difference may emerge unexpectedly.
Similarly, some scheduled transactions that are expected to be profitable may ultimately be
unprofitable (flowing from the high priced area to the low priced area) because the price spread
is different than expected. The purpose of the Scaling Factor is to account for the fact that inter-
regional price differences cannot be fully arbitraged because of the price uncertainty on both
sides of the interface.

To unrealistically assume that a transmission owner could perfectly arbitrage the inter-
regional price differences would overstate energy net revenues and, therefore, understate the
HTP Project’s Unit Net Cone. Consequently, in order to implement the BSM Rules’ requirement
that it reasonably estimate net energy revenues, the NYISO had to use a Scaling Factor. The

78 Id. at P 8.

79 Id. See also Jerke Affidavit at PP 24-41.

Jerke Affidavit explains in greater detail why it is necessary and reasonable to apply a Scaling
Factor to UDR Projects like the HTP Project, but not to generators.80 In order to reasonably
calculate the HTP Project’s net energy revenues, the NYISO applied a Scaling Factor that “takes into account the price spread between the respective locations in the Control Areas from which
the power is exported and the location to which it is imported.”81 The price spread that would
induce arbitrage is determined by considering associated fees that a Market Participant pays to
export energy from the neighboring Control Area and the likelihood that the spread would
exist.82 That fee is then used to determine when a transaction will be scheduled to flow and
when it will not flow; so when the energy spread exceeds that rate, the rate is subtracted from the spread to calculate the net energy revenues.83

As further shown in the Jerke Affidavit, it was reasonable, in order to accurately calculate
the HTP Project’s net energy revenues, to set the Scaling Factor at the level calculated by the
NYISO.84 It was set as “the ratio of (a) historic net energy revenues from the day-ahead and
real-time markets to (b) theoretical net energy revenues from the day-ahead market for same
historic period. Projected net energy revenues assume perfect arbitrage of PJM and NYISO day-
ahead market energy prices.”85 The Complaint notes that the NYISO had informed HTP that the
Scaling Factor utilized in the December 2011 determination was approximately 50 percent. At
the time of the retest, the NYISO determined that it was appropriate to reduce the inputs to the

80 See Jerke Affidavit at 24-41.

81 2011 Boles Supplemental Affidavit at P 12.

82 Id.

83 Id.

84 See Jerke Affidavit at PP 24-41,

85 Id. at P 33.

Scaling Factor, which resulted in reducing the Scaling Factor.86 That adjustment had a small

effect on the HTP Project’s net energy revenues, and an even smaller effect on the HTP Project’s
Unit Net CONE. Further, as discussed in the Jerke Affidavit, the Complaint inaccurately
characterizes the impact of the Scaling Factor. The application of a Scaling Factor at a given
percentage level does not “increase [HTP’s] Unit Net CONE by a corresponding amount.”87 Nor
do adjustments to the Scaling Factor have a commensurate effect on the level of Unit Net
CONE.88

Additionally, Complainant’s assertions that its discussions with “a number of energy

market trading participants” indicated that unnamed entities believe that the HTP Project should
be able to receive at a minimum the day-ahead price spread less any transaction cost89 should be
given no evidentiary weight. As the Jerke Affidavit emphasizes, the NYISO, NERA Economic
Consulting (its economic consultant,) and the MMU all agreed that it would be unreasonable to
assume 100 percent capture of revenues for the HTP Project because “in practice, price spreads
cannot be perfectly arbitraged.”90 The NYISO also recognized that observed behavior on

existing competitively scheduled lines confirms the unreasonableness of assuming perfect

arbitrage91 and other specific limitations affecting the scheduling of inter-market transactions.92 Therefore, the Commission must reject Complainant’s assertions that the NYISO should have assumed that the HTP Project would receive 100 percent energy revenues.

86 See id. at P 36.

87 Complaint at 4.

88 Jerke Affidavit at P 36.

89 Complaint at 46.

90 Jerke Affidavit at P 31.

91 Id.

92 Id. at P 32.

The NYISO developed the Scaling Factor with input from and in close consultation with
the MMU. The MMU Report supports the NYISO’s approach to estimating the forecasted
energy and ancillary services net revenue for the HTP Project, including the NYISO’s use of the
Scaling Factor.93 It states that the “NYISO used assumptions that were both reasonable and tariff
compliant.”94 It also concurred that it was necessary for the NYISO to adopt a different
methodology for estimating net revenues for UDR projects than would be used for generators.95
Although the MMU Report notes that there are some “alternative assumptions” the NYISO
might have used, it concludes that the results of the exemption analysis for the HTP Project
“would not be affected by reasonable improvements in assumptions.”96 The Jerke Affidavit and
the 2011 Boles Supplemental Affidavit also explain why the NYISO’s proposed Scaling Factor
is just and reasonable.97

The Commission must also reject Complainant’s proposed alternative to the NYISO’s
Scaling Factor.98 As demonstrated by the Jerke Affidavit, the Complainant’s approach bears
little relation to the net energy revenues relevant to the HTP Project. It provides no explanation
for important elements of its proposal and is overly simplistic.99 Even if Complainant’s
alternative approach were plausible it would not render the NYISO’s administration of its tariff
unjust and unreasonable. Commission and judicial precedent are clear that alternative
methodologies can simultaneously be just and reasonable without diminishing the justness and

93 See MMU Report at 7.

94 Id. at 7.

95 Id. at 8-9.

96 Id. at 8.

97 See Jerke Affidavit at PP 24-41 and 2011 Boles Supplemental Affidavit at PP 10-15.

98 Complaint at 48-49.

99 See Jerke Affidavit at PP 42-45.

reasonableness of others.100 Thus, even if the Commission found merit in Complainant’s

alternative approach to the calculation of the HTP Project’s net energy revenues it must reject it, because the NYISO’s methodology is just and reasonable.

C. The NYISO Treated the HTP Project the Same as Other New Entrants

Regarding the Exclusion of Sunk Costs and Complainant Has Not Justified Excluding Additional Costs

Complainant argues that the Commission must direct the NYISO to exclude anywhere from $16.7 million to $300 million in sunk costs from its Unit Net CONE calculation for the
HTP Project.101 While Complainant does not take a position regarding whether the exclusion of sunk costs is in compliance with the BSM Rules as a general matter, it does argue that including sunk costs in the examination for the HTP Project was unduly discriminatory given the NYISO’s exclusion of sunk costs in its exemption analyses for Astoria Energy II (“AEII”) and the
Bayonne Energy Center (“BEC”) projects.

Complainant’s argument must be rejected, because it incorrectly assumes that the

NYISO did not exclude sunk costs in its examination of the HTP Project. Consistent with its
determinations for other projects examined under the BSM Rules, the NYISO excluded certain
categories of costs from its calculation of Unit Net CONE for the HTP Project. As is explained

100 PJM Interconnection, LLC, 119 FERC ¶ 61,063 at P 41 (2007) (stating that “on the same set of facts there can be ‘multiple just and reasonable rate designs’”); California Independent System
Operator Corporation, 119 FERC ¶ 61,076 at P 14 (2007) (stating that “there can be more than just and
reasonable proposal, and the proposal under consideration will be selected unless it is found unjust and
unreasonable”); Midwest Independent Transmission System Operator, Inc., 117 FERC ¶ 61,241 at P 62
(2006) (stating that “[u]nder the FPA, if we find that the Midwest ISO has successfully supported the
justness and reasonableness of its proposal, we must approve it even if there are other just and reasonable ways…”); Cities of Bethany v. FERC, 727 F.2d 1131 at 1136 (1984) (finding that “[t]he Federal Power
Act requires that all rates charged by public utilities be ‘just and reasonable.’ In the past FERC has
interpreted is authority to review rates under this provision of the Act as limited to an inquiry into whether the rates proposed by a utility are reasonable - and not to extend to determining whether a proposed rate
schedule is more or less reasonable than alternative rate designs”).

101 Complaint at 48, n.126.

in the Jerke Affidavit, the NYISO excluded the non-engineering, procurement, and construction (“non-EPC”) cost components that its engineering consultant advised developers typically incur prior to committing to a project. These costs were equal to one-half of permitting costs, one-half of legal costs, all environmental studies costs, and all market studies costs.102

Complainant’s suggestion that additional sunk costs beyond non-EPC costs should have
been excluded from the NYISO’s analysis are unsupported and vague.103 Complainant gives no
indication of how it estimated its claimed sunk costs.104 Thus, there is no basis to even consider
the argument and it must be rejected. The MMU Report supports the NYISO’s position.105

D.The NYISO Properly Estimated the Cost of Capacity to Be Delivered Over

the HTP Project

The Complaint contends that the NYISO improperly estimated the cost of capacity to be
delivered over the HTP Project and sold into the NYISO administered ICAP auctions.
Complainant argues that the NYISO erroneously based those costs on prices in PJM’s Base
Residual Auctions (“BRAs”) which have a longer forward period (i.e., three years) than the
NYISO’s Spot Market Auctions, which a have a forward period of less than one month.
Complainant argues that this supposed error increases the HTP Project’s Unit Net CONE,
because the prices in the BRAs are allegedly higher than the prices used in PJM’s incremental

102 See Jerke Affidavit at PP 46-47. The EL11-50 10 Order noted the NYISO’s statements that it excluded these same categories of costs from Unit Net CONE calculations under the prior In-City buyerside mitigation rules and did not expressly indicate that the NYISO was prohibited from continuing to do so. See Astoria Generating Company, L.P., et al. v. New York Independent System Operator, Inc., 140
FERC ¶ 61,189 (2012).

103 Id. at PP 48-49.

104 The Commission’s order in the EL11-50 September Order stated that all of an Installed

Capacity Supplier’s embedded costs should be considered in the Unit net CONE analysis under the BSM
Rules. The Commission defined “embedded costs” broadly to include all “costs that have been incurred
in the past, whether or not the associated assets have any opportunity costs or market value.” See EL11-

50 September 10 Order at P 121.

105 See MMU Report at 6.

auctions which supposedly have a forward period “more closely aligned” (i.e., less than six
months) with those in the NYISO-administered Installed Capacity auctions.
The Commission must reject this assertion. The NYISO properly calculated the HTP Project’s capacity costs using PJM BRA prices. As the Jerke Affidavit explains, Complainant puts too much emphasis on the apparent similarity in timing between the NYISO’s capacity
auctions and PJM’s incremental auctions, but neglects to consider a number of more salient
factors that make the NYISO’s auctions more similar to the BRAs.106 In particular, the BRAs
closely resemble the NYISO’s auctions insofar as prices in both are driven by demand curves
“based on transparent net CONE values, the planning requirement, and the level of supply.”107
As is the case with the NYISO’s auctions, the large majority of capacity transactions in PJM take
place in the BRAs.108 By contrast, PJM’s incremental auctions are “thinly-traded and prices in
them are set by the interaction of a relatively small number of bids and offers.”109 Because
capacity cannot be reliably procured from the incremental auctions the apparent price difference
between them and the BRAs is not meaningful.110 Nor is it necessarily the case that even the
apparent difference in prices will persist into the future given that prices tend to converge in the
long run.111 Taken together, those factors make BRA prices a reasonable estimate of capacity
costs in PJM rather than the incremental auctions. Indeed, if anything, the NYISO’s use of BRA
prices was conservative because it did not account for the increased prices in PJM that would

106 See Jerke Affidavit at PP 51-57.

107 Id. at P 53.

108 Id. at PP 56.
109 Id. at P 54.

110 Id. at PP 54, 56.
111 Id. at P 54.

likely result from the export of PJM capacity to New York over the HTP Project. There is no basis for Complainant’s claim that they are likely to produce “false positives” because of their supposed use of “overstated prices.”112

In addition, the Jerke Affidavit explains that the alternative pricing proposals offered by Complainant are without merit. First, discounting BRA prices based on the historical
relationship between BRA and incremental auction prices would be unreasonable given the
differences between the two auctions, including the inability to count on being able to obtain
capacity in the incremental auctions. Furthermore any PJM resource seeking to export capacity to New York would only do so if it could obtain at least the BRA prices, which strongly militates in favor of the NYISO’s use of BRA prices.113

Second, the Jerke Affidavit explains how trying to use “appropriate” incremental auction
prices from the “appropriate” “go forward” date would be unreasonable and impracticable.114 It
would be unreasonable and impracticable because “there is no certainty that capacity can be
procured in the incremental auctions,” and because it is unclear how the proposal would be
applied.115

Similarly, the MMU Report concludes that is “generally reasonable” for the NYISO to
look to BRA clearing prices, notwithstanding the timing difference between them and the
NYISO’s auctions.116 It points to four reasons to support this conclusion. First, the MMU states
that BRAs are extremely liquid. Almost all capacity that is traded in PJM is traded through

112 Id. at P 57.

113 Id. at PP 55-57.
114 Id. at PP 58-59.
115 Id. at PP 58-61.

116 See MMU Report at 14.

them. Second, it is not reasonable to assume PJM capacity to be available after the BRA because all PJM supply must normally be offered into it. Any PJM supply that wishes to avoid the BRA in order to export capacity must have a bilateral contract to do so. Third, PJM’s incremental
auctions are conducted much closer to the delivery timeframe than is the case in the NYISO, are generally illiquid, and lack sufficient supply to support capacity exports over Controllable Lines to New York City. Fourth, and finally, given the lack of liquidity in the incremental auctions,
attempts by the HTP Project to purchase substantial amounts of capacity in them to support
exports to New York City would likely result in sharply higher prices.117 Complainant’s
challenge to this decision should therefore be denied.

III. THE COMMISSION MUST DENY COMPLAINANT’S REQUEST FOR

“RELIABILITY BENEFITS” COMPENSATION

A.Complainant’s Request for “Reliability Benefits” Compensation Is

Procedurally Defective

1. Complainant’s Unilateral Request that the NYISO Be Compelled to

Establish a “Tariff Mechanism” to Compensate It Is an Inappropriate
Attempt to Circumvent the NYISO’s Shared Governance Process

Complainant’s request that the NYISO should be required to establish a “tariff

mechanism” to compensate it for the claimed “reliability benefits” supplied by the HTP Project
is a violation of the NYISO’s shared governance rules and is contrary to Commission precedent.
Under the ISO Agreement, the NYISO’s tariffs may only be revised under Section 205 of the
FPA if the revision has been approved by a super-majority of the stakeholder Management
Committee and by the NYISO’s independent Board of Directors.118 Although interested parties

117 See MMU Report at 14-15.

118 See ISO Agreement § 7.01. The one exception to this requirement, which is not relevant here, is the rule allowing the NYISO to propose temporary tariff changes under Section 205 when “exigent circumstances” exist. See ISO Agreement § 19.01.

may ask that tariff changes be imposed under FPA Section 206, the Commission has been clear that such filings are disfavored when the NYISO stakeholder process has not been exhausted.119 Numerous other Commission orders discourage parties from attempting “end-runs” around
ISO/RTO governance processes by proposing tariff changes that have not had the benefit of stakeholder vetting. 120 Allowing such end-runs would create harmful incentives to avoid
collaboration and compromise. Complainant has made no effort to pursue its proposed tariff mechanism through the NYISO stakeholder process.

As is discussed below, Complainant’s proposed “reliability benefits” compensation rule
would be a radical departure from the existing NYISO tariff structure, market design, and market
power mitigation measures. The Services Tariff should not be permanently revised to include
such a major change without stakeholder review. This would be true even if such a rule were
only applicable to Complainant. In reality, however, it is difficult to discern a principled basis
for limiting a “reliability benefits compensation rule” to a single Market Participant. Thus, even
if the Commission were to conclude that Complainant’s “reliability benefits compensation”

119 See Niagara Mohawk Power Corp. v. New York State Reliability Council and New York

Independent System Operator, Inc., 114 FERC ¶61,098 at P 1 (2006) (“For the reasons described below, we will exercise our discretion and require that National Grid first exhaust its methods of resolving this dispute within Reliability Council and NYISO before filing a complaint with the Commission. Thus, we will dismiss the Complaint, without prejudice.”).

120 See, e.g., ISO New England Inc., 130 FERC ¶ 61,145, at P 34 (2010) (“we encourage parties to
participate in the stakeholder process if they seek to change the market rules...”); ISO New England Inc.,
125 FERC ¶ 61,154 at P 39 (2008) (directing that unresolved issues be addressed through the stakeholder
process); ISO New England, 128 FERC ¶ 61,266 at P 55 (2009) (declining to grant a party’s specific
request for relief because the Commission “will not ... circumvent that stakeholder process”); New York
Independent System Operator, Inc., New York Transmission Owners, 126 FERC ¶ 61,046, at PP 53-54
(2009) (directing that a proposal be “presented to and discussed among … stakeholders and filed as a
section 205 proposal, not unilaterally presented to the Commission”); New England Power Pool, 107
FERC ¶ 61,135 at PP 20, 24 (2004) (declining to accept changes proposed for the first time in a
FERC proceeding by an entity that participated in the stakeholder process because the “suggested
revisions have not been vetted through the stakeholder process and could impact various participants”).

proposal might have merit,121 it should not allow such a dramatic change to be made without a stakeholder process.

2. The Commission Should Not “Clarify” that Complainant May Make

a Section 205 Filing to Establish Its Own Rate Schedule for “Reliability Benefits” Compensation

As an alternative to its request that the NYISO tariff be revised, Complainant asks that
the Commission “clarify” that it “may file, under Section 205 of the FPA, a rate schedule to
receive . . . compensation” for the reliability benefits that it claims that the HTP Project will
confer.122 The Commission should grant no such “clarification.” If Complainant wanted the
Commission to provide declaratory guidance it should have filed a petition for a declaratory
order. Even if the Commission does not believe that a petition is necessary, there is no reason
for it to effectively “pre-approve” a future Section 205 filing by Complainant before it has

actually been submitted and supported. The Commission recently denied a similar request by a
supplier seeking a “declaration of a general right” to unilaterally file rate schedules that was
outside the scope of the proceeding.123 It should follow that precedent here.
If the Commission were to accept such a Section 205 filing for the HTP Project it would indirectly establish a new compensation rule that should be established directly in the NYISO tariff.124 Accepting such a filing would create a paradoxical situation in which a party would

121 To be clear, the NYISO’s position, which is set forth below, is that the proposed rule has no merit, would undermine the NYISO’s market design and market power mitigation measures, and should not be adopted.

122 Complaint at 62-63.

123 See New York Independent System Operator, Inc., 141 FERC 61,081 (2012) (“However, we deny NRG’s request for a declaration of a general right to file its own rate schedule under section 205 of the FPA, as that issue goes beyond the scope of the instant filing.”)

124 The Long Island Power Authority’s (“LIPA”) has interests in two controllable transmission
projects with UDRs, the Neptune Scheduled Line and the Cross-Sound Cable Scheduled Line. LIPA
protests the relief that HTP requests. However, it argues that “if the Commission finds merit in Hudson

effectively have a unilateral right to effectuate de facto amendments to the NYISO tariffs Section 205 that the NYISO itself would lack.125

A “stand alone” filing in this context would raise all of the concerns that have properly
resulted in earlier rejections126 of attempted “end-runs” around ISO/RTO stakeholder
processes.127 For example, the Commission rejected a NYISO market participant’s attempt to
unilaterally file a rate schedule for a new ancillary service, directing it to work through the
stakeholder process instead.128 The Commission also rejected a market participant’s proposed

Transmission’s requests, … the Commission [should] recognize that similarly situated merchant

transmission facilities are interconnected with the New York State Transmission System and that those
facilities may be eligible for treatment comparable to any approval that the Commission might provide to
Hudson Transmission.” See Motion to Intervene and Protest of the Long Island Power Authority at 3-4,
Docket No. EL12-98-000 (filed September 12, 2012). LIPA then argues that if approved for HTP, the
opportunity should “be available to Neptune and Cross Sound Cable as well.” Id at 4. The Neptune and
Cross Sound Cable Scheduled Lines do not interconnect In-City and, therefore, they are not subject to
buyer-side mitigation. HTP’s argument is premised on it being mitigated. LIPA’s argument therefore
would expand the relief HTP request. LIPA’s request (albeit subject to its protest of HTP’s request)

should also be rejected as should the application of HTP’s proposal to any other scheduled line or transmission facility.

125 See ISO Agreement § 7.01.

126 USGen New England, Inc., 90 FERC ¶ 61,323 at 62,090 (2000), reh’g denied, 92 FERC ¶
61,020 (2000) (rejecting a proposed SRS agreement because the ISO should be “the first instance for
stakeholders to work out their differences on issues such as costs and recovery of costs…”); Sithe New
England Holdings, LLC and Sithe New Boston, LLC v. New England Power Pool and ISO New England,
Inc., 86 FERC ¶ 61,283 at 62,021 (1999) (rejecting a proposed cost-based rate schedule finding that
changes to such compensation mechanisms should be pursued through the stakeholder process).

127 There are few exceptions and they are not relevant here. See, e.g., ISO New England Inc. and
New England Power Pool, 129 FERC ¶ 61,008, at P 18 (2009) (allowing certain generators to file
individual cost-based rate schedules pursuant to FPA section 205, but only under the rubric of an ISO
Tariff) and Otter Tail Power Co., 99 FERC ¶ 61,019, at 61,091 (2002) (allowing for the filing of a tariff
by a MISO market participant, but only for non-Midwest ISO transactions). Additionally, although a
recent Commission order did not reject outright a market participant’s proposed stand alone rate schedule
for black start service, that order does not support Complainant’s request. In that proceeding, the
Commission did not rule on the disputed legal issues raised by the proposed rate schedule, but, expressly
accepted it as an interim arrangement to maintain reliability in New York City during the summer. See
TC Ravenswood, LLC, 139 FERC ¶ 61,151 at P 38 (2012); reh’g dismissed as moot, TC Ravenswood,
LLC, 140 FERC ¶ 61,214 at P 16 (2012) .

128 See Astoria Generating Company, L.P., 101 FERC ¶ 61,275 at P 1 (2002).

stand alone rate schedule providing compensation for costs incurred in providing a service that was included in the NYISO’s tariff.129

A Section 205 filing by Complainant to establish a “reliability benefits compensation” service would be unprecedented. The Commission has never previously authorized a market participant to unilaterally create an entirely new product that ISOs/RTOs, or their customers, would be forced to purchase. As discussed below, there is no legal, factual, economic, or equitable reason to break new ground in this proceeding.

B. Providing Non-Market-Based Compensation to the HTP Project Would

Contravene the Design of the BSM Rules and the NYISO’s Market

Mandating non-market-based compensation for the HTP Project’s self-proclaimed

reliability benefits would undermine the BSM Rules. Complainant’s theory is premised on its
expectation that the HTP Project’s capacity will not clear if it is subject to an Offer Floor.
Complainant is thus attempting to require customers to wholly or partially offset the capacity
revenues that it might not obtain because of its own investment decisions.
Complainant’s proposal directly contradicts the purpose and design of the BSM Rules. The prospect of Offer Floor mitigation discourages uneconomic entry by creating the possibility that an uneconomic project would not clear in the capacity auctions. It is entirely appropriate, and consistent with the design of the BSM Rules, that projects be at risk of receiving reduced capacity revenues if they are uneconomic, regardless of whether they might confer reliability benefits. Allowing entrants to avoid this risk by showing that they increase the reliability of the

129 See TC Ravenswood, LLC, 135 FERC ¶ 61,087 (2010) (rejecting Ravenswood’s proposed

stand-alone rate schedule providing compensation for certain variable costs incurred in providing

“Minimum Oil Burn Service”); reh’g dismissed as moot, TC Ravenswood, LLC, 140 FERC ¶ 61,214 at P

16 (2012).

system would insulate them from the effects of Offer Floor mitigation. Doing so would undermine the BSM Rules and their deterrent effect.

Complainant’s proposal is also inconsistent with the NYISO’s market design.130 The NYISO’s rules are designed to provide market-based compensation to suppliers of discrete
energy, capacity, and ancillary services products. Suppliers are not compensated separately for the “reliability benefits” that their services provide. Thus, “reliability benefits” are not
separately priced. Compensation for providing such benefits is instead a component of the tariff derived prices for market products paid to suppliers.

Paying non-market-based compensation for “reliability benefits” would be a fundamental departure from the basic design of “organized markets” such as the NYISO’s. As noted below, the Commission has allowed non-market-based compensation in the limited circumstances
specified in its RMR precedents while expressing concern that the use of such arrangements
would harm competitive markets. Complainant’s proposal would expand the use of non-market-
based compensation rules far beyond what the Commission has reluctantly accepted in the past. If the HTP Project is entitled to separate compensation for reliability benefits, then all other
owners of transmission facilities in the NYISO-administered markets presumably would be as
well. Awarding reliability benefits compensation to Complainant would therefore lead to
fundamental and undesirable changes in the NYISO-administered markets. The NYISO is
concerned that moving in this direction would reduce the efficiency of competitive markets and, ultimately, diminish the benefits that they bring to consumers.

130 To the best of the NYISO’s knowledge, Complainant’s proposal would also be inconsistent with the design of all other Commission-jurisdictional “organized markets.”

The Commission has rejected claims,131 similar to Complainant’s, by capacity market
participants in other markets that they should be guaranteed cost recovery under FPC v. Hope
Natural Gas Co..132 The Commission’s policy is to allow capacity suppliers to recover their
costs through market-based rates in competitive markets. The fluctuation of prices in a
competitive market, by itself, is not sufficient to establish that an entity lacks the opportunity to
recover its costs. It is fully expected that where prices are set by competitive forces that they
will go up and down as market conditions change and new entry and retirements occur. The
Commission has clearly stated that in competitive markets, it “is only responsible for assuring
that [a resource] is provided the opportunity to recover its costs not a guarantee of cost
recovery.”133 The Commission has further explained “[t]he purpose of the [capacity market] is,
in part, to enable the capacity price to signal when new entry is needed; in order for this process
to work, prices must also be allowed to signal when new entry is not needed.”134
Complainant’s assertion that the purpose of ICAP is to compensate for reliability, is also overly simplistic. The purpose of the NYISO-administered capacity market is to attract new and retain existing economic capacity.135 This purpose would be undermined if uneconomic new

131 See ISO New England, 135 FERC ¶61,029 at P 252 (2011) (“The utility regulatory paradigm under which the Supreme Court decided Hope and Bluefield has changed.”).

132 320 U.S. 591 (1944) (“Hope”).

133 See ISO New England, 135 FERC ¶61,029 at P 254 (2011), citing, ISO New England, 128 FERC ¶ 61,023 at P 34 (2004), Bridgeport Energy, LLC, 113 FERC ¶ 61,311 (2005).

134 See ISO New England, 138 FERC ¶61,027 at P 146 (2012).

135 New York Independent System Operator, Inc., 111 FERC ¶61,117 at P 25 (2005) (“The

purpose of an ICAP requirement is to ensure a minimum amount of capacity in the market to promote
reliability, and thus, to elicit additional capacity that might not otherwise enter the market); New York
Independent System Operator, Inc., 118 FERC ¶61,182 at P 17 (2007) (Just and reasonable capacity
market rules “provide a level of compensation that will attract and retain needed infrastructure and thus
promote long-term reliability while neither overcompensating nor under-compensation generators”).

entrants were entitled to compensation to offset the impact of market power mitigation rules.
Such a rule would subvert the BSM Rules and also deter economic capacity investment.

C. Complainant Has Not Established that the HTP Project Will Actually

Provide “Substantial and Easily Quantifiable” Reliability Benefits to the NYISO Beyond Those Reflected in the Capacity Market Price

1. Complainant Has Not Shown that Any Reliability Benefits

Attributable to the HTP Project Are Needed

Complainant has failed to establish any factual basis for paying the HTP Project for

bringing “reliability benefits.” It simply asserts that the HTP Project will provide “substantial and easily quantifiable reliability benefits . . .” by “decreasing the NYISO Installed Reserve
Margin (“IRM”) and the Minimum Locational Capacity Requirement (“LCR”) for the New York City and Long Island capacity zones.”136

These assertions are not accurate. The mere fact that the HTP Project might be available to provide “emergency assistance” or might contribute to a near-term IRM or LCR reductions does not mean that it will provide “substantial” reliability benefits. Nor does it mean that the NYISO system has any need for such incremental reliability benefits.

The two most recent Reliability Needs Assessments (“RNAs”) completed before the
Complaint was filed both indicated that New York’s bulk power system had no need for
additional reliability benefits. Both studies concluded that there would be no Reliability Needs
in the New York City area through at least 2020.137 These RNAs were finalized in January 2009

136 Complaint at 52.

137 Specifically, the 2009 RNA identified no Reliability Needs between 2009 and 2018. See <

http://www.nyiso.com/public/webdocs/services/planning/reliability_assessments/RNA_2009_Final_1_13
_09.pdf >. The 2010 RNA identified no Reliability Needs between 2011 and 2020. See
<http://www.nyiso.com/public/webdocs/services/planning/reliability_assessments/2010_Reliability_Need
s_Assessment_Final_Report_September_2010.pdf>. In both cases, the absence of Reliability Needs was
“due to increased generation resources and the reduced load forecast resulting from the economic

and September 2010, respectively, and thus capture the long-range reliability outlook

immediately before, and for numerous years after, the HTP Project’s expected entry date.138

The most recently completed RNA139 indicates that a Reliability Need may arise in New
York City starting in 2020.140 That possibility, however, is no justification for awarding non-
market based compensation to the HTP Project more than seven years in advance. This is
especially true given that the HTP Project is a merchant transmission project that is supposed to
bear all market risk and has not been selected to address any potential future Reliability Need.141
Furthermore, the Commission-accepted ICAP Demand Curves define the level of excess capacity above the minimum needed to satisfy the IRM and LCRs that is beneficial. They
therefore establish a threshold beyond which new capacity additions will not truly bring
reliability benefits.142 The ICAP Demand Curve level of excess capacity is carefully set at a
point that balances the need to ensure reliability against the need to avoid imposing excessive
costs on customers. As the MMU previously explained, the level of excess capacity incorporated in the currently effective ICAP Demand Curves, is:

recession” and to “[i]ncreased participation in the NYISO’s demand response program.” See 2012
Reliability Needs Assessment Report, “Final Draft Report” (August 29, 2012) available at
<http://www.nyiso.com/public/webdocs/committees/mc/meeting_materials/2012-08-
29/agenda_04_2012_RNA_Final_Draft_Report_82112.pdf> (“Draft 2012 RNA”).

138 It also predates and continues nearly a decade beyond HTP’s asserted “go-forward date” of December 2009 or January 2010.

139 Pursuant to a 2010 tariff revision, the Reliability Needs Assessment is performed every two years. Accordingly, no RNA was issued in 2011.

140 See 2012 Reliability Needs Assessment: Final Report (September 18, 2012) (“2012 RNA”)
<http://www.nyiso.com/public/webdocs/services/planning/reliability_assessments/2012_RNA_Final_Rep
ort_9-18-12_PDF.pdf>.

141 See 2012 RNA at 6-7 (explaining the potential for transmission security violations as early as
2013 in Load Zones B, C, and G that may require attention from National Grid, RGE and Orange &
Rockland and the potential resource adequacy issues starting in 2020 in New York City and elsewhere).

142 See also EL11-50 September 10 Order at P 142 wherein the Commission discusses that buyer-
side mitigation is consistent with and does not impair introducing new capacity to meet reliability needs.

high enough so that investment and retirement decisions can be expected to lead to adequate planning reserves over the long term to maintain reliability.
Therefore, they will not result in ICAP Demand Curves that under-compensate
suppliers, but instead should produce “consistent reliability signals” in New York State that the Commission recognized would prevent capacity levels from falling to the minimum requirement. At the same time, they are not so high as to risk
inflating the ICAP Demand Curves to levels which would inefficiently perpetuate New York’s existing capacity surplus.143

The Commission has likewise recognized that “the assumption of excess capacity must
balance competing interests, i.e., avoid imposing excessive capacity costs on customers . . . ,
while ensuring sufficient incentives such that levels of capacity do not fall below the minimum
requirement.”144 The NYISO’s market design and market-based planning processes are designed
to rely on market responses to ensure that system reliability is maintained above the minimum
level. Complainant has not explained why the HTP Project should receive non-market based
compensation for capacity that the ICAP Demand Curve level of excess indicates is not needed.
It has not even addressed the question of whether paying non-market compensation to resources
that claim to provide “reliability benefits” would upset the balance that the level of excess is
meant to establish.

Thus, even if Complainant were correct that the HTP Project would incrementally

enhance reliability, it has not shown that it would confer a “substantial benefit” that is actually needed by the NYISO, its Customers, or consumers.

2. Complainant Has Not Shown that Reliability Benefits Attributable to

Individual Transmission Facilities Are Practicably Quantifiable

To the extent that the HTP Project might provide actual reliability benefits they would
hardly be “easily quantifiable.” Given the networked nature of the bulk power system, the

143 Compliance Filing and Request for Flexible Effective and Implementation Dates, Docket No. ER11-2224-004 at Attachment 4, Affidavit of Dr. David B. Patton at P 13 (filed March 29, 2011).

144 New York Independent System Operator, Inc., 136 FERC ¶ 61,192 at P 54 (2011).

reliability benefit produced by any single transmission project is contingent on, and

interdependent with, the relative contribution that all other transmission lines, generators, and demand side resources make to reliability.

Complainant greatly oversimplifies the difficulties of quantification when it suggests that
the NYISO would only have to determine a reliability benefit value for the HTP Project, and
potentially for other “similarly situated” merchant transmission lines.145 The reality is that all
transmission lines, both regulated and merchant, are similarly situated to the HTP Project. All
existing and new transmission facilities have the potential to provide “reliability benefits” but the
actual benefit that they may provide is relative to all other facilities and to the system’s actual
reliability needs. Complainant has not articulated, and the NYISO is unaware of, any principled
basis for treating the HTP Project differently from other transmission facilities.
As discussed below, it would be incompatible with the design of competitive markets, including the NYISO-administered markets, to compensate asset owners based on the varying reliability impacts over time of each individual component of the bulk power system. Doing so would also undermine the NYISO’s reliability planning processes which rely on market price signals to drive the development of market-based solutions that maintain system reliability.
Finally, Complainant’s proposed formula for calculating reliability benefits rests on the erroneous premise that a change in the IRM must change the level of UCAP purchased. The IRM is a measure of existing resources needed to provide a certain level of UCAP with the
system under stress. It therefore does not necessarily correspond to a change in the amount of
UCAP purchased.

145 Complaint at 61.

Thus, Complainant has not met its burden of showing that the HTP Project would bring “substantial” or “easily quantifiable” reliability benefits.

D.Providing Non-Market-Based Compensation to a New Entrant that Is

Properly Subject to an Offer Floor Would Violate Commission Policy and

Precedent

1.Complainant’s Request Is Prohibited by Commission Policy

Requiring Merchant Transmission Projects to Assume All Market

Risk

Complainant alleges that the HTP Project should receive reliability benefits

compensation because the Commission has found that “merchant projects which do not have a guaranteed cost recovery from captive customers, must still have a reasonable opportunity to recover the costs of their investment.”146

As stated above, the Complaint has not established a factual justification for providing
non-market-based compensation to the HTP Project. The various legal and conceptual flaws in
Complainant’s claim are addressed below. It bears emphasizing at the outset, however, that the
HTP Project is a merchant transmission project that has voluntarily assumed full market risk.
Complainant’s “reliability benefits” compensation proposal would convert the NYISO’s
customers into “captive customers” of the HTP Project, in direct violation of Commission
merchant transmission project policy. The proposal should be rejected for that reason alone.
Under a long line of Commission precedents, 147 developers seeking negotiated rate
authority for a merchant transmission project must agree to assume full market risk. Developers

146 Complaint at 56.

147 See, e.g., Champlain Hudson Power Express, Inc., 132 FERC ¶ 61,006 at P 22 (2010)

(accepting negotiated rates because the project’s developer “has agreed to bear the risk … [that it] will
succeed or fail based on whether a market exists for its services and the fact that [there is] no ability to
pass on any costs to captive ratepayers”); TransEnergie U.S., Ltd., 91 FERC ¶ 61,230, at 61,838 (2000)
(accepting negotiated rates because the project “will provide benefits to electric consumers and producers
… while imposing no risk or cost on captive customers in any market”); Chinook Power Transmission,

must further confirm that they are not building a merchant project within the footprint of their
own (or an affiliate’s) traditionally regulated transmission system. The Commission also must
find that there are no captive customers that would be required to pay the costs of the project.148

These precedents are fully applicable to the HTP Project. The Commission’s order accepting the HTP Project’s negotiated rate proposal stated that:

The Commission concludes that Hudson Transmission's request for authority to charge negotiated rates for service on the Project is just and reasonable. Hudson Transmission meets the definition of a merchant transmission owner because it assumes all market risk associated with the Project and has no captive customers. Hudson Transmission has agreed to bear the risk that the Project will succeed or fail based on whether a market exists for its services. Hudson Transmission also has no ability to pass on any costs to captive ratepayers.149

Complainant acknowledged and represented that it took full market risk in its May 3,
2011, Application for Authority to Sell Transmission Rights at Negotiated Rates which stated
that:

HTP will assume the full market risk of the Project. HTP’s investors already have
invested tens of millions of dollars of at-risk capital in the Project with no
guarantee of any return. HTP has no captive customers. Neither HTP nor its
affiliates have a traditionally regulated transmission system in the footprint of the
Project or in any “first-tier” geographic locality. No customer is under any
obligation to purchase transmission capacity on the line. HTP will recover its
costs only from customers who voluntarily agree to purchase transmission
capacity on the Project. All project costs, fixed and operating, will be recovered

L.L.C., 126 FERC ¶ 61,134, at P 55 (2009) (“Chinook”) (approving negotiated rates because the projects
“will succeed or fail based on whether a market exists for their services; they have no ability to pass on
any costs to captive ratepayers”); MATL LLP and Montana Alberta Tie, Ltd, at 139 FERC ¶ 61,208 at P

15 (2012) (accepting negotiated rates because there are no “captive customers … [thus it] will not be able to pass on any costs of the Project to captive ratepayers”).

148 Chinook at P 38 (“To approve negotiated rates for a merchant transmission project, the

Commission must find that the rates are just and reasonable. In determining whether negotiated rates are just and reasonable, the Commission first looks to whether the merchant transmission owner has assumed the full market risk for the cost of constructing a particular transmission project and is not building within the footprint of its own (or an affiliate’s) traditionally regulated transmission system. In such a case, there are no “captive” customers who would be required to pay the costs of the project.”).

149 Hudson Transmission Partners, LLC, 135 FERC ¶61,104 at P 18 (2011).

through the revenues received from customers that voluntarily acquire

transmission capacity on the Project. Because HTP has no captive customers, the Project will succeed or fail based on whether a market exists for transmission capacity on the Project. HTP accepts this risk.150

These statements were made years after the Commission unambiguously established that
controllable lines into New York City, including specifically the HTP Project, would be subject
to the BSM Rules.151 Complainant thus knowingly and expressly assumed the risk that the HTP
Project could be subject to Offer Floor mitigation and that if its capacity did not clear, the HTP
Project would earn less revenue. A developer that assumes all market risk associated with its
project has “no ability to pass on any costs to captive customers.”152 It would be wholly

inappropriate, and unprecedented, to allow Complainant to retroactively shift its risks to the NYISO’s customers.

2. Providing Additional Compensation to the HTP Project Is Contrary

to Commission Precedent and the NYISO’s Tariffs

a.The NYISO Already Has a Process for Identifying and

Compensating Projects that Are Needed to Address Reliability

Needs

Complainant argues that it should be entitled to receive non-market-based compensation
if the HTP Project is subject to Offer Floor mitigation under the “principles of cost causation”
and the “beneficiaries pay” concept.153 The NYISO’s Comprehensive System Planning Process

150 Application for Authority to Sell Transmission Rights at Negotiated Rates and Request for Expedited Action at 25, Docket No. ER11-3017-000 (filed March 3, 2011).

151 See March 2008 Order at P 21 (“because both transmission and generating capacity are paid based on the same principle of making capacity available in-City, there should be no special exemption. Controllable transmission and generating capacity should be subject to the same mitigation.”)

152 Chinook at P 55.

153 Complaint at 59.

(“CSPP”), provides for the identification and selection for cost recovery of projects that are

identified as a regulated transmission solution to address identified Reliability Needs.154

The NYISO has not issued a request for solutions to meet a Reliability Need. The HTP Project is clearly not a response to any such Reliability Need. The Commission should not allow a party to claim that it is entitled to revenues based on “reliability benefits” absent a
determination pursuant to Attachment Y of the NYISO OATT that it is actually needed to
address an identified Reliability Need.155

b. HTP Is Not Eligible for Non-Market Based Compensation

Under the Commission’s Precedent Governing Reliability Must Run Agreements

The circumstances in this proceeding are clearly distinguishable from those in

proceedings where the Commission has accepted the use of Reliability Must Run (“RMR”)

agreements. Commission precedent has allowed generators to obtain “RMR” compensation to
the extent that an ISO/RTO has found that a resource that would otherwise exit the market is
necessary for reliability.156 Where an ISO/RTO identifies such a unit, and has a mechanism in
place for entering into RMR agreements, the Commission has authorized them to preserve a
resource owner’s “reasonable opportunity” to recover its costs. The Commission has frequently

154 See NYISOOATT Attachment Y § 31.2 (establishing the processes for administration of the NYISO’s reliability planning process).

155 Note that the NYISO is currently considering, through its stakeholder process, possible
mechanisms to compensate resources identified as needed for reliability. That stakeholder process
however has not been completed and no such mechanism currently exists in the NYISO tariff.

156 See, e.g., PJM Interconnection, L.L.C., 135 FERC ¶ 61,190 (2011) (accepting a new PJM rate schedule governing operation of two generating units the PJM determined would be needed past the date of their planned deactivation); CalPeak Power, LLC, 107 FERC ¶ 61,026 (2004) (accepting proposed
Reliability Must-Run Agreement between CalPeak Power and California Independent System Operator Corporation (“CAISO”) that establishes the terms for operating a power plant CAISO determined would be needed for local reliability).

emphasized that RMR agreements are disfavored, because they can suppress prices and

discourage new investments. Market-based arrangements are strongly preferred.157

The HTP Project has not been identified as critical to reliability, nor has the NYISO

identified a Reliability Need that the HTP Project could resolve. The NYISO is unaware of any Commission precedent, and Complainant cites none supporting the proposition that, a resource may simply declare itself to provide “reliability benefits” and therefore claim an entitlement to compensation. Complainant has presented no reason for the Commission to depart from its precedent and expand the availability of non-market based compensation in this case. Doing so would promote the proliferation of non-market compensation arrangements, and all of the
adverse consequences, that the Commission has sought to avoid.

c.The Other Cases Referenced by HTP Do Not Support its

Request for Compensation

Complainant cites several orders from “loop flow” cases and the Commission’s precedent regarding the “beneficiaries pay” principle to support its request for additional compensation.158 None of these rulings are apposite.

Nothing in Order No. 1000159 supports Complainant’s theories.160 Order No. 1000 is

clear that to be eligible for regulated cost recovery projects must be selected through a regional

157 See, e.g., Bridgeport Energy, LLC, 118 FERC ¶ 61,243 at P 41 (2007) (explaining that

reliability must run agreements should only be used as a “last resort,” because they “suppress market-

clearing prices and deter investment in new generation”); Devon Power LLC , 115 FERC ¶ 61,340 at P 7
(2006) (explaining that in a series of orders addressing RMR agreements, “the Commission rejected the
majority of the RMR agreements, out of concern about the effect widespread use of such contracts could
have on the competitive market,” citing, Devon Power LLC, 102 FERC ¶ 61,314 (2003); Devon Power
LLC, 103 FERC ¶ 61,082 (2003); Devon Power Company, 104 FERC ¶ 61,123 (2003); PPL Wallingford
Energy LLC, 103 FERC ¶ 61,185 (2003); PPL Wallingford Energy LLC, 105 FERC ¶ 61,324 (2003).

158 Complaint at 59-60.

159 Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & Regs. ¶ 31,232 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132 (2012), order on reh’g, Order No. 1000-B, 141 FERC ¶ 61,044 (2012).

planning process.161 As explained above, the NYISO’s tariff contains a process for requesting
proposed solutions to identified Reliability Needs but the HTP Project was not developed under
that process.

Complainant’s citations to precedent generally establishing the beneficiaries pay

principle are clearly distinguishable 162 Its references to American Electric Power163 and other similar decisions 164 are irrelevant. Those cases all address situations in which
transactions benefited the parties to them but caused adverse impacts to third parties and there were no tariffs, contracts, or other arrangements to compensate them.

160 Complaint at 58-59.

161 See Order No. 1000 at P 539 (stating that “our cost allocation reforms are tied to our

transmission planning reforms, which require that, to be eligible for regional cost allocation, a proposed
new transmission facility first must be selected in a regional transmission plan for purposes of cost
allocation, which depends on a full assessment by a broad range of regional stakeholders of the benefits
accruing from transmission facilities planned according to the reformed transmission planning process”).

162 Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 (D.C. Cir. 2004) (did not concern the allocation of costs of transmission upgrades, but rather the allocation of MISO’s administrative costs) Illinois Commerce Comm’n v. FERC, 576 F.3d 470 (7th Cir. 2009) (The court rejected arguments that the costs of all new 500 kV and above transmission facilities should be allocated pro rata to all PJM
members, because there was no evidence of that all PJM members benefited from the facilities); KN
Energy, Inc. v. FERC, 968 F.2d 1295 (D.C. Cir. 1992) (benefits were allocated to a wider group than
normally considered under Commission precedent because the problem of the resolution of take-or-pay claims in the natural gas industry was of “an extraordinary nature … [and] requires the aid of the entire
industry to solve it”); Western Massachusetts Elec. Co. v. FERC, 165 F.3d 922 (D.C.Cir. 1992) (required the recovery of interconnection upgrades with system-wide benefits through the utility’s rate base rather than requiring the developer to pay for such upgrades).

163 Compliant at 59, citing American Electric Power Service Corp., 49 FERC ¶ 61,377 at 61,381 (1989) (rejecting a request to consider loop flows, as outside the scope and indicating that addressing such issues was “for the interconnected parties as the owners of utility systems to establish mutually acceptable operating practices”).

164 See East Kentucky Power Coop. Inc., 114 FERC ¶61,035 at P 40 & n. 29 (2006) (finding that a
burden had not been demonstrated to justify compensation for loop flows); Cincinnati Gas & Elec. Co.
and PSI Energy, Inc., 69 FERC ¶61,005 at 61,037 (1994) (rejecting a request to hold a hearing regarding
loop flows, because the entities to the transaction had committed to integrate the system and there was no
claim of impairment to reliability of service or prevention of power sales to other utilities by the affected
entity).

By contrast, the NYISO has clear rules in place governing the compensation of suppliers that provide capacity, energy, and/or ancillary services. These rules are applicable to the HTP
Project. As noted above, rightsholders to the HTP Project UDRs will receive compensation
under the rules for capacity offers they choose to make, when the Market-Clearing Prices exceed the Offer Floor.165 To the extent that the HTP Project’s capacity revenues may be lower under the BSM Rules, that reduction is a necessary part of a Commission-approved mitigation regime designed to deter uneconomic entry.

3. Subjecting the HTP Project to an Offer Floor Does Not Constitute a

Compensable “Taking” of HTP’s Property

The Commission must also reject Complainant’s suggestions that there would somehow
be an “unlawful appropriation” of its property if the HTP Project is subject to an Offer Floor
without receiving offsetting non-market based compensation.166 A “regulatory taking” is one in
which a regulation is “so onerous that its effect is tantamount to a direct appropriation or
ouster”167 that deprives a property owner of “all economically beneficial use” of its property.168
Complainant has not come close to establishing that it has, or will be, subject to such a deprivation of property rights. The Commission previously rejected claims by capacity suppliers that its refusal to ensure that they were compensated at a desired level constituted a “taking.” 169

165 Under the BSM Rules, the “portion of a resource’s UCAP … that has cleared for any twelve, not-necessarily consecutive months shall cease to be subject to the Offer Floor requirement. See Services Tariff Section 23.4.5.7.

166 Complaint at 56.

167 Lingle v. Chevron U.S.A. Inc., 544 U.S. 528, 537, 125 S.Ct. 2074, 161 L.Ed.2d 876 (2005). 168 Lucas v. South Carolina Coastal Council, 505 U.S. 1003 (1992).

169 See ISO New England, 135 FERC ¶61,029 at P 251 (2011) (“We reject the view, however, that
a resource that provides capacity in New England has a property right to be compensated at its desired
level for that service such that an abrogation of that property right is prohibited by the Fifth
Amendment.”), order on reh’g, 138 FERC ¶61,027 at P 140 (2011) (“Because resources are not

Offer Floor mitigation will not “prevent” 170 the HTP Project from participating in the NYISOadministered capacity market.171 It would merely require that any capacity offers be at or above the mitigated level, and be made into the ICAP Spot Market Auction. The mitigated level is
determined through rules that have been found to be just, reasonable, and necessary to deter the exercise of buyer-side market power. The HTP Project would also have an opportunity to offer into the capacity market during a Capability Year in which it has not elected to return its UDRs. It will always be able to earn capacity auction revenues to the extent that the Market-Clearing
Prices exceed the Offer Floor. Thus, Offer Floor mitigation will, at most, deprive the HTP
Project of some portion of the revenues it could have earned absent mitigation. This falls far
short of what is required to establish a taking.172

Moreover, the HTP Project’s capacity will cease to be subject to the Offer Floor to the
extent that it clears in the capacity auctions for twelve not necessarily consecutive months.173
The impact that mitigation may have on the HTP Project’s opportunity to earn capacity revenues
is bounded. Complainant has also acknowledged that “the length of mitigation is unknown.”174

compelled to provide [capacity] service at a price that is unacceptable to them, we found that there was no confiscation or taking of private property.”).

170 See Complaint at 65.

171 New York Independent System Operator, Inc., 124 FERC ¶ 61,301 at P 27 (2008) (explaining that buyer side mitigation rules “assure that new capacity will not be allowed to distort market supply curves and inefficiently depress market clearing prices below a competitive level. This is accomplished by setting a bid floor applied to new capacity for a stated period”). Thus, the Offer Floor does not prevent projects from entering but instead allows each project to make an entry decision based on its own
estimate of whether it would clear in the market.

172 Complainant’s own actions have limited its opportunity to earn capacity revenues from the

HTP Project. HTP currently has elected to only pay for firm withdrawal rights in PJM for 320 MW of the 660 MW of capacity.

173 See Services Tariff Attachment H at § 23.4.5.7.5. (“UCAP Clearing Rule”). 174 See Complaint at 65.

It has stated that “it is difficult to predict with any certainty”175 what capacity prices will be years in the future. Consequently, it is not credible for Complainant to say that Offer Floor mitigation amounts to an “unlawful appropriation” of its property.

IV. COMPLIANCE WITH COMMISSION RULE 213(c)(2)(i)

Attachment 1 to this Answer addresses the formal requirements of Commission Rule 213(c)(2) in order to ensure the NYISO’s full compliance with them.

V.ATTACHMENTS

The NYISO attaches the following documents in support of the facts of this answer:  Attachment 1- Compliance with Commission Rule 213(c)(2)
 Attachment 2 - Affidavit of Daniel A. Jerke

 Attachment 3 - July 22, 2011 Supplemental Affidavit of Joshua A. Boles filed in
Docket No. EL11-42-000

175 See Complaint at 65.

Robert E. Fernandez, General Counsel
Raymond Stalter, Director of Regulatory Affairs * Gloria Kavanah, Senior Attorney

New York Independent System Operator, Inc.

10 Krey Boulevard

Rensselaer, NY 12144
Tel: (518) 356-6103
Fax: (518) 356-7678
rfernandez@nyiso.com
rstalter@nyiso.com

gkavanah@nyiso.com

* Persons designated for service.

VII. CONCLUSION

* Ted J Murphy

Hunton & Williams LLP
2200 Pennsylvania Ave, N.W. Washington, D.C. 20037
Tel: (202) 955-1588

Fax: (202) 778-2201
tmurphy@hunton.com

* Vanessa A. Colón
Hunton & Williams LLP
Bank of America Center
700 Louisiana St., Suite 4200 Houston, TX 77002

Tel: (713) 229-5724
Fax: (713) 229-5782
vcolon@hunton.com

CERTIFICATE OF SERVICE

I hereby certify that I have this day caused the foregoing document to be served upon each person designated on the official service list compiled by the Secretary in this proceeding in accordance with the requirements of Rule 2010 of the Commission Rules of Practice and Procedure, 18 C.F.R. § 385.2010 (2012).

Dated at Washington, D.C. this 13th day of November, 2012.

/s/ Catherine Karimi

Catherine Karimi

Hunton & Williams LLP

2200 Pennsylvania Ave., NW
Washington, DC 20037
Tel: (202) 955-1500
Fax: (202) 778-2201

E-mail: ckarimi@hunton.com

Attachment 1

Compliance with Commission Rule 213(c)(2)

A. Specific Admissions and Denials of Material Allegations

In accordance with Commission Rule 213(c)(2)(i), to the extent practicable and to the best of the NYISO’s knowledge and belief at this time, the NYISO admits or denies below the factual allegations in the Complaint. To the extent that any fact or allegation in the Complaint is not specifically admitted below, it is denied. Except as specifically stated herein, the NYISO does not admit any facts in the form or manner stated in the Complaint. The NYISO's denials are equally applicable to the BSM rule analyses that it conducted for the HTP Project in 2011 and to the re-test that it completed in November 2012.

1.Denials

•The NYISO denies all allegations and characterizations that it has improperly

implemented or violated its tariff, otherwise acted unjustly or unreasonably, or in an

unduly discriminatory manner, when the NYISO determined that the HTP Project would be subject to an Offer Floor. (Complaint at 3, 5, n.5, 29, 30, 31, 62).

• The NYISO denies all allegations that it conducted its mitigation exemption or Offer

Floor determination for the HTP Project using arbitrary and unreasonable assumptions,
that its determination included ad hoc adjustments that lacked a basis in the Services
Tariff or economic theory consistent with the Services Tariff, and that it unduly
discriminated against merchant transmission facilities. (Complaint at 3, 24, 28, 29, 31,

50. 62).

• The NYISO denies all allegations that its determination that the HTP Project is subject to

an Offer Floor is preventing the HTP Project from serving “the purpose for which it was developed and constructed.” (Complaint at 3).

• The NYISO denies all allegations that its determination will prevent the HTP Project

from participating in the capacity market. The NYISO neither admits nor denies that the
application of the Offer Floor in the determination will prevent the HTP Project from
earning capacity revenues. Whether or not the HTP Project would offer capacity, or
whether the capacity offers would clear in an ICAP Spot Market Auction is not relevant
to the question of whether the NYISO has properly implemented the BSM Rules.
(Complaint at 1, 5, 52).

• The NYISO denies all allegations that it wrongly conducted its determination of the HTP

Project concurrently with Class Year 2010 projects or that its examination of the HTP Project concurrently with Class Year 2010 projects violated its tariffs. (Complaint at 4, 24, 25, 32, 33, 38, 39, 40, 41, 42, 43, 44, 50, 62).

• The NYISO denies all allegations that its analysis was based on an inappropriate “go-

forward” date, causing it to underestimate energy revenues for the HTP Project and use
the incorrect ICAP Demand Curves. (Complaint at 4, 25, n. 78, 34, 35, 36, 37, 38, 39, 50,
62).

•The NYISO denies all allegations that its actions “deprived” the HTP Project of the

ability to “lock in” its “initial Offer Floor” that was 50 percent lower than the Offer Floor established for it in the December 22, 2011 determination. (Complaint at 39).

• The NYISO denies all allegations that its approach to analyzing the HTP Project changed

during June 2011 and December 2011. (Complaint at n. 69).

• The NYISO denies all allegations that its application of a scaling factor to its calculations

of projected net energy revenues for the HTP Project violated the Services Tariff, the
Filed Rate Doctrine, and the Rule of Reason. (Complaint at 4, 26, 44, 45, 51. 62).

• The NYISO denies all allegations that application of a scaling factor unduly discriminates

against merchant transmission facilities. (Complaint at 45).

• The NYISO denies all allegations that application of a scaling factor is inconsistent with

“market fundamentals.” The NYISO neither admits nor denies that the application of a scaling factor is inconsistent with Complainant’s business model or agreements with NYPA. Whether or not Complainant’s business plans and agreements conflict with the requirements of the Services Tariff is not relevant to the question of whether the NYISO has properly implemented the BSM Rules (Complaint at 46).

• The NYISO denies all allegations that it did not exclude “sunk costs” from its calculation

of the HTP Project’s Unit Net CONE and that it treated the HTP Project differently from other new entrants in this area. (Complaint at 4, 26, 27, 47, 48, 51. 62).

• The NYISO denies all allegations that its use of PJM base residual auction (“BRA”)

prices to estimate the cost of capacity delivered by the HTP Project into PJM was

unreasonable and all claims that it should use adjusted BRA prices or incremental auction prices. (Complaint at 4, 27, 48, 49, 51, 62).

•The NYISO denies all allegations that the HTP Project “will provide substantial and

readily quantifiable reliability benefits” to the NYCA. (Complaint at 5, 52, 53, 54, 55,

62).

• The NYISO denies all allegations that it should be directed to develop a mechanism to

compensate the HTP Project for the value of any “reliability benefits” that it may provide in the event that it is subject to an Offer Floor. (Complaint at 5, 52, 60, 61, 62, 63).

• The NYISO denies all allegations that its current tariff rules are unfair, conflict with the

“beneficiaries pay” principle, or deprive the Complainant’s of their “right to receive just
and reasonable compensation,” or constitute an “unlawful appropriation” of
Complainant’s property. (Complaint at 5, 30, 31, 52, 55, 56, 57, 58, 59, 60, 62, 63).

2.Admissions

•The NYISO admits that it initially adopted its buyer-side market power mitigation

measures in 2008, and that the rules are intended to deter uneconomic entry.(Complaint

at 2).

• The NYISO admits that it conducted the exemption and Offer Floor determination for the

HTP Project under the BSM Rules, that it issued determinations to the HTP Project on

June 9, 2011, September 9, 2011, October 5, 2011, and December 22, 2011 and that each

determination concluded that the HTP Project was subject to an Offer Floor. (Complaint at 3, 23).

• The NYISO admits that the HTP Project is the first transmission facility that has been

subjected to the BSM Rules in the NYISO. (Complaint at 3).

• The NYISO admits that it conducted its analysis for the HTP Project concurrently with

Class Year 2010 projects. (Complaint at 4, n. 68).

• The NYISO admits that it applied a scaling factor to determine the HTP Project’s

projected net energy revenues. (Complaint at 4, 26).

• The NYISO admits that it used the PJM BRA prices to estimate the cost of capacity

delivered by the HTP Project from PJM. (Complaint at 4).

• The NYISO admits that it provides open access transmission service, maintains reliability

and administers the competitive wholesale markets for electricity, capacity, and ancillary services in New York State. (Complaint at 8).

•The NYISO admits that, pursuant to the provisions in its Services Tariff, it administers

the ICAP auctions. (Complaint at 8).

•The NYISO admits that the HTP Project is a Class Year 2008 project. (Complaint at 9,

21).

•The NYISO admits that Attachment S of the OATT establishes the rules regarding cost

allocation for new interconnection facilities and that such rules provide that Developers

are responsible for the costs of facilities that would not be required “but for” the proposed

project.(Complaint at 11).

•The NYISO admits that OATT Attachment S establishes rules pursuant to which

Developers seeking to participate in the ICAP market must pay costs for System Upgrade Facilities (“SUFs”) and System Deliverability Upgrades (“SDUs”) necessary to
interconnect the project. (Complaint at 11, 12).

• The NYISO admits that it examines all new facilities assigned to a given Class Year to

determine needed upgrades and that it performs the Interconnection Feasibility Study, the Interconnection System Reliability Impact Study, and the Interconnection Facilities Study as a part of that process. (Complaint at 12).

• The NYISO admits that an Interconnection Facilities Study is performed for all projects

within a given Class Year and in conjunction with the Annual Transmission Reliability Assessment and the Class Year Deliverability Study. (Complaint at 12).

• The NYISO admits that it conducts a Deliverability study process, and each Developer in

a Class Year is provided with a Project Cost Allocation, such Developers may accept or reject such cost allocation, and the process continues until no Developers remaining in a Class Year reject their cost allocations. (Complaint at 13).

• The NYISO admits that it identifies and allocates costs of SUFs and SDUs based on a

system which includes, pursuant to OATT Attachment S, existing generation and

transmission facilities, and planned generation and merchant transmission facilities that
have accepted their SUF and SDU cost allocation, as applicable. (Complaint at 13, 14).

•The NYISO admits that it proposed the basic framework for the BSM Rules in its

October 4, 2007 filing in Docket No. EL07-39 and the Commission conditionally accepted that filing on March 7, 2008. (Complaint at 14).

• The NYISO admits that a new entrant is subject to mitigation unless it passes either the

Part A or Part B tests in Section 23.4.5.7.2 of Attachment H to the Services Tariff. (Complaint at 14, 15).

• The NYISO admits that it filed additional revisions to its BSM Rules on September 27,

2010 in Docket No. ER10-3043. The NYISO admits that the revisions included the

addition of language that would ensure that a new entrant would have information

regarding its mitigation exemption or Offer Floor determination prior to its acceptance of its Project Cost Allocation. (Complaint at 17, 18).

• The NYISO admits that its additional revisions to the BSM Rules proposed the adoption

of the “Three-Year Rule” and that the Commission issued an order on its September 10 ER10-3043 Filing, accepting in part and rejecting in part the proposed modifications, effective November 27, 2010. (Complaint at 18).

• The NYISO admits that the Commission accepted the Three-Year Rule, beginning with

projects in Class Year 2009 in November 2010 and for determinations made after the
effective date, but directed that the rule not apply to projects in Class Year 2008 for
which determinations had not been made. Instead, such projects would be evaluated
under the previously effective “Reasonably Anticipated Entry Date” rule. (Complaint at
19).

• The NYISO admits that it permits generation from outside the NYISO footprint to be

offered into the ICAP auctions and to satisfy the NYC and LI Minimum Locational Capacity Requirements so long as such capacity is combined with external UDRs. (Complaint at 20).

• The NYISO admits that entities may make an annual election to return all or a portion of

their External UDRs to the NYISO and an entity that makes such election cannot offer

External capacity utilizing the “returned” rights to External UDRs for the Capability Year for which it makes such election. (Complaint at 21).

• The NYISO admits that it communicated with HTP regarding the HTP Project’s buyer-

side mitigation examination and Offer Floor determination and that it formally requested required information and began the process for the HTP Project on September 28, 2010. (Complaint at 22).

• The NYISO admits that it applied the ICAP Demand Curves accepted in Docket No.

ER11-2224 to the HTP Project. (Complaint at 26).

B.Defenses

In accordance with Commission Rule 213(c)(2)(ii), the NYISO sets forth the following defenses.

• Complainant has failed to meet its burden of proof under Sections 206 and 306 of the
FPA, and Commission Rule 206.

•Complainant has not shown that the NYISO violated or improperly implemented its

tariffs, let alone that the NYISO made “arbitrary, unreasonable, and unduly discriminatory assumptions.”

• Complainant has not shown that the NYISO “unduly discriminate[d] against merchant

transmission facilities” in general or the HTP Project in particular, when the NYISO determined that the HTP Project would be subject to Offer Floor mitigation.

•Complainant has not shown that there is any basis for its allegations that there is a

systematic “bias” against the HTP Project.

•Complainant has not shown that the NYISO’s determination that the HTP Project is

subject to an Offer Floor, based on the application of the BSM Rules to the HTP Project

is inconsistent with the NYISO’s capacity market design and sound economic theory.

•Complainant’s assertions that the BSM Rules lack transparency is an impermissible

collateral attack on the June 22 Order.

• Complainant has not shown that the NYISO’s evaluation of the HTP Project concurrent

with Class Year 2010 projects, application of a scaling factor, calculated level of sunk costs, or use of PJM BRA prices was contrary to the tariff or otherwise unjust and
unreasonable, let alone that they were “absurd” or that they could have only been applied in “blatant violation” of the Services Tariff.

• Complainant has not shown that it should be compensated through a NYISO-

administered tariff for what it labels as “reliability benefits” that might arise due to the
existence of the HTP Project. Such compensation would not be justified, is not legally
required, would be inconsistent with Commission precedent, the HTP Project’s
assumption of all market risk as a merchant transmission facility, and the fundamental
design of the NYISO-administered markets, and would defeat the purpose of the BSM
Rules.

C.Proposed Resolution Process

Commission Rule 213(c)(4) states that an answer “is also required to describe the formal or consensual process it proposes for resolving the complaint.” As explained in the Complaint, the NYISO and Complainant have had multiple discussions regarding the application of the BSM Rules to the HTP Project and Complainant states it does not believe that further informal discussions will resolve the issues raised in the Complaint. The NYISO requests that the
Complaint be dismissed based solely on the pleadings in this proceeding.

55430.000134 EMF_US 42846410v2

UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Hudson Transmission Partners, LLC)

v.)Docket No. EL12-98-000

New York Independent System Operator, Inc.)

AFFIDAVIT OF DANIEL A. JERKE

Mr. Daniel A. Jerke declares:

1.I have personal knowledge of the facts and opinions herein and if called to testify

could and would testify competently hereto.

I.Purpose of this Affidavit:

2.I submit this affidavit in support of the Answer of the New York Independent System

Operator, Inc.’s (“NYISO”) to the Complaint filed by Hudson Transmission Partners,
LLC (“HTP”) (“Answer”). HTP challenges the NYISO’s December 2011
determination that the Hudson Transmission project (“HTP Project”) should be
subject to an Offer Floor1 under the New York City (“In-City”) buyer-side market
power mitigation measures (“BSM Rules”) (the “December 2011 Determination”).
The Commission directed the NYISO to retest HTP and the NYISO did so. The
NYISO again determined that the HTP Project is subject to an Offer Floor. The

1 Terms with initial capitalization that are not otherwise defined herein have the meaning set forth in the Answer, and if not defined therein, then the NYISO’s Market Administration and Control Area Services Tariff (Services Tariff), as modified by Commission’s June 22, 2012 Order (Astoria Generating Company, L.P., et al. v. New York Independent System Operator, Inc., 139 FERC ¶ 61,244 (2012)), and accordingly as described in the NYISO’s August 6, 2012 compliance filing in ER12-2414.

NYISO announced that redetermination on November 6, 2012 (“November 2012 Retest Determination”).

3. This affidavit responds to the claims set forth in section IV. A. 1. through IV. A. 4. of

the Complaint. I demonstrate that the NYISO’s application of the BSM Rules with
respect to the HTP Project adhered to the requirements of Services Tariff Section 23
(Attachment H) and Section 30 (Attachment O) and to the relevant Commission
orders.

II.Qualifications

4.I am the Supervisor of the ICAP Market Mitigation staff for the NYISO’s Market

Mitigation and Analysis Department (“MMA”). My responsibilities include

administering the NYISO’s supplier-side and buyer-side capacity market power mitigation measures, which are set forth in Services Tariff Section 23.

5. I received a B.S. with dual majors in Applied Economics and Natural Resources from

Cornell University, and an M.S. in Financial Engineering and Risk Analytics from Rensselaer Polytechnic Institute.

6. Since 2009, I have been actively involved in the NYISO’s administration of the BSM

Rules and the buyer-side mitigation rules that preceded them (the “Pre-Amendment
Rules”). My ICAP market administration responsibilities have included performing
determinations under the Pre-Amendment Rules and the BSM Rules, calculating
Going-Forward Costs, identifying and evaluating possible withholding, and
implementing the monthly supply-side mitigation measures (i.e., Pivotal Supplier

measures). I have worked on all of the NYISO proceedings before the Commission that have involved these matters beginning in 2009 to the present.

7. Apart from ICAP market mitigation administration, I assist in the development of

new capacity market rules and perform periodic reviews of capacity market

outcomes. I report internally on market outcomes, and am responsible for preparing,
and have prepared the past three, annual reports to the Commission on the NYISO’s
ICAP Demand Curves and potential withholding issues in Docket No. ER01-3001, et.
al.

8. I and staff under my supervision recently prepared and posted to the NYISO’s

website a detailed narrative and numerical example describing how the BSM Rules are implemented. I and staff under my supervision performed the revised buyer-side mitigation analyses required by the Commission’s EL11-50 September 10 Order. The final buyer-side mitigation rule determinations for those projects were posted to the NYISO’s website on November 6, 2012.

9.In the course of conducting evaluations under the BSM Rules, and fulfilling my other

responsibilities for the NYISO, I have become familiar with the PJM

Interconnection’s (“PJM”) capacity market design, capacity market auctions, and the

similarities and differences between them and their NYISO analogues.

III.The NYISO’s Buyer-Side Mitigation Analysis of the HTP Project

10.In my position as Supervisor, I am responsible for the implementation of the BSM

Rules, and for ensuring that they are implemented in accordance with the NYISO’s
Tariffs, and fairly and impartially. The December 2011 Determination and the

November 2012 Retest Determination were performed in accordance with the NYISO’s Tariffs, fairly, and impartially.

11. Section 23.4.5.7.3.3 of the Services Tariff requires the NYISO to seek comment from

the MMU on analyses under the BSM Rules. The NYISO engaged the MMU

throughout the analysis of the HTP Project. That process began in September 2010
with the first data request to HTP, and continued through the issuance of the
December 2011 Determination and the re-testing required by Commission order in
Docket No. EL11-42. The MMU provided input and comments during the process
and agreed with the December 2011 Determination and the November 2012 Retest
Determination.

12. On November 6, 2012, the MMU released its assessment of the NYISO’s application

of the BSM Rules to the HTP Project (“MMU Report”).2 The MMU Report states that the NYISO reasonably concluded that the HTP Project should be subject to an Offer Floor. It identifies a few areas where the MMU would have preferred that the NYISO make different assumptions or favors a different legal interpretation of the Services Tariff. None of the MMU’s recommended improvements would, however, have resulted in the HTP Project being exempt. Various findings from the MMU Report are referenced throughout this affidavit.

13. The NYISO provided a high level of transparency to HTP. The NYISO and its

consultant, Sargent & Lundy, had frequent written and verbal communications with

2 See Assessment of the Buyer-Side Mitigation Exemption Test for the Hudson Transmission
Partners Project, Potomac Economics, Ltd. (Nov. 6, 2012) available at
<http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/HTP_Report_11-6-
12_Final.pdf> (“MMU Report”).

HTP that facilitated the NYISO’s understanding of the HTP Project. In addition, HTP was given the opportunity to provide additional information on issues with which it disagreed with the NYISO. The NYISO’s December 2011 Determination and November 2012 Retest Determination reflect its independent judgment and were independently supported by the MMU.

14. This affidavit demonstrates that both the December 2011 Determination and the

November 2012 Retest Determinations conformed to the Services Tariff. It further shows that the NYISO’s analysis was based upon reasonable assumptions, and that the alternative assumptions proposed by HTP are not reasonable.

15.The following sections of this affidavit address the four major arguments included in

Section IV.A of the Complaint.

A.The NYISO Correctly Analyzed the HTP Project Concurrent with Class Year

2010 Examined Facilities

16. HTP argues that the NYISO violated its tariff by evaluating the HTP Project, a

member of the 2008 Class Year, as part of the 2010 Class Year. HTP claims that the
HTP Project should be evaluated without consideration of projects in future Class
Years and based on a “Go Forward Date” of December 2009 or January 2010.

17. The BSM Rules provide that projects are evaluated by Class Year. The BSM Rules

also contain a provision that explicitly governs the evaluation of projects in

completed Class Years at the time of the effective date of the BSM Rules and that had
not received buyer-side mitigation determinations under the Pre-Amendment Rules.
Services Tariff Section 23.4.5.7.3 defines “Type III” “Examined Facilities” as a
transitional “catch-all” category that includes projects “in a Class Year prior to

2009/10 that [have] not commenced commercial operation or been canceled and for which the ISO has not made an exemption or Unit Net CONE determination.” The HTP Project is a type III Examined Facility because it was in a Class Year prior to Class Year 2009, had not commenced commercial operation, and had not previously received an exemption or Offer Floor determination.

18. The HTP Project was therefore evaluated at the same time as other projects that had

met the definition of Examined Facilities and had not been evaluated under the PreAmendment Rules. The projects were in Class Years subsequent to the HTP
Project’s Class Year. As described in the Answer, the other projects that were
considered in the forecasts used for HTP were due to the application of the “Three Year Rule” to Examined Facilities other than the HTP Project, and the application of the “Reasonably Anticipated Entry Date Rule” to the HTP Project.3

19. The NYISO notified HTP of the facilities that would be considered in the HTP

Project analysis starting in November 2010. The NYISO identified the list of

Examined Facilities in spreadsheets containing the relevant forecast inputs that were
posted to its website. The first of these spreadsheets was posted on November 12,

3 See Answer at 10-14.

20104; subsequent updated versions were posted on June 8, 20115, and October 4,
20116.

20. The Complaint introduces the notion that determinations under the BSM Rules should

be made sequentially to argue that the HTP Project should be evaluated in total

isolation from Examined Facilities in Class Years 2009 and 2010. The paragraphs
above describe how the provisions in the BSM Rules, including the definition of
Examined Facilities, apply to the HTP Project. The Answer describes the
applications of the Commission order that required the NYISO to analyze the HTP
Project under the “Reasonably Anticipated Entry Date” rule. When those
requirements are applied, HTP has the same Mitigation Study Period start date as
Class Year 2010 projects.7

21. The Complaint also mischaracterizes the NYISO’s September 28, 2010 data request,

which informed HTP that it was “a potential new entrant for which a determination is
to be made in advance of the Initial Decision Period for Class Years 2009 and 2010.”
HTP twice claims that this statement somehow means that “the NYISO initially
intended to complete its evaluation of Hudson Transmission, a Class Year 2008
project, first, then address the Class year 2009 and 2010 projects afterwards.”8 The

4 See <http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/In-
City_ICAP.pdf>.

5 See <http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/In-
City_ICAP_Buyer-side_Mitigation_Test_Data.pdf>.

6 See <http://www.nyiso.com/public/webdocs/products/icap/incity_mitigation/In-
City_ICAP_Buyer-side_Mitigation_Test_Data_100411.pdf>.

7 See Answer at 10-14.

8 Complaint at 33, and at n. 69.

data request simply reflected Section 23.4.5.7.3.3 of the Services Tariff, which

requires that the preliminary determination is to be provided to Examined Facilities “prior to the commencement of the Initial Decision Period.” That same Services Tariff section also specifies the timing for subsequent determinations.9 The data request was not intended, and cannot reasonably be construed, to signal that the NYISO intended to evaluate the HTP Project in a manner different from what is required by the Services Tariff and the Commission’s orders.

22. In fact, the NYISO never changed its approach to evaluating the HTP Project.

Because the HTP Project was a pre-Class Year 2009 project that was not previously
examined, it was evaluated with Class Year 2009 Examined Facilities in the
calculation of the ICAP Spot Market Auction forecast and of net energy and ancillary
services revenues, and concurrent with Class Year 2010 Examined Facilities. The
NYISO had to request and collect data from HTP at the same time as it collected data
from other facilities being examined under the BSM Rules. On September 28, 2010,
the NYISO issued information request letters to the Examined Facilities in Class
Years 2009 and 2010 that were being examined under the BSM Rules. The Answer
describes that the NYISO’s filing of the BSM Rules with the Commission explained
the need for an earlier effective date for the data gathering provisions so it could
gather data from these facilities.10

9 The Complaint attaches the determinations made in accordance with the timing described in Services Tariff Section 23.4.5.7.3.3. See Complaint at Attachments 7 - 10.

10 See Answer at 13.

23.The MMU Report accepts the NYISO’s evaluation of the HTP Project as part of the

same Mitigation Study Period as the completed Class Year 2010. Beyond

acknowledging the NYISO’s tariff interpretation, the MMU Report states that the

NYISO’s approach is “appropriate” as a substantive matter “because the commitment to move forward with the project likely did not occur until 2011 and the project is not scheduled to be operational until 2013.”11

B. Scaling Factor

24. HTP takes issue with the NYISO’s use of a scaling factor when calculating the net

energy revenues for the HTP Project. HTP alleges that the application of the scaling
factor has no tariff basis, unduly discriminates against merchant transmission
facilities, and is inconsistent with market fundamentals, HTP’s business model, and
HTP’s agreements with the New York Power Authority. HTP argues that net energy
revenues should be calculated as the “positive price spread between PJM and NYISO
Zone J in the day-ahead market (net of transactions costs).”12 It claims that this is
required by the “plain meaning” of section 23.2.1 of the Services Tariff which defines
Unit Net CONE as the “localized levelized embedded costs of a specified Installed
Capacity Supplier, …net of likely projected annual Energy and Ancillary Services
revenues”13

11 MMU Report at 13.

12 Complaint at 46.

13 Id. at 44.

25.HTP’s assertion is premised on an inappropriate distinction between the NYISO’s

calculation of forecast day-ahead energy revenues and the scaling factor. The scaling factor is a component of the calculation of net energy revenues. The net energy
revenue methodology was developed with consideration of, and alongside, the scaling factor. Taken together, the two provide the HTP Project’s “likely projected” net
energy revenues. As explained below, it would be unreasonable to evaluate the HTP Project without making this adjustment.

26. HTP states that the use of a scaling factor is “unduly discriminatory against merchant

transmission facilities insofar as it: (1) assumes, without any basis, that a merchant

transmission line would not be able to capture roughly 50 percent of available energy
revenues; and (2) does not apply a comparable assumption to generator new
entrants.”14

27. In this section, I describe the basis for applying a scaling factor to the HTP Project,

how the scaling factor was applied to the HTP Project, and why it would not be reasonable to apply a scaling factor adjustment to generators.

i. The Basis for the Scaling Factor and its Application to the HTP Project

28.The NYISO’s Answer explains that the scaling factor has a firm tariff basis in the

requirement that the NYISO reasonably project the net energy revenues for Examined

Facilities.15

14 Id at 45.

15 2011 Boles Supplemental Affidavit in EL11-42 at P 12.

29.The net energy revenues for UDR projects that interconnect the NYISO with another

organized market (such as PJM) are calculated as the sum of the projected positive
net price spread between the source and sink locations, over the three years of the
Mitigation Study Period, multiplied by a scaling factor to account for the fact that
perfect arbitrage is impossible. In the case of the HTP Project, the positive net price
spread represents the difference between the PJM Bergen node and Zone J prices, less
a fee for non-firm transmission service and related charges, summed over all hours in
which the net difference is positive. This calculation reasonably assumes that HTP
would not import energy into New York at a loss when the price spread, less a fee, is
negative.

30. At the request of the NYISO, NERA Economic Consulting (“NERA”) performed this

calculation and modeled Zone J prices at varying excess levels. NERA performed the
net energy revenue estimates for the HTP Project by comparing historic day-ahead
prices at PJM Bergen over a three-year period to the Zone J day-ahead prices
produced by its econometric model, controlling for the level of excess in the forecast.

31. The NERA model assumed perfect arbitrage of day-ahead prices; in any hour in

which the day-ahead price spread, less an “expected export fee,” was positive, the
revenues accrued to the HTP project. The expected export fee is based on PJM’s
charges to exports for non-firm transmission service and ancillary services. The
NERA model did not account for the fact that in practice, price spreads cannot be
perfectly arbitraged. Accordingly, both NERA and the MMU recommended that an

adjustment be applied to discount the estimated net energy revenues by accounting for anticipated actual performance using confidential historic market data.

32. The scaling factor was developed to account for these realities. Without perfect

information, which is only available after the decision to import has been made, there will inevitably be times when the HTP Project either imports energy when it would have been more profitable not to do so or does not import energy when it would have been more profitable to do so.

33. The scaling factor was computed as the ratio of (a) historic net energy revenues from

the day-ahead and real-time markets to (b) theoretical net energy revenues from the
day-ahead market over the same historic period. The theoretical net energy revenues,
however, assume perfect arbitrage of PJM and NYISO day-ahead market energy
prices. The calculation of the scaling factor used hourly day-ahead and real-time
energy prices for New York and PJM, and data pertaining to energy schedules.

34. At the time of the NYISO’s analysis of the HTP Project in 2011, I discussed the

necessity for and the application of a scaling factor with the MMU. The MMU

concurred with the application of a scaling factor to estimate the HTP Project’s net energy revenues, and with the specific scaling factor utilized in that determination. The MMU Report concludes that: “If a Scaling Factor were not employed by NYISO, the net revenue estimate would assume perfect arbitrage between PJM and the
NYISO in the day-ahead market, which is not reasonable”16

16 MMU Report at 8.

35.At the time of the retest, the NYISO revised the pricing and scheduling inputs used to

calculate the scaling factor and adjusted net energy revenues at the 345 kV level. The revisions to the pricing and scheduling inputs were made to enhance the accuracy of the scaling factor calculation. Those revisions resulted in a lower scaling factor value than the 50 percent stated in the Complaint. The methodology used to establish the scaling factor was not changed. The 345 kV adjustment was made at the time of the retest consistent with the Commission’s EL11-50 September 10 Order.17 The MMU agreed that both revisions were appropriate.

36. The adjusted net energy revenues were calculated as the product of the scaling factor

and the projected net energy revenues from the NERA econometric model, which were adjusted downward for lower projected net energy revenues at the 345 kV voltage level. The adjusted net energy revenue value was used in the calculation of the HTP Project’s Unit Net CONE.

37. The Complaint, in several instances, greatly overstates the impact of the scaling factor

on the HTP Project’s annual net CONE calculation. For example, it states that the application of the scaling factor resulted in a corresponding increase to annual net CONE.18 However, the use of the initial or revised scaling factor result in
considerably less than a 50 percent increase to the annual net CONE, and far less than the “corresponding” increase that the Complaint suggests.

17 September Order at P 100.

18 See Complaint at 4, “The NYISO applied a ‘scaling factor’ to reduce the projected net energy revenues for the Hudson Transmission Project by approximately 50 percent, which had the effect of increasing Unit Net CONE (i.e. the NYISO’s estimate of Hudson Transmission annualized cost of new entry (“CONE”)) by a corresponding amount.” See also Complaint at 26, 46.

38.The scaling factor accounts for imperfect arbitrage and the value derived from real-

time scheduling. It does not, however, account for higher prices in PJM that would likely occur as a result of exporting 660 MW at the Bergen node.19 If this price convergence were taken into account, it would likely further decrease the estimated net energy revenues for the HTP Project.

ii. Claims Regarding Discriminatory Treatment

39. HTP argues that the scaling factor discriminates against merchant transmission

facilities because no comparable assumption has been applied to generators.

40. The justification for applying a scaling factor to UDR Projects connecting two

organized markets was described above. To reiterate, because energy prices cannot
be precisely forecasted, and because of the asynchronous timing of the NYISO and
PJM markets, perfect arbitrage profits cannot be obtained. Therefore, it is necessary
to apply a scaling factor to UDR Projects to avoid overestimating their net energy
revenues.

41. These uncertainties are largely non-existent for generators because they sell capacity

directly into the NYCA and do not rely on external energy transactions. A generator knows its marginal costs of operation, and it can make offers at that level with a high degree of certainty.

19 The NERA model accounts for lower Zone J prices that would occur as a result of importing 660 MW into Zone J because the NERA econometric model estimates prices as a function of the
forecasted excess level.

42.UDR projects, however, will normally not know their marginal costs because they

depend on the prices in the neighboring control area. A UDR project therefore must forecast clearing prices in both the NYISO Locality and the neighboring Control Area with which it interconnects. Thus, the price spread between the two areas must be considered but cannot be known with certainty. The scaling factor accounts for the inherent inaccuracies in these projections. Therefore, there is a substantial difference between the calculation of net energy revenues for UDR projects and generators that justifies applying different methodologies to them.

iii. Calculation of Net Energy Revenues for the HTP Project

43. The Pfeifenberger Affidavit estimates net energy revenues for the HTP Project based

on gas futures as of December 2009, which is when HTP accepted its project cost

allocation.20 The NYISO net energy revenue model for the HTP Project did not

utilize gas futures. It was based on the historical relationship between PJM and NYC
day-ahead market prices, adjusted for the modeled level of excess in NYC. The
NYISO utilized the NERA econometric model for this calculation, with the scaling
factor adjustment as described above. The model calculated net energy revenues as
the difference between the predicted hourly NYC LBMP and the historic hourly LMP
at the Bergen node, less a fee, then summed across all hours in which the difference
was positive. All inputs were based on historic data except for the forecasted reserve
margin levels, which were used to predict NYC LBMPs. Applying historic natural

20 See Complaint at Attachment 1 - Affidavit of Johannes P. Pfeifenberger at P 31 (“Pfeifenberger Affidavit”).

gas prices observed over the period used in the existing NERA model was a simplifying assumption that provides a reasonable estimate.

44. A second difference was that the model employed by Mr. Pfeifenberger used real-

time prices, whereas the NYISO model used day-ahead prices. Modeling of day-

ahead energy prices is more appropriate because there are typically more energy

imports in the day-ahead market than in the real-time market. Modeling of day-ahead energy prices is also consistent with the methodology utilized to establish the current ICAP Demand Curves.

45. The net energy revenue model and the resultant net energy revenue estimates that the

NYISO calculated were reasonable and in conformance with the Tariff. A detailed
explanation of the NYISO’s methodology is provided in the MMU Report.21 The
report states that the MMU “carefully reviewed the assumptions used by the NYISO

in estimating the net revenues for the HTP Project to determine whether they were
reasonable and consistent with the Services Tariff. Overall, we conclude that the
NYISO used assumptions that were both reasonable and tariff compliant.”22

46. Because of the different natural gas price and energy price inputs, it is difficult to

discern whether any valid comparison can be made between the results of the analysis
prepared by Mr. Pfeifenberger and that performed by the NYISO. The NYISO’s
methodology was developed in consultation with NERA and the MMU, and
reasonable assumptions were made in order to obtain an estimate of net energy
revenues.

21 MMU Report at pp. 7-12.

22 Id at p. 7.

C.Sunk Costs

47.HTP asserts that the NYISO’s treatment of the HTP Project was unduly

discriminatory because the NYISO did not exclude any sunk costs from its Unit Net
CONE calculation. HTP’s assertion is wrong. The NYISO excluded the non-
engineering, procurement and construction (“EPC”) costs components that developers
typically incur prior to committing to a project. These costs were equal to one-half of
permitting costs, one-half of legal costs, all environmental studies costs, and all
market studies costs.

48. The NYISO was advised by Sargent & Lundy which drew upon its extensive project

development experience. The methodology that Sargent & Lundy advised the

NYISO to use for the HTP Project was consistent with the advice it gave, and with
the approach the NYISO has taken in other analyses. Specifically, Sargent & Lundy
estimated the sunk portion of a project owner’s costs as the sum of the following:

(1) one-half of permitting costs, (2) one-half of legal costs, (3) environmental studies
costs, and (4) market studies costs. The NYISO has excluded these costs in all of its
exemption analyses under the BSM Rules, including the analysis for the HTP Project.

49. HTP puts forward two alternative estimates of HTP Project sunk costs that it claimed

the NYISO should have excluded: (i): $16.7 million based on a claimed December
2009 Go-Forward date; and (ii) $300 million based on a claimed December 2011 Go-

Forward date.23

23 Complaint at pp. 47-48, n. 126.

50.Neither of the HTP Project’s purported sunk costs would be excluded under the

methodology employed by the NYISO and recommended by Sargent & Lundy. In
the first instance, HTP states that it “had incurred $16.7 million by December 2009
when it received its final cost allocation.”24 The $16.7 million value was the System
Upgrade Facility amount assigned to the HTP Project. Therefore, it is an appropriate
cost to include as a project cost. The basis for HTP’s asserted $300 million sunk cost
and its proposed exclusion of them from the investment cost is not clear. Therefore,
they should not be excluded as sunk costs in the calculation of the Unit Net CONE for
the HTP Project.

51. Using the methodology recommended by Sargent & Lundy, the NYISO calculated

the amount of sunk costs and excluded this value from the calculation of the CONE of the HTP Project used in the December 2011 Determination. The MMU supported the exclusion of these specific sunk costs and found that the NYISO’s assumption
was reasonable.25

D. Use of PJM Base Residual Auction Clearing Prices

52. HTP takes issue with the NYISO’s use of the PJM Base Residual Auction (“BRA”)

clearing prices to estimate of the cost of capacity in PJM. HTP argues that the timing
of the three-year forward BRA is mismatched with the NYISO’s shorter-term
auctions and that “the use of prices from such mismatched time periods introduces a
significant bias” into the analysis under the BSM Rules. HTP contends that“[t]he

24 Complaint at n. 74.

25 MMU Report at 6.

three-year forward prices in PJM’s BRA are thus not representative of the prices for
PJM capacity that would be available to offer into the NYISO’s ICAP auctions.”26

53. HTP’s argument is wholly based on the fact that the incremental auctions are

conducted relatively close in time to the delivery months. It is true that the PJM

incremental auctions resemble the NYISO auctions in this single respect. However, there are much more meaningful similarities between the PJM BRA and the NYISO ICAP Spot Market Auction that HTP does not acknowledge.

54. The purpose of the BRA is to procure the resources needed to satisfy the region’s

capacity obligations. PJM’s rules provide for incremental auctions to be conducted after the BRA to procure additional resources needed to satisfy potential changes in market dynamics.27 The price in the BRA is determined based on an

administratively-determined demand curve, the Variable Resource Requirement

(“VRR”) curve. This is analogous to the NYISO ICAP Demand Curve that sets the price in the ICAP Spot Market Auctions, which are forecasted in the exemption analysis under the BSM Rules. Prices in the BRA and NYISO’s ICAP Spot Market Auction are based on a transparent net CONE value, the planning requirement, and the level of supply. Therefore, they both represent liquid markets that should
accurately reflect the supply and demand conditions in each market.

55. By contrast, the incremental auctions are thinly traded, and prices in them are set by

the intersection of a relatively limited number of participant bids and offers. Because they are thinly traded, uncertainties regarding supply or demand can cause the

26 Complaint at 48.

27 PJM Manual 18: PJM Capacity Market, Revision: 16 (September 27, 2012) available at
<http://www.pjm.com/~/media/documents/manuals/m18.ashx>.

incremental auctions to clear at prices that are substantial above or below the clearing prices in the BRA. Hence, persistent differences between the BRA and the
incremental auctions in one direction would not be expected.

56. In criticizing the use of the BRA price and proposing to use the incremental auction

prices, HTP implicitly makes unfounded assumptions: first, that there would be capacity remaining in the PJM market that was available to offer into the NYISO auctions at the time of the incremental auctions, and second, that this capacity could be contracted for at a significant discount to the BRA price. Neither of these
assumptions is reasonable, as I next explain.

57. The majority of capacity in PJM is transacted in the BRA, and relatively little is

transacted in the incremental auctions. Even if some capacity is available, it cannot
be reliably procured in the incremental auctions in the quantities necessary to utilize a
substantial portion of the HTP Project’s 660 MW of capacity. Thus, the apparent
price in the incremental auction is not meaningful for estimating the cost of exporting
660 MW from the PS-NORTH Locational Delivery Area to NYC. The majority of
PJM capacity transacts in the BRA. The high proportion of transactions is expected
to continue because there are restrictions in PJM’s rules that make it difficult to sell
outside of the BRA. If an existing resource wishes not to sell in the BRA, it must
show that it has a financially and physically firm commitment to export or
demonstrate that its avoidable cost rate (“ACR”) is above the BRA clearing price.28
PJM capacity would not be expected to enter in a financial or physical firm

28 PJM Open Access Transmission Tariff at Attachment DD § 6.6, “Offer Requirements for Capacity Resources” (effective date October 24, 2012), available at,

<http://www.pjm.com/documents/~/media/documents/agreements/tariff.ashx>.

commitment at prices below the expected BRA clearing price. Similarly, any unit
that demonstrates an ACR above the BRA could not be expected to sell capacity at
prices below the BRA. In either case, the BRA price serves as a floor and the

NYISO’s use of BRA prices in the analysis of the HTP Project is reasonable.

58. Finally, the NYISO’s use of the BRA is, if anything, conservative because it does not

account for the increased prices in PJM that would likely result from the export of capacity from HTP. Historically, the sloped portion of the BRA VRR curve for the PS-NORTH LDA has spanned 400 MW to 500 MW.29 Given the steep slope of the curve, a large export would be expected to increase prices. Thus, far from
encouraging “false positives” through the use of “overstated” prices30 the use of the BRA price is reasonably conservative.

59. HTP proposes two possible alternatives to the NYISO’s use of BRA prices. First, it

proposes that forward BRA prices be discounted to reflect the historical relationship
between BRA and incremental auction prices. Second it suggests using the
“appropriate” prices in the incremental auctions as of the “appropriate go forward
date.”

60. The first proposal is unreasonable given the explanations above. There is no certainty

that capacity can be procured in the incremental auctions. The historic price spread
may not be representative of the future price spread, if any. Also, any resources that

29 See, for example, the PJM Variable Resource Requirement (VRR) curves for the 2013-2014,
2014-2015, and 2015-2016 delivery years. The horizontal distance of the sloped portion of the VRR
curves spans 440.3 UCAP MW, 430.9 UCAP MW, and 448.0 UCAP MW, for those delivery years,
respectively. PJM RPM Auction User Information, “Planning Period Parameters.xls,” (available online
for each delivery year), available at <http://www.pjm.com/markets-and-operations/rpm/rpm-auction-
user-info.aspx>.

30 Complaint at p. 49; Pfeifenberger Affidavit at P 36-44.

would export would require at least the BRA price, which supports the NYISO use of BRA prices in its analysis.

61. In addition to its substantive problems, it is not clear how the second proposal could

be applied. The HTP Project’s Mitigation Study Period spans May 2013 through

April 2016. At the time of the final BSM determination in December 2011, only one
incremental auction had been held for that timeframe, the first Incremental Auction
for the 2013/14 delivery year. Thus, if HTP’s alternative approach had been in place
the NYISO would not have had data necessary to develop meaningful estimates of
future prices.

62. The Pfeifenberger Affidavit asserts that the BRA is not a reasonable reference point

for the NYISO’s auctions, and that it likely significantly overstates the near-term

prices for PJM capacity. Mr. Pfeifenberger proposes that the NYISO should use the prices from PJM’s third incremental auctions as a proxy for the PJM capacity price. Mr. Pfeifenberger references the Incremental Auctions for PS-NORTH that have historically cleared lower than the Base Residual Auctions. Mr. Pfeifenberger
proposes a modification to the NYISO’s methodology to reduce the three-year BRA forward price by approximately $40/kW-year for the historical discount of the third incremental auctions relative to the BRA.31

63. For the reasons described above, the BRA price is the most reasonable estimate of the

price of capacity in PJM over the Mitigation Study Period for the HTP Project.

HTP’s proposal to discount the future BRA prices by the historic Incremental Auction discount should be rejected.

31 Pfeifenberger Affidavit at P 44.

64.Lastly, Mr. Pfeifenberger takes issue with the NYISO’s use of the 2014/15 BRA price

for the 2014/15 and 2015/16 delivery years.32 Mr. Pfeifenberger describes the recent auction results for the 2015/16 BRA, in which the price was lower than the 2014/15
price, as evidence that the NYISO has overestimated market clearing prices. The
NYISO chose to use the BRA prices because they are the most robust price estimates, for the reasons described above. At the time of the analysis, the 2014/15 BRA was
the most recently-conducted auction, so the 2014/15 BRA price was used as the best estimate of the 2015/16 price.

65. The MMU supports the NYISO’s use of the BRA as the cost of acquiring capacity in

PJM throughout the HTP Project analysis. The MMU Report states, “[w]e carefully reviewed the assumptions and calculations used by the NYISO to determine the cost of exporting capacity from PJM. Overall, we find that the NYISO’s assumptions were
reasonable and compliant with the MST. Accordingly, we support the overall results of the NYISO’s determination.”33

This concludes my affidavit.

32 Id. at P 43.

33 MMU Report at p. 13.

UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Independent System Operator, Inc.Docket Nos. EL11-42-000

SUPPLEMENTAL AFFIDAVIT OF JOSHUA A BOLES

Mr. Joshua A. Boles declares:

1.I have personal knowledge of the facts and opinions herein and if called to testify

could and would testify competently hereto.1

I.Purpose of this Affidavit:

2.I submit this affidavit in support of the NYISO’s Answer to the Comments submitted

by Hudson Transmission Partners (the “HTP Comments”) in response to the

Complaint filed by Astoria Generating Company, L.P., the NRG Companies, and TC Ravenswood, LLC (collectively, the “Complainants”).

3. I provided an Initial Affidavit in this proceeding. In the Initial Affidavit, I refuted the

claims made by the Complainants that the NYISO’s implementation of the “In-City Buyer-Side Mitigation Measures,”2 has been flawed or will be flawed in the future. I demonstrated that the NYISO’s implementation adheres to all aspects of Attachment H and Attachment O to the Services Tariff and Commission Orders.

My professional and educational qualifications were summarized in PP 4-8 of my Initial

Affidavit in this proceeding which I incorporate here by reference.

As the NYISO does in the Answer, I use the term “In-City Buyer-Side Mitigation Measures” to

refer to the currently-effective buyer-side capacity market mitigation provisions in Attachment H to its

Market Administration and Control Area Services Tariff (“Services Tariff”), including those that were

accepted by the Commission in its series of orders in Docket ER10-3043.

4.The purpose of this Supplemental Affidavit is to confirm that the NYISO does

account for differences between generators and Unforced Capacity Deliverability
Right3 (“UDR”) projects when conducting Unit Net CONE calculations. My
Supplemental Affidavit also demonstrates that the methodology the NYISO uses to
determine Unit Net CONE for UDR projects is consistent with Attachment H and
Commission Orders.

II.Unit Net CONE Methodology for a UDR Project

5.The HTP Comments use the more general phrase “merchant transmission facility” to

describe the HTP project when expressing concerns regarding the NYISO’s analysis of a
merchant transmission facility. I will use the phrase UDR projects in my affidavit because
that is the term used in the In-City Buyer-Side Mitigation Measures which specify the

projects the NYISO is to examine.4 My Affidavit will only address UDR projects, such as the HTP project, that connect a neighboring Control Area to New York City.

6. Attachment H to the Services Tariff defines Unit Net CONE for purposes of the In-City

Buyer-Side Mitigation Measures as the “localized levelized embedded costs of a specified
Installed Capacity Supplier, including interconnection costs, and for an Installed Capacity
Supplier located outside the New York City Locality including embedded costs of
transmission service, in either case net of likely projected annual Energy and Ancillary
Services revenues, as determined by the ISO, translated into a seasonally adjusted monthly

3 Capitalized terms that are not otherwise defined herein shall have the meanings specified in the Services Tariff.

4 See, for example, Services Tariff Attachment H § 23.4.5.7.3.

UCAP value using an appropriate class outage rate.”5 The NYISO applies this definition in determining the Unit Net CONE for UDR projects.

7. The methodology the NYISO uses to determine Unit Net CONE for a UDR project has been

reviewed and commented on by the Independent Market Monitoring Unit (“MMU”) for the
NYISO, Potomac Economics, Ltd. The MMU has not identified any compliance concerns
with respect to the NYISO’s implementation of the In-City Buyer Side Mitigation Measures.

8. The NYISO’s approach to Unit Net CONE calculations for a UDR project is similar to its

approach for a new generation project in a number of ways. Both classifications of projects
are evaluated based on their reasonably anticipated costs minus their reasonably anticipated
revenues to determine if they are exempt or subject to an Offer Floor. For a UDR project

that connects to a neighboring Control Area, the costs and revenues associated with a UDR
project will be different from a new generator located within the New York Control Area.

9. The NYISO’s methodology includes looking at the levelized embedded costs of the

transmission facility, including the required upgrades necessary to make the facility
deliverable in New York City, and the costs of upgrades in the neighboring Control
Area that are required to export firm energy. The project is evaluated for the amount
of MW for which CRIS rights have been awarded at the NYCA interconnection point.

10. Costs, if any, for the project to be deliverable to the NYCA interface are a component

of Unit Net CONE because establishing deliverability is a prerequisite to obtaining
UDRs. The Services Tariff provides that “[t]o the extent the NYCA interface is with
an External Control Area the Unforced Capacity associated with UDRs must be

5 See Attachment H§23.2.1 at definition of Unit Net CONE.

deliverable to the Interconnection Point."6 In addition, a project must be deliverable

to qualify as an In-City capacity resource: “[t]o be counted towards the locational

component of the LSE Unforced Capacity Obligation, Unforced Capacity owned by
the holder of UDRs or contractually combined with UDRs must be deliverable to the
NYCA interface with the UDR transmission facility pursuant to NYISO requirements
and consistent with the election of the holder of the rights to the UDRs set forth in
this Section."7

11. In addition to the costs of the transmission facility itself, the NYISO’s analysis of a

UDR project connecting to a neighboring Control Area takes into account the cost of the capacity in the neighboring Control Area. This analysis is required because the In-City Buyer-Side Mitigation Measures are utilized to make determinations for InCity capacity resources. Without procuring capacity, a transmission line is not
capable of receiving ICAP revenues in the NYC capacity market. The NYISO would use a reasonable estimate of the cost of capacity in the neighboring Control Area
based on that Control Area’s capacity market clearing prices for the respective
location from which the capacity could be withdrawn.

12. To determine Unit Net CONE, the NYISO subtracts from the costs identified above,

the reasonably anticipated energy and ancillary services revenues. The model used to
determine energy revenues for a UDR project takes into account the price spread
between the respective locations in the Control Areas from which the power is

6 See Services Tariff§2.21 at definition of Unforced Capacity Deliverability Rights.

7 SeeServices Tariff §5.11.4.

exported and the location to which it is imported. In order to determine the price
spread that would induce arbitrage, the NYISO also considers the associated fees a
market participant pays to export energy from the neighboring Control Area. This fee
is used as the “hurdle rate” for when the model assumes a transaction will be
scheduled to flow and when it will not. In the hours in which the energy spread
exceeds the hurdle rate, this rate is subtracted from the spread to calculate the net
energy revenues. Because arbitraging prices between Control Areas does not occur
optimally in 100 percent of the hours when there is a price spread greater than the
transaction costs, the energy revenues must also be discounted to capture the
percentage of time that arbitrage can reasonably be expected to occur.

13. As stated in my Initial Affidavit, the NYISO contracted with NERA Economic

Consulting (“NERA”) to perform the energy revenue estimates for all Unit Net

CONE determinations. NERA uses its econometric model to estimate NYISO energy
prices at the expected excess capacity level used in the In-City Buyer-Side Mitigation
Measures. For a UDR project, instead of comparing those prices to the variable
operating costs of the unit, the NERA model compares them to the hourly energy
prices in the neighboring Control Area. NERA uses the econometric model to adjust
historic NYISO hourly prices for the applicable excess capacity level and then
compares the adjusted NYISO prices to those in the neighboring Control Area.

14. NERA has authorized the NYISO to state that they believe the analysis described in

this Supplemental Affidavit for UDR project net revenues provides reasonable net revenue estimates.

15.The NYISO’s analysis takes into account the other costs and revenues that the UDR

project would be reasonably anticipated to incur or receive under the neighboring Control Area’s tariff. For example, for a UDR project that connected PJM to New York City, the NYISO would consider whether Auction Revenue Rights (“ARRs”) are available to a project.

Conclusion

16. This Affidavit demonstrates that the NYISO’s methodology to implement the In-City

Buyer-Side Mitigation Measures for UDR projects that connect to the NYCA from a neighboring Control Area is consistent with all aspects of Attachment H to the
Services Tariff.

This concludes my affidavit.