UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Independent System Operator, Inc.)Docket No. ER11-4338-000

REQUEST FOR REHEARING AND ALTERNATIVE REQUESTS FOR EXPEDITED CLARIFICATION AND COMPLIANCE WAIVER OF THE
NEW YORK INDEPENDENT SYSTEM OPERATOR, INC.

In accordance with Rule 713 of the Commission’s Rules of Practice and Procedure,1 the
New York Independent System Operator, Inc. (“NYISO”) respectfully seeks rehearing of the
Commission’s cost allocation determination in its May 16, 2013 Order on Compliance Filing in
the above captioned proceeding (“May 16 Order”).2 In the alternative, the NYISO respectfully
requests expedited clarification of the cost allocation determination. To the extent that the
Commission denies rehearing, the NYISO also respectfully requests a temporary waiver of its
obligation to comply with section 35.28(v)(B) of the Commission’s regulations.
The May 16 Order conditionally accepted the NYISO’s proposed “Net Benefits Test,” which the NYISO developed in response to Order No. 745.3 Under its Net Benefits Test, the NYISO will use a supply curve to identify the point at which the benefits to Load in New York of dispatching Demand Side Resources exceed the costs. The supply curve is composed of Suppliers serving Load in New York,4 including Suppliers serving Load to satisfy bilateral

18 C.F.R. § 385.713 (2012).

2 See New York Independent System Operator, Inc., Order on Compliance Filing, 143 FERC ¶ 61,134 (2013) (“May

16 Order”).

3 Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 134 FERC ¶ 61,187 (March 15, 2011) (“Order No. 745”); reh’g denied, Order No. 745-A, 137 FERC ¶ 61,215 (Dec. 15, 2011) (“Order No. 745-A); reh’g denied, Order No. 745-B, 138 FERC ¶ 61,148 (2012).

4 The specific Suppliers to be included in the supply curve are described in the NYISO’s Order 745 compliance
filing. See New York Independent System Operator, Inc., Docket No. RM10-17-000 Demand Response
Compensation in Organized Wholesale Energy Markets, Docket No. ER11-4338-000 at p 4 (August 19, 2011).

contracts.5 The May 16 Order found, however, that the NYISO had not demonstrated that its

existing cost allocation methodology6 - under which it allocates the costs of dispatched Demand Side Resources to all Load on a load ratio share basis as adjusted for historic congestion -
satisfied the requirements of Order No. 745.

In response to a protest by Occidental Chemical Corporation7 (“OxyChem”), the

Commission found that certain entities that purchase power from the New York Power Authority
(“NYPA”) under its Replacement and Expansion Power program (“NYPA Program Customers”)
do not purchase energy in the NYISO Energy market.8 The Commission held that the NYISO
had not satisfied Order No. 745’s requirement that it demonstrate how its cost allocation
methodology “appropriately allocates costs to entities in NYISO’s energy markets that benefit
from the lower prices produced by dispatching demand response.”9 The Commission, therefore,
directed the “NYISO to revise its methodology to allocate the costs associated with demand
response compensation to only those entities that purchase from the relevant NYISO energy
markets in the area(s) where the demand response reduces the [Locational Based Marginal Prices
(“LBMP”)] at the time when the demand resource is committed or dispatched.”10
As described in Sections III and IV below, the Commission holding regarding the
NYISO’s cost allocation methodology proposed in its August 19, 2011, compliance filing
(“August 2011 Filing”): (i) is an overly and unnecessarily narrow interpretation of the Order No.

5 Capitalized terms not otherwise defined herein shall have the meaning specified in the NYISO’s Market
Administration and Control Area Services Tariff (“Services Tariff”) or its Open Access Transmission Tariff
(“OATT”).

6 The relevant cost allocation rules are set forth in the Attachment R to the NYISO OATT. The NYISO proposed
certain enhancements to these rules, which have been in place since 2001, in its Order No. 745 compliance filing.

7 The New York Association of Public Power (“NYAPP”) also argued that the NYISO’s proposed compliance cost allocation methodology would allocate costs to customers with fixed price bilateral power contracts. See New York Independent System Operator, Inc., Protest of the New York Association of Public Power, Docket No. ER11-4338-
000 (September 9, 2011) (“NYAPP Protest”). The May 16 Order referenced NYAPP’s argument but its ruling gave no indication that it was relying upon it.

8 May 16 Order at P 92.

9 Id.

10 Id.

745 cost allocation requirements, (ii) would lead to cost allocation rules that are fundamentally
incompatible with the NYISO’s Net Benefits Test, likely resulting in the inefficient dispatch of
Demand Side Resources and the inequitable allocation of related costs, (iii) ignores the benefits
that Load being served under bilateral contracts derive from the reduction in LBMP in the
NYISO’s Energy market when Demand Side Resources are dispatched, (iv) is inconsistent with
the basic structure of the NYISO’s cost allocation system, and (v) is inconsistent with the
Commission’s findings regarding the cost allocation methodology of other Independent System
Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”).
The NYISO, therefore, requests that the Commission grant rehearing of the May 16
Order and accept the NYISO’s cost allocation methodology as proposed in its August 2011
Filing.11 In the alternative, the NYISO requests expedited clarification to eliminate uncertainty
regarding the intent of the May 16 Order’s holding on the cost allocation methodology that is
relevant to the development of its compliance filing.12 If the Commission does not grant
rehearing, the NYISO also requests a temporary waiver that would excuse it from complying
with the cost allocation requirements in 18 C.F.R. §35.28(v)(B).13 Such a waiver should
continue until the NYISO has completed a re-evaluation of, and made any necessary revisions to,
its Net Benefits Test to restore the consistency between it and the demand response related cost
allocation rules.

This filing is supported by: (i) the Joint Affidavit of Scott M. Harvey and William W.
Hogan (“Attachment I”), which discusses three cost allocation principles that the Commission
should consider in its review of this filing; and (ii) the Confirming Affidavit of Robert Pike and

11 See Sections III and IV, below.

12 See Section V, below.

13 See Section VI, below.

Robert E. Fernandez, General Counsel
Raymond Stalter, Director of Regulatory Affairs * David Allen, Attorney

New York Independent System Operator, Inc.

10 Krey Boulevard

Rensselaer, NY 12144
Tel: (518) 356-6000
Fax: (518) 356-4702
rfernandez@nyiso.com
rstalter@nyiso.com

dallen@nyiso.com

* -- Persons designated for service.

II.BACKGROUND

*Ted J. Murphy

Hunton & Williams LLP
2200 Pennsylvania Avenue, NW Washington, D.C. 20037
Tel: (202) 955-1500

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

Kevin W. Jones

*Michael J. Messonnier, Jr.14 Hunton & Williams LLP

951 East Byrd Street
Richmond, VA 23219
Tel: (804) 788-8200
Fax: (804) 344-7999
kjones@hunton.com

mmessonnier@hunton.com

A. Demand Response in the NYISO Markets

The NYISO introduced a Day-Ahead Demand Response Program (“DADRP”) in New
York in 2001.15 Under this program, a Demand Side Resource or a group of Demand Side
Resources registered as a single DADRP resource may offer its load curtailment capability into
the NYISO’s Day-Ahead Market for Energy. If its offer is selected, the resource is paid the
LBMP for Energy at which the Day-Ahead Market settles for the relevant hour and location.
The costs of the dispatched Demand Side Resources are then allocated to all Loads on the basis

14 The NYISO respectfully requests waiver of 18 C.F.R. § 385.203(b)(3) (2011) to permit service on counsel for the NYISO in both Washington, D.C. and Richmond, VA.

15 See New York Independent System Operator, Inc., Order on Tariff Filing, 95 FERC ¶ 61,223 (May 16, 2001).

of their real-time load ratio shares and in proportion to the probability, given known transmission patterns, that a particular demand reduction will benefit a given Load by reducing Energy costs in its Load Zone or composite Load Zone.16 That is, the NYISO allocates DADRP costs to
beneficiaries in a manner that is consistent with the expected benefits from the dispatch of a
particular Demand Side Resource.

The NYISO has applied this cost allocation methodology since 2001, and all Load has
been responsible for such costs for over a decade, regardless of whether it was taking service
from a Supplier directly through the NYISO-administered markets or under a bilateral contract. The NYISO similarly recovers from all Load its annual budget, Ancillary Services, and uplift
charges on the basis of load ratio shares. The NYISO bills the portions of these charges
allocated to Load to Load Serving Entities, who recover the costs from retail customers, such as the NYPA Program Customers.

B. Order Nos. 745 and 745-A

On March 15, 2011, the Commission issued Order No. 745 to address compensation for demand response resources participating in wholesale energy markets administered by
ISOs/RTOs.17 Specifically, the Commission required that each ISO/RTO pay a demand response resource the locational marginal price (“LMP”)18 for energy when: (i) the resource has the
capability to balance supply and demand as an alternative to a generation resource and (ii)
dispatch of the resource is cost-effective as determined by a net benefits test.19

16 Congestion can limit how far the cost savings associated with dispatching demand response travels on the system. The NYISO allocates costs to Loads using historic congestion factors that capture how these benefits are expected to flow when a specific demand response resource is dispatched.

17 Order No. 745 at P 1.

18 For purposes of this proceeding, LBMP and LMP are comparable and are referred to interchangeably.

19 May 16 Order at P 2.

Order No. 745 required that each ISO/RTO include a net benefits test in its tariffs “to
determine whether a demand response resource is a cost-effective alternative to generation for
balancing supplying and demand in any given hour.”20 Specifically, the net benefits test should
determine “the point along the supply stack for each month at or beyond which the benefit to
load from the reduced LMP resulting from dispatching demand response resources exceeds the
increased cost to load” related to the decrease in billing units due to the dispatch of the demand
response resource.21

Order No. 745 also promulgated section 35.28(v)(B) of the Commission’s regulations.
This new provision required each ISO/RTO to “allocate the costs associated with demand
response compensation proportionally to all entities that purchase from the relevant energy
market in the area(s) where the demand response reduces the market price for energy at the time
when the demand response resource is committed or dispatched.”22 Each ISO/RTO could either
demonstrate that its “current cost allocation methodology appropriately allocates costs to those
that benefit from the demand reduction” or propose “revised tariff provisions that conform to this
requirement.”23 The Commission indicated in its Order 745-A that each ISO/RTO would have
the flexibility to design its cost allocation methodology consistent with the unique characteristics
of its region. In response to a request for clarification regarding the use of the term “area(s)” in
its cost allocation requirement, the Commission stated that: “The cost allocation methodology
required by the Final Rule was designed to allow sufficient flexibility for each individual RTO
and ISO to determine, in consultation with their stakeholders, an appropriate cost allocation
methodology that complies with the Final Rule. In this way, the Commission is allowing for

20 Id. at P 15.

21 Id. at P 16.

22 Order No. 745 at P 102.

23 Id. at P 102.

regional variation in the determination of the “area(s)” in which market participants benefit from demand response participation based on the unique energy market design in each RTO and ISO. The Commission will analyze and evaluate each RTO’s and ISO’s proposed cost allocation
methodology on a case-by-case basis in its compliance filing.” 24

C. NYISO August 2011 Filing

The NYISO has been paying Demand Side Resources the LBMP for Energy in the Day-
Ahead Market, as required by the Commission in Order No. 745, since the DADRP was
implemented in 2001. The NYISO has had in place for this period much of the related
framework in Order No. 745 required to support such compensation, including measurement and
verification requirements and a methodology for allocating costs to Load relative to the amount
they benefit.

The most significant component of the Commission’s requirements not already addressed
in the NYISO’s existing DADRP is the monthly net benefits test. The NYISO’s proposed Net
Benefits Test is composed of a nine-step methodology to identify the threshold price on a supply
curve at which point the benefits to Load of dispatching a demand response resource exceeds the
costs to the Load. That is, the Net Benefits Test identifies at which point a demand response
resource becomes a cost-effective alternative to generation to balance the supply and demand for
the relevant hour. Consistent with its existing methodology to allocate DADRP costs to all
Load, the NYISO’s supply curve in its Net Benefits Test considers the Suppliers required to
serve all Load in New York, including Suppliers that serve Load to satisfy bilateral contracts.
For purposes of its Net Benefits Test, the NYISO does not differentiate between
Suppliers that serve Load taking service directly through the NYISO’s Energy market and those
taking service through a bilateral contract. Suppliers in New York offer into the NYISO Day-

24 Order No. 745-A at P 115.

Ahead Market to serve the whole market and are not tied within the market solutions to a

specific Load. The NYISO Day-Ahead Market economically schedules all Suppliers to meet all
Load, at least cost, which includes Loads with bilateral contracts. Notwithstanding the existence
of a bilateral contract between a Supplier and Load, the Supplier may be making purchases in the
NYISO’s Energy market or obtaining service from another Supplier to satisfy its obligation to
provide service under a bilateral contract when it is economically efficient to do so. That is,
even if the NYISO was aware of all the terms of bilateral contracts, it would still be unable to
identify which portion of any Suppliers’ schedules were satisfying LBMP Load or Load served
by a bilateral contract.

The August 2011 Filing explained that the DADRP already satisfied most of Order No.
745’s requirements and proposed limited revisions to the NYISO’s tariffs to address additional
requirements. In its filing, the NYISO proposed, among other things, that the Commission
accept its proposed Net Benefits Test. In addition, the NYISO proposed to retain its existing cost
allocation methodology in Attachment R of the NYISO OATT with certain enhancements to
better allocate costs to the Loads that are benefitting from the dispatch of Demand Side
Resources.

D. OxyChem’s and NYAPP’s Protests

In response to the August 2011 Filing, OxyChem filed a protest with the Commission

arguing that the NYISO failed to demonstrate that its cost allocation methodology appropriately
allocated costs to those that benefitted from demand reductions.25 OxyChem is a manufacturer
that obtains most of its power under a bilateral contract as a NYPA Program Customer.
OxyChem indicated that NYPA Program Customers do not purchase Energy in the NYISO

25 New York Independent System Operator Inc., Motion to Intervene and Protest of Occidental Chemical Corporation, Docket No. ER11-4338-000 (Sep. 9, 2011) (“OxyChem Protest”).

Energy market and would not benefit from a lower LBMP due to the dispatch in the NYISO’s
Energy market of Demand Side Resources. For this reason, OxyChem argued that NYPA
Program Customers should not be allocated demand response related costs.26 Similarly, NYAPP
argued that the NYISO’s cost allocation methodology would allocate costs to customers with
fixed price bilateral power contracts.27 NYAPP stated that such customers would not benefit
from the reduced market price for Energy resulting from the dispatch of Demand Side
Resources.28

The NYISO filed an answer on September 26, 2011 (“September 2011 Answer”), which explained how its cost allocation methodology reasonably apportioned the costs of demand
response.29 The September 2011 Answer emphasized, among other things, that “bilateral
contracts are a part of the larger New York market, even if the contract price is not directly
derived from NYISO market-clearing prices” and noted that the customers could “benefit from the trends in the New York electricity markets over time, whether or not those benefits accrue immediately under the terms of those contracts.”30

E. The May 16 Order

The May 16 Order accepted in part and rejected in part the NYISO’s proposed

compliance revisions. The Commission generally found the NYISO’s proposed Net Benefits
Test to be consistent with the requirements in Order No. 745.31 As noted above, however, the
Commission did not accept the NYISO’s proposal to continue, with minor enhancements, its
existing cost allocation methodology. The Commission agreed with OxyChem that “purchasers

26 Id. at p 1.

27 NYAPP Protest at p 3.

28 Id. at p 4.

29 New York Independent System Operator, Inc., Motion for Leave to Answer and Answer of the New York

Independent System Operator, Inc., Docket No. ER11-4338-000 (September 26, 2011) (“September 2011 Answer”).

30 September 2011 Answer at p 10.

31 May 16 Order at P 37.

of NYPA Replacement Power and Expansion Power Program do not purchase energy in the
relevant NYISO energy market.”32 The Commission found that the NYISO had failed to
demonstrate how its cost allocation methodology “appropriately allocates costs to entities
purchasing in NYISO’s energy market that benefit from the lower prices produced by
dispatching demand response” and directed the NYISO to revise its methodology.33

F. Inconsistencies Between the NYISO’s Net Benefit Test and Cost Allocation
Methodology

The May 16 Order’s determination regarding the NYISO’s cost allocation methodology can be read as introducing fundamental inconsistencies between a potentially revised
methodology in line with the Commission’s directive in the May 16 Order and the NYISO’s Net Benefits Test methodology. The design of the Net Benefits Test is inextricably linked to that of the NYISO’s existing cost allocation methodology. The Net Benefits Test is based on the
premise that has been true for the NYISO’s cost allocation methodology since 2001, and
accepted by the Commission, that all Loads in New York benefit from the dispatch of Demand Side Resources in the NYISO’s Energy Market.

Modifying one methodology, either by excluding certain Load from cost allocation or by
not considering the Suppliers serving such Load in the Net Benefits Test, without making
corresponding adjustments to the other is very likely to result in inefficient and inequitable
outcomes. If there are Loads that cannot benefit by the reduction of LBMP for Energy in the
NYISO’s Day-Ahead Market due to the dispatch of a Demand Side Resource, then the supply
curve used in the Net Benefits Tests should exclude the Suppliers that are serving this Load.
Without this modification, the Net Benefits Test results may be distorted and the resulting
threshold price may result in the unnecessary dispatch of Demand Side Resources that are not

32 Id. at P 92.

33 Id.

cost effective or fail to dispatch Demand Side Resources when they are cost effective. The

remaining Load would then be required to pay for any resulting costs, regardless of whether they would receive any tangible benefit from them. In Load Zone A, alone, NYPA Program
Customers eligible for Replacement Power or Expansion Power constitute over 600 MW of
Load. Thus, mandating a difference between how the Net Benefits Test and cost allocation
methodology include Load (or the Suppliers serving Load) into their methodology could result in the inefficient dispatch of Demand Side Resources and the creation of unnecessary costs for a
subset of Loads.34 In addition, if the May 16 Order were to be interpreted as establishing that no Load served under a bilateral contract benefits from the dispatch of Demand Side Resources, the discrepancy between the Net Benefits Test and cost allocation methodology would create even
more inefficient cost-shifting, given that approximately half of the Energy transactions in New
York are undertaken through bilateral contracts.

III.REQUEST FOR REHEARING

The May 16 Order’s cost allocation ruling must be reversed on rehearing because it is arbitrary and capricious and does not reflect “a reasoned decision made based upon substantial evidence in the record.”35

A. The May 16 Order’s Application of an Overly and Unnecessarily Narrow

Interpretation of Order No. 745’s Cost Allocation Requirements to the NYISO Does Not Constitute Reasoned Decision-Making

The May 16 Order adopted an overly and unnecessarily narrow interpretation of section

35.28(v)(B) of the Commission’s regulations when it found that the cost allocation methodology proposed in the August 2011 Filing did not meet Order No. 745’s requirements. The

34 The size of the impact of the inefficient dispatch is difficult to determine because, as explained elsewhere, it is not possible for the NYISO, given the information it currently has, to identify and separate which specific generation bids are serving NYPA Program Customers.

35 Williston Basin Interstate Pipeline Co. v. Fed. Energy Regulatory Comm’n, 358 F.3d 45, 48 (D.C. Cir. 2004) (“Williston”) (citing N. States Power Co. v. FERC, 30 F.3d 177, 180 (D.C. Cir. 1994)).

Commission has apparently read section 35.28(v)(B) to prohibit the allocation of demand

response compensation costs to any Load being served under a bilateral contract and that, thus, does not explicitly “purchase energy” form a NYISO-administered market bid-based auction. But this section need not, and should not, be read so narrowly given the record in this
proceeding, including the information set forth in this filing regarding the harmful implications of creating an inconsistency between the design of the NYISO’s Net Benefits Test and its
demand response cost allocation rules.

The August 2011 Filing proposed, following the NYISO’s discussions with its

stakeholders, to retain a slightly modified version of its existing cost allocation methodology that allocates DADRP costs to all Loads. The September 2011 Answer explained how Load taking service under bilateral contracts benefit from the dispatch of cost-effective Demand Side
Resources even if they do not make direct purchases in the NYISO energy market, indicating, among other things, that “bilateral contracts are a part of the larger New York market, even if the contract price is not directly derived from NYISO market-clearing prices . . .” and “these
customers benefit from the trends in the New York electricity markets over time, whether or not those benefits accrue immediately under the terms of those contracts.”

Moreover, as described below in Section III.C, all Loads, including Loads being served
under bilateral contracts, are assessed charges, including congestion costs and Ancillary Services
charges, that would be impacted by the dispatch of Demand Side Resources in the NYISO’s
Day-Ahead Market. This fact undermines a key assumption upon which the May 16 Order’s
cost allocation ruling was apparently based. Similarly, Section III.D explains that the May 16
Order’s restrictive interpretation of section 35.28(v)(B) would create arbitrary and unfair costs
shifts. Section III.E notes that the May 16 Order’s restrictive interpretation is inconsistent with

the more flexible approach that the Commission has taken in its Order No. 745 compliance

orders regarding the PJM Interconnection, LLC (“PJM”). The NYISO’s understanding is that
the Order No. 745 related demand response compensation costs in PJM are allocated to all loads
and there is no special treatment for customers taking service under bilateral contracts. It is
unclear, and the Commission has not explained why, it would adopt a seemingly reasonable and
broad interpretation of section 25.28(v)(B)’s requirements in PJM but a narrow one in New
York.

In addition, the attached Joint Affidavit of Scott M. Harvey and William W. Hogan

describes three principal cost allocation principles that they recommend the Commission adhere
to when considering cost allocation proposals under Order No. 745. Drs. Harvey and Hogan
assert that costs should be allocated in a manner that: (i) avoids undue distortion in market
participant behavior, (ii) avoids undue implementation costs, and (iii) when relevant, assigns
costs based on causation. All three of these principles are consistent with the Commission taking
a broader, more flexible view of the cost allocation proposal that was submitted in the August
2011 Filing.

The Commission failed to adequately explain its reasons for finding that the NYISO’s
cost allocation methodology did not conform to Order No. 745’s requirements.36 The
Commission simply stated in the May 16 Order that it disagreed that the NYISO’s methodology
satisfied the Order No. 745 requirements and agreed with certain protestors that they do not
directly purchase energy in the relevant NYISO market. The Commission failed to address the
NYISO’s arguments in its September 2011 Answer. Rather, the Commission focused on the

36 See Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (noting that an agency “must examine the relevant data and articulate a satisfactory explanation for its action.”).

protest of a small number of Load resources who erroneously claimed not to be impacted by the selection of Demand Side Resources in New York.

In addition, Order No. 745-A expressly stated that the Commission would provide

“sufficient flexibility for each individual RTO and ISO to determine, in consultation with their stakeholders, an appropriate cost allocation methodology that complies with the Final Rule.”37 Although this statement was directly applicable to the language in Section 35.28(v)(B) that
pertains to identifying “area[s] where the demand response reduces the market price for energy at the time when the demand response resource is committed or dispatched” the Commission could, and should, allow for similar regional flexibility in interpreting the regulation’s references to
“purchasing” from “relevant energy markets” in New York. The May 16 Order certainly does not appear to have provided the NYISO and its stakeholders with the permitted flexibility to
fashion a suitable cost allocation proposal for New York.

B. Requiring the NYISO to Adopt Cost Allocation Rules that Would Be

Fundamentally Incompatible with its Net Benefits Test Would Not Constitute Reasoned Decision-Making

The design of NYISO’s Net Benefits Test is inextricably linked to that of the NYISO’s

DADRP cost allocation methodology. The May 16 Order conditionally accepted the Net

Benefits Test, but found that the NYISO had failed to demonstrate that its cost allocation

methodology was consistent with the requirements of Order No. 745. As described in detail in
Section II.F above, requiring modifications to the NYISO’s cost allocation methodology that are
fundamentally incompatible with the assumptions underlying the Net Benefits Test will very
likely result in inefficient and inequitable outcomes and may shift DADRP costs from some or
all Load with bilateral contracts to all other Load. Accordingly, the Commission should grant

37 Order No. 745 at P 102.

rehearing and accept the cost allocation methodology that was proposed in the August 2011

Filing that is consistent with the Net Benefits Test that the Commission conditionally accepted.

C. It Would Not Be Reasoned Decision-Making, But Would Be Unduly

Discriminatory, for the Commission to Ignore the Benefits that Load with
Bilateral Contracts Derive from the NYISO-Administered Energy Market
and to Exclude Such Customers from Being Allocated DADRP Costs

Load being served under bilateral contracts for Energy in New York, including NYPA

Program Customers, derive benefits from the reduction in the LBMP for Energy in the NYISO’s
Day-Ahead Market that results from the dispatch of Demand Side Resources. For this reason,
the Commission should grant rehearing and accept the NYISO’s proposed cost allocation
methodology set forth in its August 2011 Filing as consistent with the requirements in Order No.
745.

In its protest, OxyChem argued that it has a bilateral contract for Energy and does not benefit from the reduced LMP for Energy due to the dispatch of Demand Side Resources. Specifically, OxyChem stated:

NYISO’s DR cost allocation method assumes that every customer that pays

charges under NYISO’s Schedule 1, pursuant to which it recovers DR charges,

actually pays LMP. This is a crucial assumption because if an entity does not pay
an LMP-based price for energy, then it obviously cannot benefit from reduced
LMP.38

Similarly, NYAPP stated in its protest that “Transmission Customers that have fixed price

bilateral power contracts do not purchase in the NYISO’s energy market and do not benefit from reduced prices for energy in that market.”39

These assertions are not correct. Load being served under bilateral contracts for Energy
in New York, including NYPA Program Customers, do, in fact, benefit from the reduced prices

38 OxyChem Protest at p 9.

39 NYAPP Protest at p 4.

for Energy in the NYISO’s Energy market resulting from the dispatch of Demand Side

Resources. Such Load is responsible for paying a Transmission Usage Charge (“TUC”), which is determined based on the settlement of the NYISO’s Day-Ahead Market and can be reduced as a result of the dispatch of Demand Side Resources.

Loads that purchase directly from the NYISO’s Day-Ahead Market are responsible for
paying the LBMP for that market, which is composed of three separate price components: (i) an
energy price component, (ii) a marginal losses price component, and (iii) a congestion price
component. Loads taking service under a bilateral contract are responsible for the Energy price
negotiated under that contract.   Some bilateral contracts are structured such that LBMP has a
direct impact on the price paid for energy under the contract.   It would be very difficult or
impossible, however, for the NYISO to accurately determine which contracts take account of
LBMP in their pricing structure, and in what manner, and which do not.
Even in fixed price bilateral contracts that do not take account of LBMP in their pricing structure, the transactions are still assessed a TUC for the use of the New York transmission system that is composed of both the congestion price component and the marginal losses price component of the LBMP.   The congestion price component is determined based on the
difference in the Day-Ahead Market Energy prices between the sink location and the source
location of the transaction. Where the dispatch of Demand Side Resources results in lower Day-
Ahead Market Energy prices in a congested location, it also lowers the congestion price
component of the TUC paid by Load being served under bilateral contracts. Therefore, Load
taking service under bilateral contracts, including NYPA Program Customers, do benefit from a
reduction in the Day-Ahead Market Energy price resulting from the dispatch of Demand Side
Resources.

Load taking service under bilateral contracts, including NYPA Program Customers, also
pay for Ancillary Services and benefit when the dispatch of Demand Side Resources in the
NYISO’s Day-Ahead Market results in a reduction of Ancillary Services prices. The NYISO
settles its Day-Ahead Market by performing a simultaneous co-optimization of all resources to
meet Load, transmission security and Ancillary Services requirements and selects the set of
resources that achieves the lowest bid-in production costs to meet all obligations. The clearing
price for the products is the marginal costs of the service. For Regulation Service and Operating
Reserves, this includes the marginal resources’ offered costs for providing the services as well as
that resources lost opportunity costs incurred by not selling in other markets. When Demand
Side Resources are scheduled in the NYISO’s Energy market, such action results in a lower
LBMP than would be achieved with the next available generation resource. The lower LBMP
costs can also result in lower Ancillary Service prices by reducing the lost opportunity cost
component of the Regulation Service and Operating Reserve clearing prices. Load, including
Load taking service under bilateral contracts, benefit from the scheduling of Demand Side
Resources when it reduces Ancillary Services prices.

Load taking service under bilateral contracts for Energy in New York, including NYPA
Program Customers, receive benefits from the cost-effective dispatch of Demand Side Resources
in the NYISO’s Energy market. Accordingly, the Commission should accept the NYISO’s
proposed cost allocation methodology set forth in its August 2011 Filing. It would be unduly
discriminatory to let such Load receive benefits while shifting the costs to other Load in New
York. Contrary to what certain parties claimed in their protests of the August 2011 Filing, it
would also be fully consistent with applicable cost allocation precedent40 to assign demand

40 See, e.g., Ill. Commerce Comm’n v. FERC., 576 F. 3d 470, 477 (D.C. Cir. 2009) (affirming that cost allocation need not be precise “to the last penny” so long as there is reason to believe that costs are at least “roughly

response compensation related costs to Loads taking service under bilateral contracts, including NYPA Program Customers, because those customers do receive material benefits in relation to the costs shifted to them.

D. It Would Not Be Reasoned Decision-Making for the Commission to

Undermine the Basic Structure of the NYISO Cost Allocation System41

The load ratio share methodology is the fundamental mechanism for allocating costs
among Loads in the NYISO-administered markets. It is based on the premise that all Loads
benefit from inextricably interrelated market, operational, and reliability services, including the results of the various demand reduction programs, and therefore should bear a proportionate
burden of the cost of those programs. Exempting bilateral energy purchasers from the costs of demand response programs would arbitrarily and unfairly shift these costs to the remaining Loads that benefit from them. This cost shifting would introduce artificial factors that favor one manner of participation over another, distorting market economics.

E. It Would Not Be Reasoned Decision-Making for the Commission to Impose

Different Cost Allocation Requirements on the NYISO than it Applied to Other ISOs/RTOs

The Commission has accepted cost allocation methodologies proposed by other

ISOs/RTOs that are substantially similar to the methodology proposed by the NYISO. For

example, PJM, in its Order No. 745 compliance fling, proposed to recover costs for payments to
demand response participants from “Market Participants on a ratio-share basis based on their
real-time exports from the PJM Region and from Load Serving Entities on a ratio-share basis

commensurate” to the costs imposed and it is not the case that customers receive no or “trivial” benefits from costs incurred); Midwest ISO Transmission Owners v. FERC, 373 F,3d 1361, 368 (D.C. Cir. 2004).

41 The NYISO would consider possibly adjusting the cost allocation methodology to allocate costs on an hourly basis for the periods of the schedules of Demand Side Resources in DADRP to more closely tie the period cost to those active during the period (hourly) of actual DADRP schedules instead of allocating the costs on a daily basis. However, this issue was not raised in the original order and would best be discussed with stakeholders prior to
making any tariff change proposals.

based on their real-time loads....”42 In accepting PJM’s proposed tariff revisions, the

Commission found that “PJM’s proposed cost allocation methodology broadly satisfies the requirement of Order No. 745.”43

PJM’s cost allocation methodology, like the methodology proposed by the NYISO,

allocates costs for demand response payments to Load Serving Entities (“LSE”) based on their

load-ratio share regardless of whether the LSE procured the energy to meet its load from the PJM
energy market or through a bilateral contract. Accordingly, the Commission’s finding in this
proceeding that “NYISO has failed to demonstrate how its proposal to allocate demand response
costs as an Schedule 1 uplift cost that is then allocated to transmission customers on the basis of
their load ratio shares appropriately allocates costs to entities purchasing in NYISO’s energy
market that benefit from the lower prices produced by dispatching demand response” is an
unexplained departure from Commission precedent that is unjust, unreasonable, and unduly
discriminatory.44

IV. SPECIFICATION OF ERRORS AND STATEMENT OF ISSUES

In accordance with Rule 713(c), the NYISO submits the following specification of errors and statement of the issues on which it seeks rehearing of the May 16 Order:

 The May 16 Order’s application of an overly and unnecessarily restrictive interpretation
of Order No. 745’s cost allocation requirements to the NYISO does not constitute
reasoned decision-making,45 overlooked important facts, was not reasonably explained,46

42 PJM Interconnection, L.L.C. Order No. 745 Compliance Filing, Docket ER11-4106-000 at 23 (filed July 22,
2011).

43 PJM Interconnection, L.L.C. Order on Compliance Filing, 137 FERC ¶ 61,216 at P 78 (2011); see also ISO New England, Inc. Order on Compliance Filing, 138 FERC ¶ 61,042 at P 42 (2012) (“it is reasonable for ISO-NE to allocate costs based on Real-Time Load Obligation.”)

44 May 16 Order at P 92.

45 See Williston, 358 F.3d at 48 (“Commission ‘must demonstrate that it has made a reasoned decision based upon substantial evidence in the record’.”).

46 See Motor Vehicle Mfrs. Ass’n , 463 U.S. at 43 (noting that an agency “must examine the relevant data and articulate a satisfactory explanation for its action.”).

is contrary to sound cost allocation principles,47 and failed to afford the NYISO and its stakeholders the “regional flexibility” promised by Order No. 745-A.

 Requiring the NYISO to adopt cost allocation rules that would be fundamentally

incompatible with its Net Benefits Test does not constitute reasoned decision-making.48

 It would not be reasoned decision-making, but would be unduly discriminatory, for the

Commission to ignore the benefits that Load customers with bilateral contracts derive

from the NYISO-administered Energy Market and to exclude such customers from being allocated DADRP costs,49 and the Commission should not conclude that allocating
demand response compensation related costs to customers in New York would be
inconsistent with applicable cost allocation precedent.50

 It would not be reasoned decision-making for the Commission to undermine the basic

structure of the NYISO cost allocation system.51

It would not be reasoned decision-making for the Commission to impose different cost allocation requirements on the NYISO than it applied to other ISOs/RTOs.52

V. ALTERNATIVE REQUEST FOR EXPEDITED CLARIFICATION

The NYISO currently has approximately two months to submit the compliance filing

required by the May 16 Order. It will make every effort to work with its stakeholders to develop revisions to its DADRP that are consistent with Order No. 745 and the Commission’s May 16 Order. If the Commission denies the request for rehearing sought by the NYISO regarding the Commission directives in its May 16 Order regarding the NYISO’s cost allocation methodology, the NYISO respectfully requests that the Commission expeditiously grant the following
clarifications as far in advance of the August 14 compliance filing deadline as possible to enable the NYISO to develop with its stakeholders the necessary revisions.

The Commission should clarify that the NYISO may make any revisions to the Net
Benefits Test, which the Commission conditionally accepted in its May 16 Order, that are

47 See Attachment I.

48 See n. 45.

49 See n. 45

50 See, e.g., Ill. Commerce Comm’n v. FERC., 576 F. 3d 470, 477 (D.C. Cir. 2009); Midwest ISO Transmission Owners v. FERC, 373 F,3d 1361, 368 (D.C. Cir. 2004).

51 See n. 45.

52 See n. 45.

necessary to make its methodology consistent with a revised cost allocation methodology. As described elsewhere in this filing, if the Net Benefits Test and the cost allocation methodology are not consistent, it will result in inefficient and inequitable outcomes.

The Commission should also clarify that the May 16 Order is only intended to require the
NYISO to revise its current cost allocation methodology to exclude Load taking service under
NYPA’s Replacement Power and Expansion Power program, which is the one category of Load
taking service under a bilateral contract that the Commission expressly found not to “purchase
energy in the relevant NYISO energy market.” Bilateral transactions constitute approximately
half of the Energy transactions in New York and many of these bilateral transactions are supplied
through purchases in the NYISO’s Energy market or are otherwise connected to this market.

Moreover, the NYISO has every reason to believe these bilateral contracts are competitively

negotiated arrangements that are influenced by the competitive market outcomes of the NYISO’s marketplace. Expectation of future price changes in the NYISO markets, as well as reflections
of past outcomes, will be incorporated into future contractual negotiations that determine
bilateral contracts financial terms. For these reasons, it would be unreasonable for the
Commission to require the NYISO to exclude out of its cost allocation methodology all Load
taking service under a bilateral contract, and the Commission should clarify that it did not intend the NYISO to take such action.

VI. ALTERNATIVE REQUEST FOR WAIVER

If the Commission does not grant rehearing as requested in Sections III and IV above, the
NYISO respectfully requests that the Commission grant the NYISO a temporary waiver of its
obligation to comply with the cost allocation requirement established by section 35.28(v)(B) of
the Commission’s regulations. Such a waiver would permit the NYISO to continue to use its

existing cost allocation methodology, which has previously been accepted by the Commission as just and reasonable, while the NYISO evaluates the need to revise its Net Benefits Test, and if necessary designs a new Net Benefits Test, to conform to a revised cost allocation methodology. The NYISO will report to the Commission as part of its August 14 compliance filing on whether it believes that changes to its Net Benefits Test will be needed in order to once again make it consistent with a revised cost allocation methodology.

As described above, the NYISO’s Net Benefits Test, which was conditionally accepted
by the Commission in its May 16 Order, includes Suppliers serving all Load in New York,
including Suppliers serving Load to satisfy bilateral contracts, in its development of the supply
curve for identifying the price at which the benefits to load of dispatching Demand Side
Resources exceed the costs. This Net Benefits Test was designed to be consistent with the
NYISO’s existing cost allocation methodology that allocates demand response related costs to all
Load, including Load taking service under bilateral contracts. If the Commission’s interpretation
of the Order No. 745 cost allocation requirements in its May 16 Order to exclude certain Load
taking service under bilateral contracts from being subject to the NYISO’s cost allocation
requirements is upheld on rehearing, the NYISO will very likely have to amend the Net Benefits
Test to ensure that its supply curve excludes Suppliers serving certain customers under bilateral
contracts. As described above, absent such modifications, the Net Benefits Test results may be
distorted and result in the unnecessary dispatch of Demand Side Resources that are not cost
effective or fail to dispatch Demand Side Resources when they are cost effective, while requiring
a subset of Load to pay for any resulting costs when they may not have received any tangible
benefit.

The NYISO anticipates that designing a new Net Benefits Test would require an

extensive, lengthy process and would require working with its stakeholders in the development of a new methodology. As described above, Suppliers offer into the NYISO energy markets to serve the whole market and are not tied to specific Load. In addition, as described above, a
number of Suppliers partially satisfy their obligations under bilateral contract by making
purchases in the NYISO’s Energy market. For these reasons, it will be extremely difficult for the NYISO to determine which, if any, of a Supplier’s bids should be excluded from the Net
Benefits Test for purposes of developing the supply curve.

Given the extensive work that would be required to re-design the Net Benefits Test to

conform with a revised cost allocation methodology, the NYISO anticipates that it could require a considerable time to complete. The NYISO, therefore, requests that the Commission grant it a temporary waiver of the cost allocation requirement in section 35.28(v)(B) of its regulations to permit the NYISO to continue to use its existing cost allocation methodology, which is
consistent with the current Net Benefits Test, until it can determine whether its Net Benefits Test must be re-designed, and if it must, until it can complete that re-design.

The Commission has previously evaluated a number of issues in determining whether to grant a waiver. These include whether: (1) the underlying error was made in good faith; (2) the waiver is of limited scope; (3) a concrete problem needs to be remedied; and (4) the waiver will not have undesirable consequences, such as harming third parties.53 The NYISO’s waiver
request satisfies each of these criteria.

53 See, e.g., California Independent System Operator Corp., 116 FERC ¶ 61,226 at P 8 (2006) (granting limited

waiver of tariff provisions governing sanctions for failing to timely submit generator outage and other information in
order to allow California ISO to ensure that market participants were not inappropriately penalized); New York
Independent System Operator, Inc., 112 FERC ¶ 61,347 at P 7 (2005) (granting the NYISO a discrete tariff waiver
in order to recalculate certain charges); Great Lakes Gas Transmission Limited Partnership, 102 FERC ¶ 61,331 at
P 16 (2003) ("Great Lakes has shown good cause for its Emergency Waiver request and has shown that the impact
on non-exempt customers whose supply may be curtailed will be de minimis."); TransColorado Gas Transmission

Good Faith. The NYISO acted in good faith by arguing in its August 2011 Filing and, in
this filing, that its proposed Net Benefits Test and existing cost allocation methodology, as
revised, satisfy the Commission’s Order No. 745 requirements. In response to the Commission’s
May 16 Order, finding that the NYISO has not demonstrated that its cost allocation methodology
satisfies these requirements, the NYISO is diligently exploring revisions to its methodology and
conforming revisions to its Net Benefits Test to address the Commission’s directives.
The waiver is of limited scope. The NYISO is requesting a limited, temporary waiver to permit the NYISO to continue to apply the cost allocation methodology in its tariffs that the
Commission has previously accepted as just and reasonable to provide the NYISO with the time
required to evaluate possible changes to its Net Benefits Test to conform it to a revised cost
allocation methodology. The NYISO will report to the Commission as part of its August 14
compliance filing its estimated timeframe for making any necessary revisions to its Net Benefits
Test.

The waiver will remedy a concrete problem. As described above, the discrepancy

between the Net Benefits Test conditionally accepted by the Commission and a revised cost

allocation methodology based on the Commission’s direction in its May 16 Order could result in
the dispatch of unneeded or insufficient Demand Side Resources and inappropriate costs to
certain Load in New York. The NYISO’s requested waiver will ensure consistency in the
application of the Net Benefits Test and the NYISO’s cost allocation methodology. Moreover,
the waiver will allow the NYISO to implement the conditionally accepted Net Benefits Test to

Co., 102 FERC ¶ 61,330 at P 5 (2003) ("The Commission finds that in this instance, good cause has been shown to waive TransColorado's Fuel Gas Reimbursement provision in Section 12.9 of its FERC Gas Tariff, First Revised Volume I, as requested."); Northern Border Pipeline Co., 76 FERC ¶ 61,141 at 61,780 (1996) (granting one-time waiver request). See also Wisvest-Connecticut LLC v. ISO-New England, Inc., 101 FERC ¶ 61,372 at P 24 (2002) (finding that ISO-NE roles requiring assessment of deficiency penalty should not be applied in this case because market participant's error giving rise to the penalty was "an inadvertent mishap.").

replace its current static $75 dollar offer floor. Implementing DADRP with this Net Benefits Test will facilitate increased participation of Demand Side Resources and will benefit Loads when cost effective Demand Side Resources are scheduled.

Granting the waiver will not harm third parties. The Commission has previously

accepted as just and reasonable the NYISO’s existing allocation methodology for DADRP costs,
and Load in New York have been subject to such requirements for years. A temporary extension
of this methodology, to the extent necessary to allow the NYISO to design a new Net Benefits
Test that conforms with an updated cost allocation methodology, will not harm third parties.

VII. CONCLUSION

For the reasons specified above, the New York Independent System Operator, Inc.

respectfully requests that the Commission grant rehearing of the May 16 Order or, in the

alternative, provide the requested clarification and grant the NYISO a temporary waiver of its obligation to comply with 18 C.F.R. §35.28(v)(B).

Respectfully submitted,

/s/ Michael J. Messonnier, Jr.

Michael J. Messonnier, Jr. Counsel for the

New York Independent System Operator, Inc.

June 17, 2013

cc:Michael A. Bardee

Gregory Berson

Anna Cochrane

Jignasa Gadani

Morris Margolis

David Morenoff

Michael McLaughlin Daniel Nowak

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 (2013).

Dated at Washington, D.C. this 17th day of June 2013.

/s/ Catherine Karimi

Catherine Karimi

Sr. Professional Assistant

Hunton & Williams LLP

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

E-mail: ckarimi@hunton.com

UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Independent System Operator, Inc.)Docket No. ER11-4338-000

JOINT AFFIDAVIT OF SCOTT M. HARVEY AND WILLIAM W. HOGAN

I.Qualifications

1.Scott M. Harvey and William W. Hogan, having been duly sworn under oath,

each declare:

2. I, Scott M. Harvey am a consultant in the Boston, Massachusetts office of FTI
Consulting, Inc. (“FTI”) located at 200 State Street, 9th floor, Boston, Massachusetts 02109.
Prior to working at FTI,1 I was a consultant at LECG Corporation (“LECG”) from 1998 to 2011,
and at Putnam, Hayes & Bartlett, Inc. from 1987-1998. I was actively involved at FTI, LECG,
and Putnam, Hayes & Bartlett with the restructuring of the electric sector and creation of PJM
Interconnection, LLC (“PJM”), The New York Independent System Operator, Inc. (“NYISO”)
and ISO New England Inc. (“ISO-NE”), the development of the Midcontinent Independent
System Operator, Inc. (“Midwest ISOI”) Stage 2 congestion management system implemented in
April 2005, and the development and implementation of the California Independent System
Operator’s (California ISO”) Market Redesign and Technology Upgrade (“MRTU”) in April
2009.

3. I am currently a member of the Midwest ISO Market Advisory Committee and a
member of the California ISO Market Surveillance Committee. Before joining Putnam, Hayes &

1 Because of restrictions associated with his position on the California ISO Market Surveillance Committee, Dr. Harvey is an independent contractor, rather than an employee of FTI consulting.

Bartlett, I was employed as an economist in the Bureau of Economics of the Federal Trade

Commission from 1977 to 1987 where I concentrated on antitrust issues in the oil and gas

industries. I have a B.A. in Economics from the University of Illinois Champaign-Urbana and a PhD in Economics from the University of California, Berkeley.

4. I assisted the NYISO with the development of its Order No. 745 compliance

filing. I also participated in the California ISO’s response to Order No. 745 as a member of the California ISO Market Surveillance Committee, and participated in the writing of the Market Surveillance Committee’s opinion advising the California ISO Board on Order No. 745
compliance issues.2 I subsequently prepared a report to the ISO/RTO Council on Methods of Implementing an on-line dynamic net benefits test that was submitted to the Federal Energy Regulatory Commission (“FERC” or “Commission”).3

5. I, William W. Hogan, am the Raymond Plank Professor of Global Energy Policy,
John F. Kennedy School of Government, Harvard University. I serve as the Research Director of
the Harvard Electricity Policy Group. I am also a Director Consultant at FTI. I am part of the
Economic Consulting Segment of FTI, which specializes in providing economic, financial, and
regulatory policy consulting services to private parties and, to a lesser extent, public
organizations.

6. I am or have been a consultant on electric market reform and transmission issues
for Allegheny Electric Global Market, American Electric Power, American National Power,

2 James Bushnell, Scott Harvey, Benjamin Hobbs, Steven Stoft, Supplemental Opinion on Economic Issues
Raised by FERC Order 745: “Demand Response Compensation in Organized Wholesale Energy Markets” (May 27,
2011).

3 Scott Harvey, “Options for Implementing a Dynamic Net Benefits Test Based on the Billing Unit Effect

(2012).

Aquila, Atlantic Wind Connection, Australian Gas Light Company, Avista Corporation, Avista
Utilities, Avista Energy, Barclays, Barclays Bank PLC, Brazil Power Exchange Administrator
(ASMAE), British National Grid Company, California Independent Energy Producers
Association, California ISO, California Suppliers Group, Calpine Corporation, CAM Energy,
Canadian Imperial Bank of Commerce, Centerpoint Energy, Central Maine Power Company,
Chubu Electric Power Company, Citigroup, City Power Marketing LLC, Cobalt Capital
Management LLC, Comision Reguladora De Energia (CRE, Mexico), Commonwealth Edison
Company, COMPETE Coalition, Conectiv, Constellation Energy, Constellation Energy
Commodities Group, Constellation Power Source, Coral Power, Credit First Suisse Boston, DC
Energy, Detroit Edison Company, Deutsche Bank, Deutsche Bank Energy Trading LLC,
Duquesne Light Company, Dyon LLC, Dynegy, Edison Electric Institute, Edison Mission
Energy, Electricity Corporation of New Zealand, Electric Power Supply Association, El Paso
Electric, Exelon, Financial Marketers Coalition, FTI, GenOn Energy, GPU Inc. (and the
Supporting Companies of PJM), GPU PowerNet Pty Ltd., GDF SUEZ Energy Resources NA,
Great Bay Energy LLC, GWF Energy, Independent Energy Producers Assn., ISO-NE, Koch
Energy Trading, Inc., LECG, Luz del Sur, Maine Public Advocate, Maine Public Utilities
Commission, Merrill Lynch, Midwest ISO, Mirant Corporation, MIT Grid Study, Monterey
Enterprises LLC, MPS Merchant Services, Inc. (f/k/a Aquila Power Corporation), JP Morgan,
Morgan Stanley Capital Group, National Independent Energy Producers, New England Power
Company, NYISO, New York Power Pool, New York Utilities Collaborative, Niagara Mohawk
Corporation, NRG Energy, Inc., Ontario Attorney General, Ontario IMO, Ontario Ministries of
Energy and Infrastructure, Pepco, Pinpoint Power, PJM, PJM Power Provider (P3) Group,
Powerex Corp., Powhatan Energy Fund, Powerex, PPL Corporation, PPL Montana LLC, PPL

EnergyPlus LLC, Public Service Company of Colorado, Public Service Electric & Gas

Company, Public Service New Mexico, PSEG Companies, Red Wolf Energy Trading, Reliant
Energy, Rhode Island Public Utilities Commission, San Diego Gas & Electric Company
(“SDG&E”), Sempra Energy, SESCO LLC, Shell Energy North America (U.S.) L.P., SPP,
Texas Genco, Texas Utilities Co, Twin Cities Power LLC, Tokyo Electric Power Company,
Toronto Dominion Bank, TransAlta, TransAlta Energy Marketing (California), TransAlta
Energy Marketing (U.S.) Inc., Transcanada Corp., TransCanada Energy LTD., TransÉnergie,
Transpower of New Zealand, Tucson Electric Power, Westbrook Power, Western Power Trading
Forum, Williams Energy Group, Wisconsin Electric Power Company, and XO Energy. The
views presented here are not necessarily attributable to any of those mentioned.

7. I assisted the NYISO and the RTO/ISO Council in preparing a range of filings
addressing the economics of demand response. These documents were filed at the FERC in the
process that culminated in Order No. 745. Further details can be found on my web page at
www.whogan.com.

II. Introduction

8. This affidavit discusses the principles and empirical relationships that should govern the allocation of payments paid to demand response providers under Order No. 745 and the associated implementation costs.

9. Under Order No. 745, customers providing demand response that satisfy the “Net Benefits Test” prescribed by FERC will not only avoid paying for the power they do not

consume, they will also be paid for the reduction in consumption relative to their baseline.4 In
addition to the benefits to customers that participate in the demand response, the reduction in
power demand will, in the very short-run, reduce spot power prices paid by all customers,
including those that do not participate in the demand response. The payment for demand
response is to be collected from the customers that continue to consume power and potentially
derive a pecuniary benefit from the reduction in spot energy prices provided by the demand
response.

III.Cost Allocation Principles

10.Costs should be allocated in a manner that: (i) avoids undue distortions in market

participant behavior, (ii) avoids undue implementation costs, and, (iii) if relevant, assigns costs based on cost causation. Each of these principles is discussed below as it applies to the
allocation of Order No. 745 costs by the NYISO.

a. Avoid Undue Distortions in Market Participant Behavior

11. The application of this principle generally favors allocating the costs of payments,
such as those associated with Order No. 745, to customers with the most inelastic demand,
because their consumption will be least impacted by the allocation of these costs, and hence
allocating costs to these customers will result in the least distortion in efficient consumption
patterns. The NYISO cannot allocate costs based on this principle, however, because it
coordinates a wholesale market and cannot allocate costs to particular categories of retail
customers. Retail rate design is determined by the New York Public Service Commission.

4 In recent Order No. 745 related orders, FERC has required that such payments be made for all reductions in demand, without regard to whether the “net benefits test” is satisfied. See e.g. Midwest Independent Transmission System Operator, Inc., 143 FERC ¶61,145 (2013).

12.The most apparent potential application of this principle in the context of Order

No. 745 costs concerns the allocation of the cost of demand response payments to transmission
customers that buy power at prices that are not directly related to the wholesale spot market
price.

13. The Commission in its order directs the NYISO to demonstrate the

appropriateness of its cost allocation rule for the customers that pay for power on a basis that

would not be impacted by the billing unit effect, such as customers that buy power through New
York Power Authority’s (“NYPA”) Replacement Power and Expansion Power. Customers
served by utilities that are vertically integrated with generation (and hence generate power,
incurring fuel and operating and maintenance costs, to meet their customers demand rather than
purchasing power at the spot price), and customers that buy power under long-term contracts
entered into prior to Order No. 745, or under cost-based contracts whose price does not depend
on spot prices, would also not benefit from any billing unit effect on price in the spot energy
market.

14. However, it must also be recognized that the power consumed by these customers
is included in the purchase quantity used to apply the net benefits tests. Hence, there is a
fundamental inconsistency in distinguishing the basis on which power is purchased for the
purpose of allocating Order No. 745 costs, but not for the purpose of applying the net benefits
test.

15. Moreover, just as there is likely no direct pecuniary benefit in the energy market
to customers not buying power in the spot market from subsidized demand response, as
discussed below, there is likely little or no ultimate pecuniary benefit from the billing unit effect

to customers that are buying power in the spot market. Hence, allocating the cost of demand response payments to customers that buy power in the spot market but not to other customers would provide an artificial and inefficient incentive for transmission customers to buy power outside the spot market. This incentive would be a greater concern if the exemption from the allocation of the costs of Order No. 745 demand response payments were not limited to
contractual arrangements in place prior to Order No. 745.

16. If the exemption from the allocation of the costs of Order No. 745 demand

response payments were not limited to contracts in place prior to Order No. 745, but extended to
all bilateral contracts, there could be a substantial incentive for market participants to withdraw
from the spot market. This would narrow the allocation of the Order No. 745 costs in a manner
that would arbitrarily burden those customers unable to structure their purchase in the manner
required to avoid the cost allocation and, depending on the details of the terms required to avoid
the cost allocation, could encourage self-scheduling of generation and discourage participation in
the economic dispatch, which could undermine reliability. These incentives would be less of a
concern if the Order No. 745 payments were insignificant, but if they are insignificant, there is
no reasonable basis to require the NYISO to incur the costs required to implement and maintain
distinct allocation rules for these costs.

17. Even if the exemption were limited to pre-existing contracts, (i) implementation
could be complex because the NYISO does not have access to all of the contractual
arrangements between the parties to these contracts, (ii) determining whether the contract price is
in fact independent of future spot prices may not always be straightforward for the NYISO to

determine, particularly with limited access to contractual information5; (iii) there could be cost
impacts outside the energy market, such as on ancillary service costs, uplift costs or capacity
market costs; and (iv) an inconsistency would exist between the sales volumes on which the net
benefits test was based and sales volumes to which the cost of demand response payments would
be allocated. All of these considerations argue for a broad based cost allocation that does not
attempt to carve out exemptions based on the likely level of direct pecuniary benefits.

b. Avoid Undue Implementation Costs

18. A second principle in allocating costs is that it is desirable to avoid allocation
designs that would require undue costs to implement, thus in effect magnifying the costs that must be borne by transmission customers. Any cost allocation design that differs from existing rules used to allocate costs to transmission customers will require additional expense for the
NYISO to implement. Beyond this, some kinds of additional detail in the allocation of the cost of these demand response payments could inflate the implementation costs borne by transmission customers and could exceed the value of the payments themselves.

19. Hence, other things being equal, it is reasonable for the NYISO to allocate the

cost of the payments to demand response providers broadly to all power consumers rather than to compound the adverse impact on consumers by incurring excessive costs to more precisely
allocate the largely illusory pecuniary benefits of the billing unit effect.

20. There are some minor changes in the NYISO’s original cost allocation design that
would be consistent with the principle of avoiding undue costs of compliance. Instead of
allocating the costs of these payments in proportion to daily load as originally proposed, the

5 Assessing the extent to local serving entities vertically integrated into generation derive pecuniary benefits from the “billing unit effect,” would be even more complex for the NYISO to assess and to carry out accurately
could require an hour by hour assessment.

NYISO could, without undue additional implementation cost, allocate the cost of payments for demand response under Order No. 745 based in the hour in which the demand response was activated. Hence, the costs would be allocated in proportion to load in the hour they were
incurred, rather than in proportion to daily load. However, more elaborate measures of cost allocation could do more harm than good.

21. Another level of complexity concerns the way in which transmission congestion is accounted for in allocating the cost of Order No. 745 payments. The actual billing unit effect at each location will depend on the congestion pattern on the New York grid in the day-ahead market, the actual supply curve reflecting the unit commitment (as opposed to the projected
average monthly “supply curve” based on offers without regard to unit commitment effects that is used to apply the net benefit test). The NYISO has proposed a reasonable, low cost approach to accounting for congestion impacts.

22. More accurately accounting for the congestion impacts would require taking

account of additional major constraints, load pockets within New York City and the differential
impact of load at distinct locations on central east congestion. This would involve a more
complex calculation than that proposed by the NYISO, calculations that would require material
NYISO resources to develop and implement, and additional costs that would be borne by power
consumers. Moreover, in assessing whether it would be warranted to incur these additional
implementation costs it should be recognized that net billing effects calculated taking account of
congestion using an aggregate monthly supply curve and ignoring unit commitment effects
would not necessarily allocate the costs of payments in a manner that more closely approximates
any benefits from the net billing effect than would the method proposed by the NYISO. Even
developing models that could be used to evaluate the accuracy would require substantial NYISO

resources that would have to be diverted from market enhancements that would contribute to reducing, rather than increasing, transmission customer costs.

23. Finally, spending additional NYISO resources to more accurately allocate the cost of Order No. 745 payments in proportion to calculated benefits based on a “net billing unit”
effect is not appropriate because the calculation of a pecuniary “net billing unit” effect does not
reflect the actual overall impact of the demand response payments on consumer costs. In
practice, there is likely to be little if any pecuniary benefit to consumers from the subsidized
demand response, hence it does not make public policy sense to compound the adverse rate
impact of these payments on consumers by incurring additional costs to implement a complex
allocation scheme for these costs.

c. Allocate Costs Based on Cost Causation

24. It is generally desirable to allocate costs to the market participants that caused the NYISO to incur those costs or conversely to those that benefit from the policies that give rise to those costs. Hence, it would be desirable, other things being equal to allocate the cost of the Order No. 745 payments to those that benefit from them.

25. As discussed above, it would be complex and costly to calculate the actual billing unit effect at each location in each hour. But even the actual “billing unit effect,” if it could be calculated accurately, would not measure the actual pecuniary benefit to consumers.

26. There are three reasons that even an accurately calculated “billing unit effect,”
would not accurately measure the pecuniary benefit to consumers from these payments. First,
the “billing unit effect” is calculated based on the amount of demand response that is paid for,
not the amount of demand reduction that actually occurs. Second, any reduction in energy prices
and margins in the hours in which demand response is activated under Order No. 745, as

opposed to activated by the NYISO to manage reliability through demand response participating in the capacity market, will be transitory at best. Third, the “billing unit effect” does not account for the pecuniary cost to the remaining consumers of reduced demand and billing units.

27. Consider the first observation. The actual demand reduction from Order No. 745
demand response will be less than the amount of demand response receiving payments. This is
intrinsic in negawatt programs that pay the LBMP for demand reductions relative to a
hypothetical baseline. NYISO measuring and verification programs can at best only limit the
payments for deemed demand response that does not result in any actual load reduction. The
costs paid for deemed demand response that does not result in any actual load reduction must be
allocated to someone and would best be allocated broadly since there are no beneficiaries from
these payments.

28. Second, the calculation of the “billing unit effect” does not account for the effect
of reduced energy prices and margins in reducing investment in low cost generation. To the
extent that the demand response reduces energy prices in some range, this would reduce the
incentive to build capacity with costs low enough to earn a margin in that range. This reduced
investment in low cost generating capacity would serve to raise energy prices and margins.
Hence the billing unit effect is ephemeral in the time frame in which additional generation will
be built in New York. The duration of any “billing unit effect” benefit will be particularly short
given the recent shut-down of older generating units in New York and the need for new
generating capacity.

29. Third, to the extent that power consumption is actually reduced by Order No. 745
demand response in real-time, any pecuniary “billing unit effect” to the remaining transmission
customers will be offset in part by the pecuniary cost to those customers of having more market,

NYISO and transmission costs (Schedule 1 costs, ancillary service costs, and TSC charges) allocated to those remaining transmission customers.

30. Finally, if the NYISO is not permitted to maintain a bid floor for demand

response offers,6 the NYISO will be making payments for demand response without regard to whether the demand response passes the “net benefits test.” If this is the case, there would be even less reason to incur additional costs in order to allocate the cost of the demand response payments in some manner related to a calculated billing unit effect, as the calculated billing unit effect would not govern the demand response payments.

IV. Conclusion

31. In light of the goals of avoiding undue distortion of market participant behavior, avoiding undue implementation costs, and recognizing the general lack of any pecuniary benefit to any set of transmission customers, it would be best to allocate the costs of Order No. 745
demand response payments broadly to all power consumers, using rules that require minimal costs for the NYISO to implement.

6 See 143 FERC ¶ 61,134 at P 46.

UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Independent System Operator, Inc.)Docket No. ER11-4338-000

CONFIRMING AFFIDAVIT OF ROBERT PIKE AND CHRISTOPHER RUSSELL

Mr. Robert Pike and Mr. Christopher Russell each declare:

1. Mr. Pike is the Director of Market Design for the New York Independent System

Operator, Inc. (“NYISO”). Mr. Pike’s business address is 10 Krey Boulevard, Rensselaer, New York 12144.

2. Mr. Pike has worked for the NYISO and its predecessor organization, the New

York Power Pool, for over twenty years. Mr. Pike has been involved in the design
and implementation of electric markets at the NYISO for the past 15 years.
3. Mr. Pike holds a Bachelor of Science in Electrical and Computer Engineering and
Master of Science in Electrical Engineering from Clarkson University and a Master
of Business Administration from Union College.

4. Mr. Pike is directly involved in the integration of Demand Side Resources into the

NYISO energy market and the NYISO’s compliance with Order No. 745

5. Mr. Russell is Manager of Customer Settlements for the NYISO. Mr. Russell’s

business address is 10 Krey Boulevard, Rensselaer, New York 12144.

6. Mr. Russell oversees NYISO staff responsible for the accurate and timely billing of

all NYISO market settlements as well as the performance of unique and complex analyses to support settlement rules.

7.Mr. Russell was previously a Supervisor of Settlement Operations/Market

Accounting at the NYISO. Prior to being employed with the NYISO, Mr. Russell worked in management and staff roles in the financial services sector, and served for four years as an officer in the United States Army.

8. Mr. Russell is directly involved in all aspects of the administration,

implementation, and development of the NYISO’s cost allocation rules under Rate Schedule 1 and Attachment R to the Open Access Transmission Tariff, which is referenced in Rate Schedule 1.

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

could and would testify competently hereto.

10. I submit this affidavit in support of the NYISO Request for Rehearing and

Alternative Requests for Expedited Clarification and Compliance Waiver of the New York Independent System Operator, Inc. (“NYISO Request”).

11. The purpose of this affidavit is to confirm that I have participated in preparing, and

have reviewed, the NYISO Request, and that all of the statements and facts set forth in the NYISO Request are true and correct. Specifically I can confirm that the following facts cited in the NYISO Request are true and correct:

12. The NYISO introduced a Day-Ahead Demand Response Program (“DADRP”) in

New York in 2001. Under this program, a Demand Side Resource or a group of
Demand Side Resources registered as a single DADRP resource may offer its load
curtailment capability into the NYISO’s Day-Ahead Market for Energy. If its offer
is selected, the resource is paid the Locational Based Marginal Prices (“LBMP”)

for Energy at which the Day-Ahead Market settles for the relevant hour and

location. The costs of the dispatched Demand Side Resources are then allocated to all Loads on the basis of their real-time load ratio shares and in proportion to the
probability, given known transmission patterns, that a particular demand reduction will benefit a given Load by reducing Energy costs in its Load Zone or composite Load Zone. That is, the NYISO allocates DADRP costs to beneficiaries in a
manner that is consistent with the expected benefits from the dispatch of a
particular Demand Side Resource.

13. The NYISO has applied this cost allocation methodology since 2001, and all Load

has been responsible for such costs for over a decade, regardless of whether it was
taking service from a Supplier directly through the NYISO-administered markets or
under a bilateral contract. The NYISO similarly recovers from all Load its annual
budget, Ancillary Services, and uplift charges on the basis of their load ratio share.
The NYISO bills the portions of these charges allocated to Load to Load Serving
Entities, who recover the costs from retail customers, such as the NYPA Program
Customers.

14. The NYISO’s proposed Net Benefits Test is composed of a nine-step methodology

to identify the threshold price on a supply curve at which point the benefits to Load
of dispatching a demand response resource exceeds the costs to the Load. That is,
the Net Benefits Test identifies at which point a demand response resource
becomes a cost-effective alternative to generation to balance the supply and
demand for the relevant hour. Consistent with its existing methodology to allocate
DADRP costs to all Load, the NYISO’s supply curve in its Net Benefits Test

considers the Suppliers required to serve all Load in New York, including Suppliers that serve Load to satisfy bilateral contracts.

15. For purposes of its Net Benefits Test, the NYISO does not differentiate between

Suppliers that serve Load taking service directly through the NYISO’s Energy
market and those taking service through a bilateral contract. Suppliers in New
York offer into the NYISO Day-Ahead Market to serve the whole market and are
not tied within the market solutions to a specific Load. The NYISO Day-Ahead
Market economically schedules all Suppliers to meet all Load, at least cost, which
includes Loads with bilateral contracts. Notwithstanding the existence of a
bilateral contract between a Supplier and Load, the Supplier may be making
purchases in the NYISO’s Energy market or obtaining service from another
Supplier to satisfy its obligation to provide service under a bilateral contract when
it is economically efficient to do so.

16. The design of the Net Benefits Test is inextricably linked to that of the NYISO’s

existing cost allocation methodology. The Net Benefits Test is based on the
premise that has been true for the NYISO’s cost allocation methodology since
2001, and accepted by the Commission, that all Loads in New York benefit from
the dispatch of Demand Side Resources in the NYISO’s Energy Market.
Modifying one methodology, either by excluding certain Load from cost allocation
or by not considering the Suppliers serving such Load in the Net Benefits Test,
without making corresponding adjustments to the other is very likely to result in
inefficient and inequitable outcomes. If there are Loads that cannot benefit by the
reduction of LBMP for Energy in the NYISO’s Day-Ahead Market due to the

dispatch of a Demand Side Resource, then the supply curve used in the Net

Benefits Tests should exclude the Suppliers that are serving this Load. Without
this modification, the Net Benefits Test results may be distorted and the resulting
threshold price may result in the unnecessary dispatch of Demand Side Resources

that are not cost effective or fail to dispatch Demand Side Resources when they are
cost effective. The remaining Load would then be required to pay for any resulting
costs, regardless of whether they would receive any tangible benefit from them.

17. Load being served under bilateral contracts for Energy in New York, including

NYPA Program Customers, benefit from the reduced prices for Energy in the

NYISO’s Energy market resulting from the dispatch of Demand Side Resources. Such Load is responsible for paying a Transmission Usage Charge, which is
determined based on the settlement of the NYISO’s Day-Ahead Market and can be reduced as a result of the dispatch of Demand Side Resources.

18. Load taking service under bilateral contracts, including NYPA Program Customers,

also pay for Ancillary Services and benefit when the dispatch of Demand Side

Resources in the NYISO’s Day-Ahead Market results in a reduction of Ancillary
Services prices. The NYISO settles its Day-Ahead Market by performing a
simultaneous co-optimization of all resources to meet Load, transmission security
and Ancillary Services requirements and selects the set of resources that achieves
the lowest bid-in production costs to meet all obligations. The clearing price for
the products is the marginal costs of the service. For Regulation Service and
Operating Reserves, this includes the marginal resources’ offered costs for
providing the services as well as that resources lost opportunity costs incurred by

not selling in other markets. When Demand Side Resources are scheduled in the
NYISO’s Energy market, such action results in a lower LBMP than would be
achieved with the next available generation resource. The lower LBMP costs can
also result in lower Ancillary Service prices by reducing the lost opportunity cost
component of the Regulation Service and Operating Reserve clearing prices. Load,
including Load taking service under bilateral contracts, benefit from the scheduling
of Demand Side Resources when it reduces Ancillary Services prices.

19. The load ratio share methodology is the fundamental mechanism for allocating

costs among Loads in the NYISO-administered markets. It is based on the premise
that all Loads benefit from inextricably interrelated market, operational, and
reliability services, including the results of the various demand reduction programs,
and therefore should bear a proportionate burden of the cost of those programs.
Exempting bilateral energy purchasers from the costs of demand response
programs would arbitrarily and unfairly shift these costs to the remaining Loads
that benefit from them. This cost shifting would introduce artificial factors that
favor one manner of participation over another, distorting market economics.

20. This concludes my affidavit.