Subcontract Report

NREL/SR-550-44508

January 2009

Generation Interconnection 

Policies and Wind Power: A 

Discussion of Issues, Problems, 

and Potential Solutions

K. Porter, S. Fink, C. Mudd, and J. DeCesaro

Exeter Associates, Inc.

Columbia, Maryland
National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393

303-275-3000 • www.nrel.gov

NREL is a national laboratory of the U.S. Department of Energy

Office of Energy Efficiency and Renewable Energy

Operated by the Alliance for Sustainable Energy, LLC

Contract No. DE-AC36-08-GO28308

Subcontract Report

NREL/SR-550-44508

January 2009

Generation Interconnection 

Policies and Wind Power: A 

Discussion of Issues, Problems, 

and Potential Solutions

K. Porter, S. Fink, C. Mudd, and J. DeCesaro

Exeter Associates, Inc.

Columbia, Maryland

NREL Technical Monitor: D. Corbus

Prepared under Subcontract No. LAM-8-77548-01
NOTICE

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iii

Acknowledgments

The National Renewable Energy Laboratory’s Wind Technologies Program funded the research 

that went into this project. The authors thank Brian Parsons and David Corbus of the National 

Renewable Energy Laboratory for supporting this work. 

We also thank Lynn Coles of the National Renewable Energy Laboratory; Mark Bolinger and 

Ryan Wiser of the Ernest Orlando Lawrence Berkeley National Laboratory; Eric Laverty of the 

Midwest ISO; Natalie McIntire, a consultant to Wind on the Wires and the American Wind 

Energy Association; Brendan Kirby, a consultant to the National Renewable Energy Laboratory; 

and Matt Schuerger of Energy Systems Consulting LLC for their review comments. The authors 

also thank Mr. Laverty of the Midwest ISO, Dottie Roark of ERCOT, Ed Weber of the Western 

Area Power Administration, Monica Gonzalez of ISO New England, Sean Egusa of the 

Bonneville Power Administration, and Ken Mancini of PJM for providing review comments on 

the appendix. Finally, the authors thank Bruce Green of the National Renewable Energy 

Laboratory for his editorial assistance.
iv

TABLE OF CONTENTS

I. Introduction..........................................................................................................................1

PAGE

II. Basics of Large-Scale Generator Interconnection ...............................................................2

A. Feasibility Study...........................................................................................................5

B. Interconnection System Impact Study..........................................................................6

C. Interconnection Facilities Study...................................................................................6

D. Large Generator Interconnection Agreement...............................................................7

E. Orders 661 and 661-A: Interconnection for Wind Energy.........................................13

III. Generator Interconnection Requests in the Queues...........................................................16

IV. Factors Contributing to the Surge in Interconnection Requests ........................................24

V. Interconnection Queue Reform Initiatives.........................................................................27

VI. Potential Solutions.............................................................................................................36

VII. Summary............................................................................................................................42

LIST OF TABLES

1 Summary of Queue Procedures versus Order 2003.......................................................... 11

PAGE

2 Status of Queues as of July 2008, 2000 – 2007 by Number of Requests ........................ 23

3 Status of Queues as of July 2008, 2000 – 2007 by MW of Capacity ............................... 23

4 Legislative History of the Production Tax Credit............................................................. 25

5 RTO and ISO Generation Queue Reform Proposals (as of December 2008)................... 33
v

LIST OF FIGURES

1 FERC Order 2003 Timeline for Basic Interconnection Studies..........................................4

PAGE

2 Flow Chart of the Large Generating Facility Interconnection Process................................8

3 Annual Interconnection Requests, 2004 - 2007.................................................................16

4 MW of Annual Interconnection Requests, 2006 and 2007................................................17

5 Generator Interconnection Requests by Fuel Source, 2007...............................................18

6 Capacity of Interconnection Requests Compared to Installed Capacity 

and Electric Demand..........................................................................................................19

7 Capacity of Wind Projects in Interconnection Queues, 2006 and 2007 ............................20

8 Number of Interconnection Requests for 2008 through October 20, 2008........................21

9 Number of Interconnection Requests by Fuel Type for 2008 through 

October 20, 2008................................................................................................................21

10 Capacity of Interconnection Requests for 2008 through October 20, 2008 ......................22

11 Capacity of Interconnection Requests by Fuel Source for 2008 through

October 20, 2008................................................................................................................22

12 PTC and Wind Development.............................................................................................25

13 Wind Project Interconnection Requests.............................................................................26

14 Potential Estimated Deposits for a 100-MW Project by RTO or ISO...............................37
vi

APPENDICES

A. Bonneville Power Administration................................................................................... A-1

PAGE

B. California Independent System Operator.........................................................................B-1

C. Electric Reliability Council of Texas...............................................................................C-1

D. ISO New England ........................................................................................................... D-1

E. The Midwest Independent System Operator....................................................................E-1

F. New York Independent System Operator........................................................................F-1

G. PJM Interconnection ....................................................................................................... G-1

H. Southwest Power Pool .................................................................................................... H-1

I. Western Area Power Administration................................................................................I-1
1

I. Introduction

On July 24, 2003, the Federal Energy Regulatory Commission (FERC) issued Order 2003 

governing large generator interconnection procedures, defined as those encompassing generation 

facilities with a nameplate capacity of 20 MW or greater.1 Order 2003 directed transmission 

providers to file revised open access transmission tariffs (OATT) adding the standardized Large 

Generator Interconnection Procedures (LGIP) contained in the Order. The procedures and rules 

were subsequently reaffirmed and clarified under Orders 2003-A in March 2004, 2003-B in 

December 2004, and 2003-C in June 2005.2

Since the adoption of Order 2003, a large number of generator interconnection 

applications have been filed. From 2004 through 2007, the number of interconnection queue 

applications more than tripled amongst Bonneville Power Administration (BPA), the Western

Area Power Administration (WAPA), and RTOs and ISOs. As a result, generation 

interconnection queues across the country are clogged with proposed generating projects, which 

in turn has increased processing time for interconnection studies and contributed to significant 

delays for generating projects. Consequently, both transmission providers and generators are 

 FERC-jurisdictional transmission providers (i.e., an 

entity that engages in the generation or transmission of energy at the wholesale level) can either 

follow the standard interconnection agreement and procedures set out in Order 2003, or file 

variances as long as they are equal to or superior to the standard interconnection agreement 

FERC included in Order 2003. FERC gave greater flexibility to regional transmission 

organizations (RTOs) and independent system operators (ISOs) in complying with Order 2003, 

stating that as independent entities, RTOs and ISOs will be less likely to discriminate against 

other market participants.

FERC issued Order 2003 out of concern that the interconnection process at the time was 

characterized by delays and a lack of standardization and therefore was discouraging generators 

from participating in the electricity market. FERC determined that such delays and lack of 

standardization gave a competitive advantage to utilities that owned both transmission and 

generation facilities and was therefore inconsistent with FERC Order 888, which required 

transmission providers to offer open access to transmission facilities. FERC determined that a 

single set of interconnection procedures and agreements was necessary. FERC’s intent was to 

reduce the opportunities for undue discrimination and accelerate the development of new 

generation, while maintaining reliability and ensuring that rates are just and reasonable.

 1 FERC has a related policy governing small generator interconnection procedures for generators less than 20 MW. 

This report is primarily focused on interconnection policies for large generators over 20 MW. Standardization of 

Small Generator Interconnection Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ¶ 31,180, 

order on reh’g, Order No. 2006-A, FERC Stats. & Regs. ¶ 31,196 (2005), order granting clarification, Order No. 

2006-B, FERC Stats. & Regs. ¶ 31,221 (2006), appeal pending sub nom. Consol. Edison Co. of N.Y., Inc. v. FERC,

Nos. 06-1275, et al., (D.C. Cir. filed July 14, 2006). 2 Federal Energy Regulatory Commission, Standardization of Generator Interconnection Agreements and 

Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 (2003) (Order No. 

2003), order on reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ¶ 31,160 (2004) 

(Order No. 2003-A), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), FERC Stats. & Regs. ¶ 31,171 

(2005) (Order No. 2003-B). See also Notice Clarifying Compliance Procedures, 106 FERC ¶ 61,009 (2004), Order 

No. 2003-C, 111 FERC ¶ 61,401 (June 16, 2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 

475 F.3d 1277 (D.C. Cir. 2007).
2

frustrated. Transmission providers contend that the low entry requirements and the ease of 

suspending applications leads to a congested interconnection queue; generators complain about 

uncertain transmission cost allocation, delays in processing interconnection applications, 

potential lost market opportunities, and multiple studies and restudies, among other things. 

FERC held a technical conference on generator interconnection queues in December 

2007, and issued an order in March 2008 directing RTOs and ISOs to file a status report on their 

interconnection queues and queue reform initiatives (if any) by April 2008.3

 FERC focused on 

RTOs and ISOs as the size of the interconnection queue backlog seemed more prominent with 

them. The RTOs and ISOs were directed to file status reports on the size of their interconnection 

queue, the expected timetable for processing pending interconnection requests, the contributors 

to the queue backlog and whether clustering has helped or not helped minimize the clogging of 

the interconnection queue, and the status and schedule of any stakeholder processes on 

interconnection queue reform. It also directed the RTOs and ISOs to address the impacts of any 

potential reforms on smaller customers or other classes of interconnection customers.4

II. Basics of Large-Scale Generator Interconnection

 

All of the RTOs and ISOs filed their status reports with FERC in April 2008, and the 

RTOs and ISOs are following up the status reports with reform proposals. FERC approved the 

Midwest Independent Transmission System Operator’s (Midwest ISO) generator interconnection 

queue reform initiative in August 2008, and the California ISO’s (CAISO) reform proposal in 

September 2008. PJM Interconnection has already implemented several initial reforms and more 

are being discussed, and ISO New England filed its proposal with FERC in October 2008. 

Another generation interconnection queue reform proposal is being prepared by the Southwest 

Power Pool (SPP). The New York ISO is beginning its stakeholder process to consider possible 

interconnection queue reforms. 

This report describes the adoption and implementation of FERC Order 2003 and the 

reasons for the sharp rise in generation interconnection filings in recent years. After an 

introduction, Section II explains the basics of large-scale generator interconnection. Section III 

summarizes the number of generator interconnection filings at BPA, WAPA, and the RTOs and 

ISOs across the country. Section IV documents the reasons for these sharp increases in generator 

interconnection filings. Section V explains the interconnection queue reform initiatives that have 

been approved, proposed, or are under consideration. A review of potential solutions to the

problem of clogged generator interconnection queues is provided in Section VI. The report 

closes with a summary in Section VII.

The central feature of the generation interconnection procedure is the interconnection 

queue, effectively the waiting line for connecting to the grid. To date, the queue has been 

established on a first-come first-served basis, where the transmission provider assigns a 

sequential position to interconnection customers as they first file their interconnection request. 

The review of generator interconnection requests is conducted in phases with a series of studies, 

 3 Federal Energy Regulatory Commission, Interconnection Queuing Practices, Order on Technical Conference, 

122 FERC ¶ 61,252 (2008). 4 Federal Energy Regulatory Commission, Order on Technical Conference. 122 FERC ¶ 61,252, March 20, 2008.
3

each involving more detail and financial commitment. Each of the interconnection studies must 

take into account all other projects ahead of the proposed project in the generation 

interconnection queue. 

Generators can request energy-only interconnection, whereby the generator can connect 

to the transmission grid and deliver energy on an as-available basis. The interconnection study 

for an energy-only interconnection request consists of stability and steady state analysis that 

would identify the network upgrades necessary to interconnect the facility to the grid without 

negatively affecting reliability. Alternatively, a network interconnection request requires the 

transmission provider to assess what transmission network upgrades are needed in order to 

integrate the generating facility into the grid in the same manner as the transmission provider 

would integrate its own facilities to serve native load. Among other things, the studies for a 

network interconnection request include analysis of the transmission provider’s system at peak 

load and under a variety of severely stressed conditions to determine whether the aggregate of all 

generation in the area can be delivered to the aggregate of all load in the area when the 

interconnection customer’s generating facility is at full output, consistent with reliability criteria 

and procedures. Typically, a network interconnection is required to participate in capacity 

markets or to be counted as a capacity resource. For either energy-only or network 

interconnection service, transmission service must be arranged separately under the transmission 

provider’s open access transmission tariff.

Order 2003 stipulates that interconnection customers must submit separate requests for 

each project site, but are able to submit multiple requests for a single site, something done by 

interconnection customers that want to examine the feasibility of different points of 

interconnection for a single project. With each request, interconnection customers must also 

provide an expected in-service date. The projected in-service date must be the lesser of seven 

years, or the planning window for the regional or transmission provider’s expansion planning 

period. The expected in-service date can exceed this time period (up to a maximum of 10 years) 

if the interconnection customer can demonstrate that a large project will require a longer lead 

time, or can be even longer if the transmission provider and interconnection customer mutually 

agree to an extension.

Transmission providers assign queue positions according to the date and time that they 

receive a valid interconnection request. The position then determines the order in which the 

series of interconnection studies are conducted, and interconnection construction costs are 

allocated. A queue position can only be transferred to another interconnection customer with the 

transfer of the specific generating facility identified in the initial queue request. It is not possible 

to transfer the position in the queue to a new or materially different project. Interconnection 

customers may withdraw their requests at any time, but are liable for all costs incurred up to that 

point. Order 2003 also contains a provision for suspension of a project without loss of queue 

position. An interconnection customer can, at any time, request that a project be suspended for a 

cumulative period of up to three years. Suspension does not result in loss of queue position, and 

the transmission provider is still obligated to treat the project as a legitimate facility in studies 

conducted for other projects with lower queue positions.

The generator interconnection process leading up to a Large Generator Interconnection 

Agreement (LGIA) consists of three studies—feasibility study, system impact study, and 

interconnection facilities study—that are done sequentially while taking into account all other 
4

interconnection requests higher up in the queue. The three studies consist of increasingly more 

detailed engineering assessments that examine the technical considerations of interconnecting the 

particular project onto the grid at a certain point, while maintaining system balance and not 

exceeding the operating limits of the grid. Figure 1 provides an expected timeline for these three 

studies, outlined in more detail below.5

Figure 1 

FERC Order 2003 Timeline for Basic Interconnection Studies

Interconnection Request

Acknowledge request: 5 business days Scoping Meeting: 30 calendar days

Feasibility Study

File agreement: 30 calendar days

Conduct study: 45 calendar days following

Feasibility Study Results

Results meeting: 10 business days 

Provide System Impact Study Agreement: 3 business days following

System Impact Study

File agreement: 30 calendar days

Conduct study: 90 calendar days following

System Impact Study Results

Meeting: 10 business days

Provide Interconnection Facilities Study Agreement: 3 business days following

Interconnection Facilities Study

Plus/minus 20% of cost: 90 calendar days

Plus/minus 10% of cost: 180 calendar days

Order 2003 sets these study time requirements on a ‘best effort’ basis and hence, they are not 

considered legally binding deadlines. The timeline above includes the basic study phases only 

 5 Information on studies taken from: FERC, “Docket No. RM02-1-001; Order No. 2003-A, Appendix B, Standard 

Large Generator Interconnection Procedures (LGIP) including Standard Large Generator Interconnection 

Agreement (LGIA),” March 3, 2004.
5

and does not include any optional studies that may need to be performed. Also, additional time 

following the facilities study is required for negotiating and filing the LGIA.

A. Feasibility Study

The interconnection study process begins with an interconnection feasibility study 

agreement that specifies that the interconnection customer is responsible for study costs. The 

transmission provider and interconnection customer then conduct a scoping meeting after which 

the interconnection customer has five days to provide an attachment to the study agreement 

outlining the desired point(s) of interconnection and any alternative points. The transmission 

provider then has five days to sign and return the study agreement with a cost estimate for 

completing the study. Within 30 days, the interconnection customer executes the agreement and 

provides a $10,000 deposit, which then reserves the interconnection customer’s place in the 

interconnection queue. The initial feasibility study consists of a high-level look at whether the 

project is feasible at that particular point of entry into the grid. The feasibility study considers 

the base case with all generating facilities that are currently, or may be in the near future, 

connected to the grid.6

• All existing generating facilities; 

 This includes: 

• All proposed generating facilities interconnected to affected systems that may have an 

impact on the current request; 7

• All proposed generating facilities that have a pending higher queued interconnection 

request; and 

• All proposed generating facilities that do not have a queue position, but have executed an 

LGIA or requested that their LGIA be filed with FERC.8

FERC directs transmission providers to make an effort to complete the initial feasibility 

study within 45 days. The feasibility study results include a list of facilities needed to construct 

the interconnection and a non-binding good-faith estimate of the costs and time required to 

complete the construction. The transmission provider then meets with the interconnection 

customer within ten days to discuss the results. Sometimes the need for a re-study is identified 

due to some significant change in circumstances. This could include:

• A higher-queued project withdrawing from the queue;

• Substantial modifications being made to a higher-queued project; or

• A re-designation of the point of interconnection.

Regardless of the reason, if a re-study is required, the cost is borne by the interconnection 

customer. The need for a re-study, however, does not affect the interconnection customer’s 

queue position. 

 6 The base case refers to the base-case power flow, short circuit, and stability data for interconnecting that particular 

facility to that point on the existing grid.

7 Affected system refers to an electric system other than that particular transmission provider’s system that may be 

affected by the proposed interconnection.

8 For example, this may be the case if a generator already had an LGIA with a transmission provider prior to the 

implementation of Order 2003.
6

Order 2003 allows transmission providers to forego the initial feasibility study and move 

straight to the interconnection system impact study. In this case, the $10,000 deposit is applied to 

the cost of the interconnection system impact study. The interconnection customer must still 

meet all the conditions required to conduct an impact study (discussed below).

B. Interconnection System Impact Study

Following the meeting to discuss the feasibility study, and assuming a re-study is not 

required, the transmission provider has three days to provide a non-binding, good-faith cost and 

timeframe estimate for completing the interconnection system impact study. If the 

interconnection customer wishes to move forward with the project, it must execute the study 

agreement, provide documentation of project site control, and submit a $50,000 deposit to the 

transmission provider within 30 days. The system impact study is a more detailed version of the 

feasibility study and evaluates the impact of the proposed project on system reliability. The 

transmission provider is obliged to try to complete the study within 90 days and if unable to do 

so, it must notify the interconnection customer of an updated estimated completion date. Within 

ten days following completion of the system impact study, the parties will meet to discuss the 

results and determine if a re-study is required. Any required re-study must be done within 60 

days and does not result in a loss of queue position.

C. Interconnection Facilities Study

The final phase consists of the interconnection facilities study. The interconnection 

facilities study is a detailed study that identifies what equipment, engineering, procurement, and 

construction work will be required to connect the proposed generating project to the grid, 

including all transformer configurations, switchgear, meters, and any other equipment. The study 

includes estimates of the full interconnection cost and the time required to complete the 

construction. The transmission provider has three days to provide an interconnection facilities 

study agreement along with an estimate of the cost and time required to complete the 

interconnection facilities study. The interconnection customer then has 30 days to execute the 

agreement, provide the necessary technical data, and pay either $100,000 or the interconnection 

customer’s portion of the estimated monthly cost of conducting the interconnection facilities 

study, whichever is greater.

The transmission provider has 90 days to provide a draft report with a good faith cost 

estimate that is within 20 percent of the actual costs, or 180 days to provide a draft report with a 

good- faith cost estimate within 10 percent of actual costs. If the transmission provider cannot 

meet these deadlines, it must notify the interconnection customer of the delay and provide an 

updated timeframe and an explanation. Following receipt of the draft interconnection facilities 

study, the interconnection customer has 30 days to provide written comments that are to be 

included in the finalized facilities study. The transmission provider and interconnection customer 

will meet to discuss the results within 10 days to determine if a re-study is required. 

Following the successful conclusion of the studies and agreement on the results, the 

transmission provider may provide an engineering and procurement agreement. This is an 

optional agreement that allows the transmission provider to begin engineering and procurement

of any items that may have long acquisition lead-times. The interconnection customer can also 
7

request a series of optional interconnection studies. The optional studies are for informational 

purposes only, and the interconnection customer must bear the full study costs.

D. Large Generator Interconnection Agreement 

The result of the studies and negotiations is the LGIA. It includes a set of appendices that 

the interconnection customer must fill out containing the detailed technical specification for the 

project. The interconnection customer may also request negotiations with the transmission 

provider regarding any disputed provisions in the technical requirements. Unless an agreement is 

made to the contrary, an interconnection customer has 60 days to execute the LGIA, request 

filing of an unexecuted LGIA to FERC, or initiate the dispute resolution process at FERC. 

Otherwise, the interconnection customer will lose its position in the queue and its 

interconnection request is considered withdrawn. Following the filing of the final LGIA with 

FERC, the interconnection customer must provide evidence of continued site control or a nonrefundable $250,000 deposit that will later be applied towards the construction costs of any 

necessary facilities to interconnect the generation project. Additionally, the interconnection 

customer must demonstrate that it is meeting certain project milestones, which include one or 

more of the following:

• A fuel supply contract (if applicable);

• A cooling water supply contract (if applicable);

• Contracts for engineering, major equipment, or construction for the project;

• Contracts for the sale of energy or capacity from the project; and

• Application for an air, water, or land use permit.

Once all conditions are met and agreements in place, then the next step consists of 

gaining approval from FERC before proceeding with design, procurement, and construction of 

the facilities and upgrades agreed to in the LGIA.

Figure 2 provides a graphical representation of the large-scale generator interconnection 

process, as just described.
8

Source: FERC Order 2003, Appendix A. 

Figure 2

Flow Chart of the

Large Generating Facility Interconnection Process
9

Clustering

Order 2003 also contains provisions for giving transmission providers the option to study 

interconnection requests as a group, also known as “clustering.” Clustering must be implemented 

on the basis of queue position and within a fixed-time window based on pre-determined opening 

and closing dates. The start and end dates of the cluster window are of the transmission 

provider’s choosing, but the duration of the window is not to exceed 180 days. A transmission 

provider can then allocate the costs of the common network upgrades for the clustered projects in 

proportion to each project’s system impact, without regard to queue position. 

Cost Allocation

Order 2003 outlines how interconnection and grid reinforcement costs should be 

allocated, and the interconnection studies help assign cost responsibilities between transmission 

providers and generation developers, and among generation projects. Two types of construction 

costs are defined: direct connection facilities and network upgrades. Direct connection facilities 

consist of all equipment and construction required to connect the new generating facility to the 

first point of interconnection with the transmission grid. Network upgrades consist of equipment 

and construction required to reinforce the existing transmission system in order to accommodate 

the new generation project. Generators are responsible for the costs of all interconnection studies 

and the cost of all direct connection facilities between the generator and the transmission grid. 

Generators also pay for the up-front costs of network upgrades and new additions to the 

transmission network that are required because of generator interconnections. Over time, the 

project owners are reimbursed for the network upgrade costs by transmission providers, with 

interest, via credits against the costs of transmission service to the interconnecting generator or, 

if available, financial transmission rights (FTRs). The costs for constructing network upgrades is 

allocated according to queue position and hence, is paid initially by the first interconnection 

customer that requires them, unless the transmission provider elects to cover the costs itself. 

Transmission providers have the option of fully reimbursing generators for the network upgrade 

portion within five years from when the generating facility comes on-line, or until the total of the 

transmission credits equals the generator’s upfront payments plus interest. 

Order 2003 allows RTOs and ISOs, defined as “independent entities,” to propose 

alternative variations on the Order 2003 pro forma interconnection provisions. FERC stated that 

an RTO or ISO has “different operating characteristics depending on [its] size and location and is 

less likely to act in an unduly discriminatory manner than a Transmission Provider that is a 

market participant.”9

 As such, FERC’s “independent entity” standard allows RTOs and ISOs to 

propose variations to Order 2003 that are “just and reasonable and not unduly discriminatory and 

would accomplish the purposes of Order 2003.”10

RTOs and ISOs have used the independent entity variation to propose alternatives to the 

Order 2003 pro forma tariff on interconnection procedures and pricing of network upgrades. For 

example, the Midwest ISO allocates 50 percent of generator-related network upgrade costs 

directly to the generators, and 50 percent to load in the Midwest ISO. For transmission network 

upgrades above 345-kV needed to maintain reliability, the Midwest ISO allocates 20 percent of 

 9 FERC Order 2003, p. 827. 

10 Federal Energy Regulatory Commission, Interconnection Queuing Practices, Order on Technical Conference, 

122 FERC ¶ 61,252 (2008), p. 13, note 10.
10

the costs to all customers and 80 percent to beneficiaries as identified through modeling. For 

network upgrade costs over $100,000, SPP allocates one-third of the upgrade costs to all 

transmission customers in the SPP region and two-thirds are allocated to an affected zone on a 

megawatt-mile basis. More recently, the RTO's and ISO's queue reform proposals are also being 

filed under the independent entity standard variation. Table 1 on the next page compares the 

different RTO and ISO pre-reform procedures versus those prescribed in Order 2003.
11

 

 

Table 1

Summary of Queue Procedures versus Order 2003

 

Order 2003 PJM1 Midwest 

ISO2 NYISO ISO-NE SPP CAISO3 ERCOT

Interconnection 

Request Deposit $10,000 $10,000 $10,000 $10,000 $10,000 $10,000 $10,000 $1,000 to $5,000

Site Control/Deposit SC or 

$10,000 None SC or $10,000

SC or 

$10,000 SC or $10,000 SC or $10,000

SC or 

$10,000 None

Third Party Feasibility 

Study4 No rule Yes Yes Yes No No Yes No

Waive Feasibility Study Yes No Yes Yes No Yes Yes No

Feasibility Study 

Timeline 45 days 90 days 45 days 45 days 45 days 45 days 45 days 90 days

Cluster Studies Optional Conducts Optional Optional Optional Optional Optional Optional

System Impact Study 

Deposit $50,000 $50,000 $50,000 $50,000 $50,000 or estimated cost $50,000 $50,000 Based on project size

Permit Applications/

Site Control/Deposit Site Control Permits Site Control Site Control Site Control Site Control Site Control Site Control

System Impact Study 

Timeline 90 days 120 days 90 days 90 days 90 days 90 days 90 days Up to 210 days

1 Some of PJM’s generator interconnection reforms have been approved and implemented. 2 The Midwest ISO has a new FERC-approved generator interconnection system in place as of August 2008. 3 CAISO’s new generator interconnection process was approved by FERC in September 2008.

4 Some RTOs and ISOs hire their own consultants at times. Third party consultants refer to those hired by generation developers.
12

Table 1

Summary of Queue Procedures versus Order 2003 (continued)

Order 2003 PJM Midwest ISO NYISO ISO-NE SPP CAISO ERCOT

Interconnection 

Facilities Study Deposit

$100,000 or 

share of 

costs

$100,000 or 

3-month 

costs

$100,000 or 

estimated 

monthly cost

$100,000 or 

estimated 

monthly cost

$100,000 or 

estimated 

monthly cost

$100,000 or 

estimated 

monthly cost

$100,000 or 

estimated 

monthly cost

Combined 

with SIS

Optional Sensitivity 

Analysis Study

Yes, $10,000 

deposit No Yes

Yes, 

estimated 

cost deposit

Yes, $10,000 

deposit No Yes No

Suspend Projects Up to 3 years Up to 3 years Up to 3 years

Up to 3 years 

but only 

after signing 

the LGIA5

Up to 3 years 

but only after 

signing the 

LGIA

Up to 3 years

Up to 3 years 

but only 

after signing 

the LGIA

No

Engineering & 

Procurement 

Agreement

Optional Required6 Optional Optional Optional Optional Optional No

Large Generator 

Interconnection 

Agreement Timeline

60 days to 

file 60 days 60 days to file

60 days to 

file 75 days 60 days to file

60 days to 

file 180 days

Large Generator 

Interconnection 

Agreement Deposit

$250,000 Estimated 

costs $250,000 $250,000 $250,000 $250,000 $250,000 None

5 Does not allow projects to enter suspended status during study phase. Once an LGIA is executed, construction activity can be suspended for up to 3 

years.

6 Customers must sign a construction agreement, but they have an option for self-building interconnection facilities.

 
13

E. Orders 661 and 661-A: Interconnection for Wind Energy

1. Order 661 

In Order No. 2003-A, FERC noted that the procedures and agreements laid out in Order 

2003 were based on the needs of traditional generation facilities, and that non-synchronous 

generators, such as wind plants, might benefit from a different approach. A blank Appendix G 

was added to the standard LGIA for the future adoption of requirements specific to nonsynchronous technologies.11

In a Notice of Proposed Rulemaking (NOPR) issued in 2004, FERC proposed technical 

standards for the interconnection of large wind generating plants to be included in Appendix G 

of the LGIA.

 

12

 Low-Voltage Ride-Through (LVRT) Standard. The NOPR required wind 

generators to stay connected to the grid for voltage drops of 15 percent of nominal 

network voltage levels; however, it is not required unless the system impact study 

shows that it is needed. As a result, a wind plant is only required to satisfy the 

LVRT standard if the transmission provider illustrates, through the system impact 

study, that such capability is necessary to ensure safety or reliability. The point of 

interconnection, rather than at the high side of the wind plant substation 

transformers, was designated as the point of measurement for the LVRT. 

 The NOPR attempted to recognize the unique characteristics of wind plants, 

specifically that they use induction generators, consisting of several small generators connected 

to a collector system, and do not respond to grid disturbances in the same manner as large 

conventional generators.

On June 2, 2005, FERC issued Order No. 661 requiring public utilities to add standard 

procedures and technical requirements for the interconnection of large wind generation units to 

their standard LGIPs and LGIAs in their OATTs.

The technical requirements for wind generation facilities outlined in the NOPR were 

adopted in Order No. 661. The requirements address low-voltage ride-through capability, 

supervisory control and data acquisition (SCADA) capability, and power factor design criteria, 

among others.

 Power Factor Design Criteria (Reactive Power). A power factor range of +/-0.95 

was adopted for large wind generating plants. The wind plant is only required to 

maintain the required power factor range if the transmission provider shows, 

through the system impact study, that this capability is required of the plant to 

ensure safety or reliability. The onus is on the transmission provider to show that 

reactive power capability is needed for each individual wind plant interconnection 

customer. If it is required to provide reactive power capability, the wind plant 

should be able to operate anywhere in the +/-0.95 power factor range. 

 11 FERC Order 2003, Appendix G, Requirements of Generators Relying on Newer Technologies. 12 Federal Energy Regulatory Commission, Interconnection for Wind Energy and Other Alternative Technologies, 

Notice of Proposed Rulemaking, 110 FERC ¶ 61,036 (2004) (NOPR).
14

 SCADA Capability. The SCADA requirement adopted under the Order requires 

the wind interconnection customer to provide SCADA capability with the specific 

SCADA information and control capability required to be agreed to by the wind 

plant interconnection customer and the transmission provider. Wind plants are 

only required to have the capability to receive instructions; transmission providers 

are not authorized to control a wind plant in any way. The requirement is flexible 

enough that the customer and the provider can negotiate the specific SCADA 

capability that meets the needs of the transmission system at the specific location 

of the wind plant. In addition, the parties have the flexibility to decide what 

information should be provided and what equipment should be installed at the 

site. 

 Self-Study of Interconnection Feasibility. The wind developer is permitted to 

satisfy the requirements of the interconnection request by providing a set of 

preliminary electrical design specifications depicting the wind plant as a single 

equivalent generator after which the plant may enter the queue and receive the 

base case data as is provided for all large generators in Order No. 2003. No more 

than six months following the submittal, the wind plant is required to submit 

completed detailed design specifications and other data needed to allow the 

transmission provider to complete its system impact study. 

The initial application for the LVRT, SCADA, and power factor design criteria 

requirements was for LGIAs signed on or after January 1, 2006. The procedure permitting the 

wind plant interconnection customer to complete the interconnection request with singlegenerator equivalent design specifications went into effect immediately after the Final Order was 

published.

2. Order 661-A

On December 12, 2005, FERC issued Order No. 661-A making changes to certain 

provisions included in Order No. 661. While no changes were made to the power factor 

provisions or the self-study of interconnection feasibility, significant changes were made to the 

LVRT standard. 

The North American Electric Reliability Corporation (NERC) and the American Wind 

Energy Association (AWEA) submitted joint recommendations for proposed changes to the 

LVRT standard, which were adopted by FERC. The changes also included a transition period 

that has since expired. The changes include the following:

 Wind plants (following the transition period) are required to ride through low 

voltage events down to a zero voltage level for “location specific” clearing times 

up to a maximum of nine cycles.13 If the fault on the transmission system remains 

after the clearing time, the wind plant is permitted to disconnect from the system.

 13 A cycle is equal to 1/60th of a second.
15

 LVRT capability is required for all new wind plant interconnections, not just 

those flagged by the system impact study. The point of measurement for the 

requirement is at the high side of the wind plant step-up transformer and no longer 

at the point of interconnection.

 Variations to the LVRT provisions are only permitted on an interconnection-wide 

basis. Limiting variations does not restrict the ability of any party to request a 

deviation in a specific non-conforming agreement filed with the FERC (as 

opposed to a variation built into a pro forma tariff).

3. RTO and ISO Compliance with Orders 661 and 661-A

In accordance with Order 661 and 661-A, RTOs and ISOs created separate attachments to 

their open access transmission tariffs regarding wind interconnection criteria. The Midwest ISO, 

SPP, PJM, ISO-NE, CAISO, and NYISO all follow Order 661-A for low-voltage ride-through 

requirements. They also follow the Order 661 rule for meeting power factor capability as only 

being required if so shown in the System Impact Study. The Midwest ISO, SPP, PJM, ISO-NE, 

and NYISO grant wind developers six months to provide detailed technical data following the 

interconnection request, though both SPP and PJM have had working group discussions 

examining this issue. The new CAISO generator interconnection procedures remove this sixmonth exemption for wind projects and require all generators to provide all detailed technical 

data along with their interconnection request.

The RTOs and ISOs differ in whether they regard a change of wind turbine type as a 

material change requiring a re-study. SPP and PJM both require a re-study. The Midwest ISO, 

ISO-NE, CAISO, and NYISO examine each on a case-by-case basis to determine whether it is a 

large enough variation to be considered a material change. A material change would lead to a restudy, while a non-material change would not.
16

III. Generator Interconnection Requests in the Queues

The number of generator interconnection requests received by the various RTOs and 

ISOs has ballooned in recent years, partially driven by state renewable portfolio standard (RPS) 

requirements that have led to a significant increase in interconnection requests for wind power 

projects. At the end of 2007, the Midwest ISO estimated that at the current rate and under the 

current system, they would succeed in completing the processing of the projects in their queue by 

about 2050.14

Figure 3

 For this report, data was compiled on the number of generation interconnection 

requests filed at the seven RTOs and ISOs, as well as at two power marketing administrations 

with high quality wind resources—BPA and WAPA. The number of generator interconnection 

requests received by the various RTOs started to increase dramatically in 2005. Figure 3 below 

shows the number of requests received annually for the years 2004 to 2007. As indicated, the 

number of interconnection requests has at least doubled for each RTO, and in many cases, more 

than tripled since 2004.

Annual Interconnection Requests, 2004 - 2007

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

 14 Midwest ISO, “Prepared Remarks of Clair J. Moeller, Vice President of Transmission Asset Management, 

Midwest Independent Transmission System Operator, Inc.,” FERC Docket No. AD08-2-000, December 11, 2007.
17

Caution should be exercised in interpreting the data as some interconnection customers 

may have several different interconnection points evaluated for the same project and must submit 

a separate request for each point of connection. Some of the requests are ultimately withdrawn, 

as project owners elect not to continue with the project at that site or encounter difficulties with 

procuring equipment or securing site control. Nevertheless, each request often requires at least 

the completion of an initial feasibility study. Figure 4 shows the amount of megawatts (MW) 

represented by the requests that were made in 2006 and 2007. The amount of capacity requested 

for interconnection more than doubled in the Midwest ISO and CAISO between 2006 and 2007, 

and significant increases were also seen in PJM and ERCOT.

Figure 4

MW of Annual Interconnection Requests, 2006 and 2007

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.
18

Figure 5 represents the gigawatts of capacity in the interconnection queues at the same 

transmission providers, by fuel source in 2007. Only projects active in the interconnection 

queue, but not placed in-service are included in Figure 5–suspended projects are not included. 

There were 225 gigawatts (GW) of wind capacity in the interconnection queue, more than twice 

as much as natural gas, the next largest fuel resource in the interconnection queue. Moreover, 64

percent of the wind capacity entered the interconnection queues in 2007.15

Figure 5

Generator Interconnection Requests by Fuel Source, 2007

Source: Ryan Wiser and Mark Bolinger. Annual Report on U.S. Wind Power Installation, Cost and Performance 

2007. U.S. Department of Energy, May 2008. http://eetd.lbl.gov/EA/EMP/reports/lbnl-275e.pdf. (Accessed 

September 5, 2008). Based on data compiled by Exeter Associates, Inc.

 15 Ryan Wiser and Mark Bolinger, Annual Report on U.S. Wind Power Installation, Cost and Performance 2007. 

U.S. Department of Energy, May 2008. http://eetd.lbl.gov/EA/EMP/reports/lbnl-275e.pdf. (Accessed September 5, 

2008).
19

Figure 6 presents the capacity of interconnection requests through 2007 by ISO or RTO 

and BPA and WAPA. For CAISO, ERCOT, and WAPA, the capacity of interconnection 

requests is more than the total installed generating capacity and, in CAISO’s and ERCOT’s case, 

peak electricity demand as well.

Figure 6

Capacity of Interconnection Requests Compared to

Installed Capacity and Electric Demand

 Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

 

 
20

Figure 7 below shows the cumulative capacity of wind power projects in the 

interconnection queues at the end of 2007. This graph does not include projects that have been 

suspended or withdrawn.

 

Figure 7

Capacity of Wind Projects in Interconnection Queues, 2006 and 2007

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

Note: ERCOT does not maintain a ‘queue,’ therefore, project-specific cumulative data is not available; the 

2006 ERCOT figure is an estimate only. 

The rapid pace for generator interconnection requests has continued for the first 10 

months of 2008. As indicated in Figure 8, the nation’s RTOs, ISOs, BPA, and WAPA have 

received 742 interconnection requests in 2008 through October 20, 2008. During that period, the 

Midwest ISO has received the most interconnection requests, followed by PJM, CAISO, and 

then SPP and BPA. Of the Midwest ISO’s 169 interconnection requests for the first threequarters of 2008, all but 18 are from for wind. Wind accounts for the majority of the 

interconnection requests made in the first three-quarters of 2008, with 458, or 62 percent of all 

requests across all of the RTOs and ISOs (see Figure 9). This compares to 450 interconnection 

requests filed by wind generators for all of 2007. 
21

Figure 8

Number of Interconnection Requests for 2008 through October 20, 2008

 

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

Note: ERCOT 2008 specific project data not available; estimates only.

^ WAPA through to July 15, 2008.

Figure 9

Number of Interconnection Requests by Fuel Type for 2008 through October 20, 

2008

 

 Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

Note: ERCOT 2008 specific project breakdown not available; includes estimates only.
22

The 742 interconnection requests amount to almost 160 GW, with wind accounting for 56

percent of the total capacity. As indicated in Figure 10, PJM has received interconnection 

requests for the most total capacity, followed by SPP, the Midwest ISO, and CAISO. For wind, 

SPP has the most capacity of wind interconnection requests, followed by the Midwest ISO, 

ERCOT, and PJM. Note that the CAISO has received a significant amount of solar capacity 

requesting interconnection. By fuel type, wind has more than twice the capacity in 

interconnection requests as natural gas, as indicated in Figure 11.

Figure 10

Capacity of Interconnection Requests for 2008 through October 20, 2008

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

Note: ERCOT estimate only.

Figure 11

Capacity of Interconnection Requests by Fuel Source for 2008 through 

October 20, 2008

Source: Exeter Associates, Inc., based on data from BPA, WAPA, and the RTOs and ISOs.

Note: ERCOT estimate only.
23

Table 2 and 3 indicate the percentage of requests that are still in progress, have been 

withdrawn, or were in service from 2000 through 2007, measured by percentage of the number 

of generation interconnection requests and by percentage of the capacity of generator 

interconnection requests. Although a number of generator interconnection requests are still in 

progress, only a small percentage of total requests have been placed in-service.

Table 2

Status of Queues as of July 2008, 2000 – 2007 by Number of Requests 

 

ISO/RTO

Total Requests from 

2000 to 2004

Total Requests from

2005 to 2007

All requests from

2000 to 2007

Still in 

Progress 

Have Been 

Withdrawn

Gone 

Into 

Service

Still in 

Progress

Have Been 

Withdrawn

Gone 

Into 

Service

Still in 

Progress

Have Been 

Withdrawn

Gone 

Into 

Service

PJM 6% 65% 29% 51% 31% 18% 34% 44% 22%

Midwest 

ISO 27% 59% 14% 69% 30% 1% 50% 43% 7%

SPP 10% 74% 16% 58% 38% 4% 38% 53% 9%

CAISO 49% 37% 14% 67% 31% 2% 66% 30% 4%

ISO-NE 14% 65% 21% 57% 29% 14% 41% 43% 16%

NYISO 40% 56% 4% 68% 31% 1% 55% 43% 2%

Average 25% 59% 16% 62% 32% 7% 47% 43% 10%

 Source: Examination of generator interconnection queue information on RTO and ISO web sites.

 

 

Table 3

Status of Queues as of July 2008, 2000 – 2007 by MW of Capacity

ISO/RTO

Total Requests from 

2000 to 2004

Total Requests from

2005 to 2007

All requests from

2000 to 2007

Still in 

Progress 

Have Been 

Withdrawn

Gone 

Into 

Service

Still in 

Progress

Have Been 

Withdrawn

Gone 

Into 

Service

Still in 

Progress

Have Been 

Withdrawn

Gone 

Into 

Service

PJM 3% 90% 7% 60% 39% 1% 38% 58% 4%

Midwest 

ISO 18% 76% 6% 74% 25% < 1% 45% 52% 3%

SPP 11% 82% 7% 64% 35% 1% 35% 61% 4%

CAISO 52% 42% 6% 75% 24% < 1% 72% 27% 1%

ISO-NE 7% 91% 2% 82% 16% 2% 38% 60% 2%

NYISO 14% 84% 2% 52% 47% < 1% 29% 70% 1%

Average 18% 77% 5% 68% 31% 1% 42% 55% 3%

Source: Examination of generator interconnection queue information on RTO and ISO web sites.
24

IV. Factors Contributing to the Surge in Interconnection

Requests

A number of factors have led to the backlog in generation interconnection queues across 

the country. Chief among them are the relatively low requirements for filing an interconnection 

application, but other significant factors are policy initiatives such as the federal PTC and state 

renewable portfolio standards, transmission cost allocation policies, and unclear milestones in 

Order 2003. These issues are discussed in more detail below. 

Easy Entry and Exit Requirements: Order 2003 contains relatively low entry and exit 

requirements for filing a generator interconnection request. Entering the queue requires a 

$10,000 deposit, with an additional $10,000 required if site control cannot be demonstrated. A 

generator can also request that the processing of its interconnection application be suspended at 

any time, and for multiple times, for a total of up to three years without penalty, or any form of 

financial deposit other than paying for the interconnection study costs incurred to date. 

These minimum requirements, combined with the general market knowledge that there is 

insufficient transmission, and the uncertainties in estimating the costs of transmission network 

upgrades and what a generator’s cost allocation for upgrades may be, provides an incentive for 

generators to file interconnection requests early and often. As the queue becomes more 

congested, more generation interconnection requests may be filed as generators move to secure a 

position in the queue before it gets even longer. 

For these reasons, increasing the requirements (both financial and informational) for 

entering the interconnection queue and for suspending an interconnection request have been 

early targets of proposals to reform generator interconnection procedures. 

On-Again, Off-Again Availability of the Federal PTC: The production tax credit (PTC) 

was first introduced in the Energy Policy Act of 1992 and currently provides a tax credit of 

2.1¢/kWh over the first 10 years of operation for eligible technologies including wind. The PTC 

has been renewed five times in the last 16 years, but typically only for 1 to 2 years at a time. 

Indeed, the PTC completely lapsed prior to being renewed on three occasions. More recently, 

the PTC was renewed in 2006 and applies to all projects that are placed in service by the end of 

2008. In October 2008, Congress extended the deadline to the end of 2009. Table 4 below 

shows the history and duration of the PTC. 

The on-again, off-again availability of the PTC may affect the number of interconnection 

requests for wind projects that are suspended by creating economic uncertainty for developers 

trying to finance their projects. For example, the Midwest ISO said that of the 4,446 MW of 

wind interconnection requests processed since December of 2001, nearly 2,200 MW have been 

suspended.16

 16 Clair J. Moeller, Midwest ISO, prepared remarks before the Federal Energy Regulatory Commission’s Technical 

Conference on Interconnection Queuing Practices, December 11, 2007.

 The PTC lapsed twice during this period, in 2002 and 2004. 
25

Table 4

Legislative History of the Production Tax Credit

Legislation Date 

Enacted

PTC Eligibility 

Window (for wind)

PTC 

Lapse 

Duration

Effective Duration of 

PTC Window 

(considering lapses)

Section 1914, Energy Policy Act of 1992 

(P.L. 102-486) 1/24/92 1994-June 1999 n/a 80 months

Section 507, Ticket to Work and Work 

Incentive Improvement Act of 1999 (P.L. 106-

170)

12/19/99 July 1999-2001 6 months 24 months

Section 603, Job Creation and Worker 

Assistance Act (P.L. 107-147) 03/09/02 2002-2003 2 months 22 months

Section 313, The Working Families Tax Relief 

Act, (P.L. 108-311) 10/04/04 2004-2005 9 months 15 months

Section 1301, Energy Policy Act of 2005 

(P.L. 109-58) 08/08/05 2006-2007 None 24 months

Section 201, Tax Relief and Health Care Act of 

2006 (P.L. 109-432) 12/20/06 2008 None 12 months

Section 101, Emergency Economic 

Stabilization Act of 2008 (H.R. 1424) 10/3/08 2009 None 12 months

Source for Original Table: R. Wiser, M. Bolinger, G. Barbose, Using the Federal Production Tax Credit to Build a Durable 

Market for Wind Power in the United States, Ernest Orlando Lawrence Berkeley National Laboratory, November 2007. 

http://eetd.lbl.gov/EA/EMP/reports/63583.pdf. (Accessed June 10, 2008).

H.R. 1424, http://www.house.gov/apps/list/press/financialsvcs_dem/essabill.pdf. (Accessed October 27, 2008)

Wind project development shows a distinct pattern of on-again, off-again activity 

concurrent with the availability of the PTC. Figure 12 below illustrates this pattern.

Figure 12 

PTC and Wind Development

2008 Projected Data: American Wind Energy Association Press Release:

http://www.awea.org/newsroom/releases/Wind_Installations_Surpass_20K_MW_03Sept08.html

2007 data: R. Wiser & M. Bolinger, “Annual Report on U.S. Wind Power Installation, Costs, and Performance Trends: 2007,” 

U.S. Department of Energy, LBNL-275E, May 2008. http://eetd.lbl.gov/EA/EMP/reports/lbnl-275e.pdf

Source for original graph: R. Wiser, M. Bolinger, G. Barbose, “Using the Federal Production Tax Credit to Build a Durable 

Market for Wind Power in the United States,” Ernest Orlando Lawrence Berkeley National Laboratory, November 2007.
26

The number of interconnection requests received by the various RTOs and ISOs also 

echoes this pattern, with lulls in activity in 2002 and 2004 when the PTC lapsed temporarily (see 

Figure 13). The number of interconnection requests for wind surged beginning in 2005 and 

continued through 2006 and 2007 when the PTC was extended through the end of 2008. 

Congress recently extended the PTC through 2009.

 

Figure 13

Wind Project Interconnection Requests

Source: Exeter Associates, Inc., based on data from BPA, ERCOT, WAPA, and the RTOs and ISOs.

Note: ERCOT 2008 project-specific data not available; includes estimate of 20 new wind projects.

Transmission Cost Uncertainties: The ease of entry and exit compounds existing 

uncertainties regarding transmission network upgrade costs that may be necessary for a generator 

to interconnect. The costs for a generator to interconnect are not specified until an application is 

submitted and the interconnection studies are performed. Order 2003’s pricing policy effectively 

assigns the costs of a transmission network upgrade, which may be quite significant, to the first 

generator whose project requires upgrades. 

As a result, generators may file multiple interconnection requests for a single project to 

determine the lowest cost for interconnection, sometimes termed “upgrade shopping.” Should 

the feasibility study or system impact study come back unfavorably, a generator may drop out of 

the queue. That forces restudies for all the projects lower in the queue, adding to time and costs. 

The suspension of a project in the interconnection queue also leads to increased uncertainty for 

projects lower in the queue and increased processing time and costs for the transmission 

provider. Lower queued projects may have to pay the transmission network upgrade costs if the 

suspended project does not proceed. 

Policy and Regulatory Initiatives: Different policy initiatives and market forces are 

affecting the type of generating project that is entering the interconnection queue. Of the 28 

states and the District of Columbia that have implemented renewable portfolio standards, more 
27

than half of them (15) have been enacted since FERC adopted Order 2003. In addition, sixteen 

states with existing RPS policies have amended those policies since the issuance of Order 2003, 

with most of these states increasing the level of the RPS requirements. All told, 61 GW of 

renewable energy may be needed to meet state RPS requirements by 2025.17 Increasing concern 

by regulators and policymakers over climate change is also changing the composition of

generators entering the interconnection queue. Twenty-eight states have enacted or have joined 

regional initiatives to combat climate change.18

Unclear Milestones in Order 2003: Stakeholders have contended that Order 2003 is not 

clear on some aspects, such as what evidence is required of project developers to demonstrate 

site control, or what is considered a material modification to an interconnection application that 

justifies the loss of the position in the queue. One example is whether a change in wind turbines 

is a material modification that results in the loss of a queue position. SPP, for example, does not 

consider a change in wind turbines as material but does require a restudy. Substituting different 

wind turbines has apparently been relatively common, as wind developers enter the queue 

planning to purchase one type of turbine, and then determine that the turbine is unavailable or 

that the turbine will require substantial reactive compensation to meet FERC Order 661-A 

requirements.

 

Interaction between Interconnection Queues and Transmission Planning: Underinvestment in new backbone transmission facilities and the surge of applications by generators 

wishing to interconnect has complicated the processing of interconnection applications. What 

may originally be thought of as a straightforward generator interconnection request may turn out 

to be not so simple if large-scale network upgrades need to be made to reliably interconnect the 

new generation facility. This is particularly true in transmission-constrained areas. Furthermore, 

these studies can take time to prepare and evaluate and will, by necessity, impact the generator 

interconnection applications in the queue that follow the one being studied. Market knowledge 

of these issues is a contributing factor to multiple interconnection requests for the same project, 

i.e., “upgrade shopping,” in an attempt to minimize the possibility of incurring and having to pay 

for large transmission network upgrades that may doom a project’s economics. 

19

V. Interconnection Queue Reform Initiatives

All of the nation’s RTOs and ISOs have submitted, or are in the process of developing, 

queue reform proposals in response to FERC’s March 20, 2008, order.20 FERC conditionally 

granted the Midwest ISO’s queue reform proposal in August 2008. In addition, BPA developed 

and received FERC approval for an open season whereby generators and load-serving entities 

signed agreements and placed deposits for BPA to offer existing transmission capacity (if 

available), or to develop new transmission if BPA can do so under its embedded costs and be in 

compliance with the National Environmental Policy Act.21 In addition, CAISO filed a queue 

reform proposal before FERC in July 2008 that was approved in September 2008. ISO New 

England filed its queue reform proposal with FERC in October 2008,22

 17 Ryan Wiser and Galen Barbose, Renewable Portfolio Standards in the United States: A Status Report with Data 

Through 2007, Lawrence Berkeley National Laboratory, April 2008.

and the Southwest Power 

18 U.S. Department of Energy Annual Energy Outlook 2008, June 2008, http://www.eia.doe.gov/oiaf/aeo/ 19 ISO/RTO Council, ISO/RTO Council White Paper on Interconnection Queue Management Process, January 

2008.
28

Pool expects to file its queue reform proposal by the end of 2008. NYISO is just beginning its 

stakeholder process considering queue reforms. 

These proposals are summarized below as of October 2008, but note that some of these 

proposals are still in the drafting phase and may evolve over time. A more complete summary of 

these initiatives is provided in the Appendices.

Bonneville Power Administration: BPA’s queue logjam involved interconnection 

requests for transmission service rather than for generation interconnection. As noted earlier, 

BPA relied on an open season as a means of sorting through its queue, and will offer open 

seasons on an annual basis. BPA’s open season requires all those with transmission 

interconnection requests to participate in the open season or lose their position in the 

transmission queue. Those who wish to stay in the transmission queue have to sign a precedent 

service agreement with BPA and to make a deposit equal to one year’s worth of transmission 

service. After the open season closes, BPA then determines what it can satisfy with existing 

transmission service. For the remaining requests, BPA performs a cluster study and determines 

what new transmission facilities may be needed to accommodate the requests, and at what cost. 

If BPA cannot build the transmission at its embedded cost, then it will need to use incremental 

rates, which requires a federal rate case and public hearings. 

BPA held its first open season in May 2008, and initially offered 316 agreements for 

14,464 MW of transmission service. The open season closed on June 16th, and security deposits 

were required on June 27th. At that time, BPA received 153 signed agreements from 28 

participants representing 6,410 MW. Of this, 4,176 MW was from wind. The signed agreements 

for transmission service differed by duration, with the average being about 13 years. BPA also 

received about $83 million in deposits.23

California ISO: CAISO is transitioning its interconnection process from a serial study 

(first-come, first-served) approach to a cluster approach. CAISO submitted its reform proposal 

filing to FERC on July 28, 2008,

24 and received approval on September 26, 2008.25

 20 Federal Energy Regulatory Commission, Interconnection Queuing Practices, Order on Technical Conference, 

122 FERC ¶ 61,252 (2008). 21 Embedded costs refers to the total costs of assets and ongoing charges to providing and maintaining a supply of 

energy or the transmission system. In BPA’s case, embedded costs would reference their current transmission rates 

and therefore does not require a rate increase to pay for transmission upgrades needed to accommodate the new 

project.

CAISO 

proposed three study groups as a transition strategy: the Serial Study Group, the Transition 

Cluster, and the Initial Generation Interconnection Process Reform (GIPR) Cluster. The Serial 

22 ISO New England, Joint Filing of Proposed Revisions to the Generator Interconnection Process and Forward 

Capacity Market Participation Provisions Set Forth in the ISO New England Inc. Transmission, Markets and 

Services Tariff, October 31, 2008, http://www.iso-ne.com/regulatory/ferc/filings/2008/oct/er09-____-000_10-8-

31_fcm_queue.pdf. (Accessed November 4, 2008). 23 Bonneville Power Administration, 2008 Network Open Season Results. July 7, 2008. 

http://www.transmission.bpa.gov/business/IssuesPolicySteeringCmttee/documents/2008_NOS_Final_PTSA_Result

s_07_07_2008.pdf. 24 California ISO, “California Independent System Operator Corporation Generation Interconnection Process 

Reform Tariff Amendment,” July 28, 2008.

25 Federal Energy Regulatory Commission, Order Conditionally Approving Tariff Amendment. 124 FERC ¶ 61,292, 

September 26, 2008. http://www.caiso.com/2051/20517cf513430.pdf (accessed October 29, 2008). 
29

Study group will use the existing CAISO serial study processes for generating projects that are 

further along in the interconnection queue. Specifically, this means generating projects that meet 

one or more of the following conditions: they have executed a system impact study agreement 

with an estimated completion of before May 31, 2008; they have an approved or pending power 

purchase agreement; or they are seeking interconnection to a transmission project that has 

received state or federal approval. 

Those that do not meet these requirements will be placed in the Transition Cluster and 

will have to submit a deposit of $250,000. The deposit will be refundable, minus study and 

administrative costs, should the proposed generator enter into an interconnection agreement with 

CAISO. In addition, interconnection customers will have to submit proof of site control; a newly 

signed interconnection process agreement; any missing technical data; and whether the project is 

a capacity or energy-only project. Interconnection customers that do not meet those 

requirements will be withdrawn from the CAISO queue. CAISO plans to suspend the study 

activities for those projects in the Transition Cluster until all studies in the Serial Study Group 

are completed, expected to be about July 2009. 

All interconnection requests that are received by CAISO after June 2, 2008, will be 

placed in the Initial GIPR Cluster study group and subject to a temporary suspension. CAISO’s 

LGIP tariff limits the cluster window to 180 days; however, CAISO requested and received a 

waiver from FERC to extend the window for the Initial GIPR Cluster from June 2, 2008 to July 

31, 2009, to coincide with the conclusion of the expected study period of the Transition Cluster. 

Once fully in place, CAISO will open two four-month clusters each year. During these 

windows, interconnection customers will submit an interconnection request with an application 

and $250,000 deposit, site control documents, expected in-service date, technical data, and 

deliverability status (energy only, or capacity and energy). Another $250,000 is required if site 

control cannot be demonstrated. The deposits become non-refundable 19 months after the 

interconnection application is filed, as the deposits are used to pay for the studies. Before the 

project is assigned cost responsibility for any necessary transmission network upgrades, the 

interconnection customer must post an additional deposit of 20 percent of the estimated cost 

responsibility or $500,000, whichever is greater. Once the cluster studies are completed, the 

interconnection customer must post financial security for 100 percent of the total cost 

responsibility of the project, or $500,000, whichever is greater. Partial refund of these last two 

sets of deposits are allowed if the interconnection customer could not secure a power purchase 

agreement or regulatory permits, or if the upgrade costs are at least 30 percent higher than first 

estimated, or if costs increased because CAISO changed the interconnection point.

Midwest ISO: In September 2007, the Midwest ISO formed the Interconnection Process 

Task Force, comprised of stakeholders, to identify solutions for reducing the waiting time for 

projects in the generator interconnection queue, and to increase the certainty and validity of the 

proposed projects. The reforms create a generation interconnection process that is based on 

milestones, with four key phases: Pre-Queue, Application Review, System Planning and 

Analysis, and Definitive Planning. 

The Pre-Queue phase is an opportunity for the Midwest ISO and the interconnection 

customer to interact and discuss the generation interconnection process, timeline, and 

expectations. The phase consists of meetings and public information sessions, as well as 
30

collecting application data prior to formally submitting an application. At the end of the phase, 

interconnection customers are required to submit a non-refundable $5,000 application fee, and 

proof of site control, or a $100,000 deposit in lieu of site control to achieve the milestone and 

move forward through the process. There is also an optional study that interconnection 

customers may request to see their cost obligation. 

The Application Review phase includes technical and non-technical aspects. Generator 

and project models and one-line diagrams are developed and a study deposit and documentation 

are submitted. The additional deposit is based on the size of the project and ranges from $10,000 

to $120,000. If a project withdraws before the next phase, any unused portion of the study 

deposit would be refunded. During this phase, Midwest ISO conducts a feasibility study to 

determine if the transmission network is “ready,” meaning it is able to accommodate the 

interconnection request without significant transmission network upgrades. A project that cannot 

be accommodated within the existing transmission system capacity margin may choose to 

continue with an optional study to estimate its direct facility interconnection and network 

upgrade costs in a non-binding process. 

If the transmission network can accommodate it, the project bypasses the system 

planning and analysis study and moves directly to the Definitive Planning phase. A project that 

does this is usually located in a relatively unconstrained area and needs minimal transmission 

network upgrades. Otherwise, the project moves on to the Planning and Analysis phase where a 

system impact study determines the upgrades necessary for interconnection. Midwest ISO will 

study the interconnection requests as groups, organized by region and electrically related 

projects. 

Next, a project proceeds to the Definitive Planning phase where the interconnection 

customer executes an interconnection agreement, and pays additional study deposits based on 

capacity size ranging from $40,000 to $520,000. Additionally, this phase includes a detailed 

stability model, a final point of interconnection, and recertification of site control. During the 

second part of the phase, the interconnection customer must provide security for the cost of the 

transmission network upgrades, an execution of a contract for the sale of energy or capacity, and 

proof that generating equipment has been ordered. Processing these requests may allow a project 

to move forward. Once in the second phase of the Definitive Planning phase, suspension of a 

project is only allowed in cases of force majeure, and even then the interconnection customer 

must put forward a deposit equal to the higher of the cost of the network upgrades or $5 million 

so that projects placed lower in the queue within the group are not negatively impacted by the 

suspension. 

The Midwest ISO filed their proposed queue reform tariff with FERC on June 26, 2008. 

On August 25, 2008, FERC issued an order conditionally accepting the reform filing.26 FERC 

largely accepted the proposed filing, requiring only minor modifications on a few issues and 

rejecting only one change.27

 26 FERC, “Order Conditionally Accepting Tariff Revisions Addressing Queue Reform,” Docket No. ER08-1169-

000, August 25, 2008.

27 FERC ruled that Midwest ISO had not provided sufficient evidence to justify the proposed change to how energyonly resource interconnections will be handled. The Midwest ISO was ordered to revisit this issue along with some 

other minor modifications and clarifications in a supplemental filing due within 30 days. 

 
31

Southwest Power Pool: SPP is in the midst of a stakeholder process on interconnection 

queue reform. Although still under development and subject to change, SPP’s proposal would 

also move to a milestone-based process, with interconnection customers having to meet five 

milestones before being interconnected. In addition, SPP would also sharply raise deposits.

Specifically, for the preliminary impact study, SPP would require a study deposit of 

$40,000 for proposed projects less than 100 MW, $60,000 for proposed projects less than 800 

MW, and $90,000 for proposed projects exceeding 800 MW. The unused portions of the study 

deposits would be refundable. A demonstration of site control would be required, with no 

option for paying a deposit in lieu of site control. A generation project’s proposed installed 

capacity must also stay relatively constant with the capacity studied in SPP’s preliminary impact 

study. The proposed project’s generating capacity must remain at a level that is no less than 10

percent of the final installed capacity, and no increases in generating capacity will be allowed.

For the next phase, the Definitive Impact Study, interconnection customers would have to 

provide a $150,000 study deposit; a definitive point of interconnection; the final plant capacity 

rating with no decreases allowed; and detailed study materials for power flow and stability 

studies. Interconnection customers also would have to provide one of the following: a power 

purchase agreement; a purchase order for generating equipment specific to the project; an 

application for an air permit (if applicable); and a security deposit of $2,000/MW, refundable at 

time of commercial operation or withdrawal. 

For the Facilities Study, SPP would require one of the following: a letter of credit or 

payment for estimated network upgrades, less the deposit for the Definitive Impact Study; a 

power purchase agreement; a purchase order for generating equipment specific to the proposed 

project; an application for an air permit (if applicable); or an executed contract for cooling water 

supply (if applicable).

After meeting the milestones, SPP and the interconnection customer would negotiate a 

LGIA, after which the interconnection customer must make a non-refundable payment of 

estimated network upgrade costs within 30 days. Suspending the LGIA would not stop this 

payment. Finally, suspending the LGIA requires $5 million, less the estimated cost of the 

network upgrades. 

SPP and SPP’s Regional State Committee are also working on new ways to allocate 

transmission costs in particular cases. SPP’s new “balanced portfolio” approach will assign the 

costs of economic upgrades for transmission lines rated 345 kV or higher SPP-wide, as long as 

the identified balanced portfolio plan has a benefit-to-cost ratio of better than one (for all zones 

within SPP). SPP’s Market and Operations Committee will recommend one balanced portfolio 

for SPP’s Board of Governors to evaluate. If the portfolio receives Board approval, it will be 

added to SPP’s transmission expansion plan. FERC approved SPP’s balanced portfolio filing in 

October 2008.28

Separately, SPP’s Regional State Committee has proposed a methodology for allocating 

transmission network upgrade costs for wind projects that are designated to serve network 

 28 Federal Energy Regulatory Commission, Order Accepting Tariff Revisions as Modified. 125 FERC ¶ 61,054, 

October 16, 2008. 
32

transmission customers in SPP.29

ISO New England: ISO-NE’s filed its queue reform initiative with FERC on October 31, 

2008.

 If approved, this new cost recovery approach would apply for 

wind capacity up to 20 percent of a load-serving entity’s summer peak demand. For the loadserving entity’s zone, transmission cost allocation is 1/3 postage stamp, 2/3 MW-mile. For the 

other zones, transmission cost allocation is 2/3 postage stamp, 1/3 direct assignment. 

Transmission additions or upgrades directly related to interconnecting a wind project selected as 

a designated network resource are limited by a safe harbor limit of $180,000 per MW of 

nameplate generating capacity that is applicable to all sources of generation, again assuming the 

load-serving entity is below the 20 percent peak demand limitation on wind energy purchases. If 

the load-serving entity is already at or above the 20 percent limitation, only a percentage of 

transmission costs equal to the wind project’s capacity accreditation factor (about 10 percent) 

would be eligible for SPP base funding, with the remainder being directly assigned, or 

participant funded.

30 ISO-NE recently launched a Forward Capacity Market (FCM) for soliciting capacity up 

to three years in advance of need, with the first auction held in February 2008 for delivery in 

2010/11. The initial auction highlighted the issues with backlogs in generator interconnection 

applications, as some generators noted they were unsure they could commit to a 2010/11 

timeframe because of where they were in the ISO-NE interconnection queue.

In addition to raising deposits for filing an interconnection request and for the feasibility 

study, the system impact study, and the facilities study, ISO-NE is proposing to create two new 

categories for the FCM. One, for conditional qualified capacity resources, would allow a lower 

queued project that has overlapping system impacts with a higher queued project to qualify for a 

forward capacity auction along with the higher queued project. Should the higher queued project 

clear in the forward capacity auction, the lower queued project cannot proceed. If, however, the 

higher queued project withdraws or fails to meet various milestones, then the lower queued 

project would proceed instead in the forward capacity auction.

ISO-NE is also proposing a new process for long-lead resources that have longer 

development cycles than the two-to-three years between the auction and required power delivery 

time. Essentially, it would allow a long-lead resource to qualify in a forward capacity auction as 

long as it follows a development schedule and meets certain financial milestones.

Table 5 provides a summary of the different RTO and ISO queue reform initiatives. 

Some RTOs and ISOs are still deliberating over their interconnection queue reform initiatives; 

therefore, some of the information in Table 5 is subject to change.

 29 “SPP Expected to Vote on Postage-Stamp Rate Design for Economic Upgrades, Says CEO,” Inside FERC, July 

7, 2008, p. 3.

30 ISO New England, Joint Filing of Proposed Revisions to the Generator Interconnection Process and Forward 

Capacity Market Participation Provisions Set Forth in the ISO New England Inc. Transmission, Markets and 

Services Tariff, October 31, 2008. http://www.iso-ne.com/regulatory/ferc/filings/2008/oct/er09-____-000_10-8-

31_fcm_queue.pdf (accessed November 4, 2008).
33

Table 5

RTO and ISO Generation Queue Reform Proposals (as of December 2008)

 

PJM1 Midwest ISO2 ISO-NE NYISO3 SPP4 CAISO5

Status

Under Discussion, 

Some Approved by 

FERC

Approved by FERC Filed at FERC in 

October 2008 Under Discussion Under Discussion Approved by FERC

New Initial 

Interconnection 

Request Deposit

1st month $10,000

2nd month $20,000

3rd month $30,0006

$5,0007/

$10,000-$120,0008 $50,000 TBD

FS:8 $10,000

PIS: < 100 MW -

$40,000

100-800 MW -

$60,000

≥ 800 MW -

$90,000

$250,000

New Site Control 

and/or Feasibility 

Study Deposit 

Requirements

1st month $100/MW

2nd month $150/MW

3rd month $200/MW

SC or $100,000 SC required plus 100% 

of estimated FS costs TBD FS: nonePIS: SC SC or $250,000

Data Requirement 

Changes No No No TBD

FS: none

PIS: all data due, 

including from 

wind developers

Wind developers 

no longer have 

60 days

Feasibility Study 

Timeline Change No 10 days No TBD FS: noPIS: 150 days

Phase I – 270 

days

Cluster Studies Conducts Still Optional Still Optional TBD Still Optional Now Conducts
34

Table 5

RTO and ISO Generation Queue Reform Proposals (as of December 2008, continued)

PJM Midwest ISO ISO-NE NYISO SPP CAISO

New System Impact 

Study Deposit

Several options still 

under discussion. 

Option include:

1. $20,000 plus 

$100/MW, Max. 

$120,000

2. $30,000 plus 

$300/MW, Max. 

$300,000.

No deposit, all 

funds for FS and SIS 

collected upfront 

during FS stage.

Three options:

1. 100% est. study cost 

or $250,000

2. 100% est. study cost 

or $50,000 plus all 

permits.

3. 100% est. study cost 

or $50,000 plus at-risk 

expenditures equal to 

amount in (1.)

TBD

< 75 MW - 75,000

≥ 75 MW -

$150,000

Plus meet 

milestones.

No deposit, all 

funds for FS and 

SIS collected 

upfront in Phase 

1.

System Impact Study 

Timeline Changes No 1 year No TBD 120 days Phase II – TBD, 1 year

New Interconnection 

Facilities Study 

Deposit

Still under discussion, 

considering moving 

to milestone based.

$40,000 - $520,000

Three options:

1. 25% est. study cost 

or $250,000

2. $100,000 or est. 

monthly share of costs 

plus all permits.

3. $100,000 or est. 

study cost plus at-risk 

expenditures equal to 

amount in (1.)

TBD

Letter of credit or 

payment of full 

estimated cost of 

network upgrades.

Plus must meet 

milestones.

Within 180 days 

of Phase II 

completion 

$500,000 or 

100% of 

estimated costs

Suspend Projects 

Changes

Up to 3 years, but 

only after signing a 

Construction Service 

Agreement.

Only Force Majeure No TBD

Up to 18 months 

only after signing 

the LGIA

Up to 3 years 

but only after 

signing the LGIA
35

Table 5

RTO and ISO Generation Queue Reform Proposals (as of December 2008, continued)

PJM Midwest ISO1 ISO-NE NYISO SPP CAISO

New Large Generator 

Interconnection 

Agreement Deposit

Still under discussion. Based on project 

size

IFS can be waived and 

project fast-tracked. If 

waived deposit equal 

to estimated cost of 

engineering studies 

plus all permits plus 

commit to 

construction 

expenditure schedule.

If IFS conducted, 

deposit is 20% of 

estimated construction 

costs, plus commit to 

schedule for 

expenditures and 

permit milestones.

TBD

Letter, credit, or 

payment was due 

at IFS deposit 

stage. This 

payment is 

refunded if LGIA is 

not signed.

100% of 

estimated costs.

1 PJM Tariff changes regarding Feasibility and Interconnection Request deposits have been approved. Other changes are still in progress. 2 FERC approved the Midwest ISO’s Queue Reform Proposal on August 25, 2008 and the new study process will be implemented sometime around November 

2008. 3 The NYISO just began a stakeholder process on generation interconnection queue reform. 4 SPP has proposed moving to a three-queue system based on project readiness milestones. One queue for customers opting to do an optional Feasibility Study, 

one for customers opting to go directly to a Preliminary Impact Study, and then one queue for customers that are ready and meet the milestones for entering 

the Definitive Planning phase. 5 CAISO received approval on September 26, 2008. The new study process is organized according to Phase I and Phase II portions. 6 All deposits based on when project entered queue: in first month of 3-month cluster window, 2nd month, or 3rd month. 7 Pre-Queue Phase. 8

 Application review and feasibility study phase. Amount is scaled depending on the size of the proposed facility.

FS = Feasibility Study, PIS = Preliminary Impact Study; SIS = System Impact Study; IFS = Interconnection Facility Study
36

VI. Potential Solutions

A number of potential solutions have been offered in the reform proposals about

addressing clogged interconnection queues. Momentum has gathered around four particular 

options: (1) increasing the financial deposit requirements for receiving and maintaining a queue 

position; (2) eliminating the initial feasibility study or re-creating it as an optional screening 

phase; (3) greater limitations on project suspensions; and (4) moving away from a first-come, 

first-serve approach towards one that is more milestone-based. 

FERC itself lent some weight to these potential options in an Order issued on March 20, 

2008.31

Furthermore, for the LGIA, some generation queue reform proposals call for a sizable 

deposit for identified transmission upgrades, or for suspending a project, to cover the costs of 

any necessary restudies and to discourage developers from keeping questionable projects in the 

queue. Figure 14 presents potential generation interconnection deposit costs for a hypothetical 

100-MW plant for individual RTOs and ISOs, based on the RTO and ISO generation 

interconnection queue reform proposals. The estimated deposit costs do not include various 

deposits that may apply to specific projects, such as additional deposits that may be required if a 

 FERC acknowledged that increasing the amount of the deposits required at different 

stages of generator interconnection would “more accurately reflect the cost of the necessary 

studies” and could also increase the probability that only commercially viable projects enter the 

generator interconnection queue. FERC also noted that eliminating the feasibility study could 

decrease processing time and also reduce the number of generator interconnection requests, as 

generators not willing to pay the higher costs of the system impact study will not enter the 

generator interconnection queue in the first place. Finally, FERC said that there may be 

advantages in transitioning towards a “first-ready, first-served” approach instead of first-come, 

first-served. 

FERC also indicated, though, that increasing the strictness of required deposits and 

eliminating the feasibility study requires that other sources of information on available 

transmission capacity be available to narrow generator interconnection requests toward a single 

point of interconnection. FERC also stated that increasing the strictness of requirements might

place a greater burden on smaller customers. 

A number of the more common potential generation queue reform proposals are 

discussed below. 

Increasing Deposit Requirements for Entering and Staying in the Queue: A central 

theme among transmission providers is the relatively low financial requirements for entering and 

staying in the interconnection queue. Increasing these financial requirements is considered to be 

one way to prevent multiple requests on individual projects and future logjams. Based on the 

generation queue reform initiatives either filed to date or under discussion, it appears that a 

sizable increase in deposits for all elements of the interconnection process—feasibility study, 

system impact study, facilities study—can be expected. 

 31 Federal Energy Regulatory Commission, Interconnection Queuing Practices, Order on Technical Conference, 

122 FERC ¶ 61,252 (2008).
37

project does not have site control. The deposit estimates in Figure 14 also do not include 

deposits that may be required after signing an LGIA. Nevertheless, the data in Figure 14 is 

illustrative and indicates some variation among the different RTOs and ISOs. For instance, only 

two of the five RTOs and ISOs are keeping the feasibility study as a separate definitive study 

phase. In addition, the CAISO’s up-front deposit is larger than the other RTOs and ISOs, but it 

covers all of the study work up to the facility study phase.

Figure 14

Potential Estimated Deposits for a 100-MW Project by RTO or ISO

Notes: FS = Feasibility study

SIS = System impact study

IFS = Interconnection facility study

Chart reflects theoretical typical amounts of getting to completion of Facilities Study 

phase, may be lower if project developer meets certain milestones or fulfills certain 

conditions, e.g., evidence of at risk expenditures; permits acquired; contracts 

acquired; and for PJM, earlier applications. With many of the deposits, amounts not 

used are later refunded.

Total cost can also be higher e.g.,:

CAISO – FS stage, if no site control must pay additional $250,000.

ISO-NE – full estimated cost of study due for FS, assumed cost here is $100,000.

Midwest ISO - FS stage, if no site control must pay additional $100,000.

Project developers will still be required to pay a deposit upon signing an LGIA. The 

specific amounts are still being discussed by PJM; ISO-NE is 20% of estimated 

construction costs; the Midwest ISO is based on project size and estimated costs; and 

SPP and CAISO is 100% of estimated construction costs.

Reducing Project Suspension Provisions: Another general area of agreement is that the 

three-year allowance for interconnection customers to suspend processing on their 

interconnection applications for a project is too easy to obtain. The Midwest ISO’s queue reform 

initiative bars the use of project suspension except for circumstances of force majeure. SPP is 
38

tentatively proposing to retain the three-year suspension period, but requiring a deposit of 

$500,000 to pay for the costs of any necessary restudies. Still another possibility is to reduce the 

period of suspension from three years to one or two years, although that has not been included in 

any generation queue reform proposal as of yet. These proposals are likely an improvement over 

the current process of allowing generating projects relatively low-cost suspension while forcing 

other generating projects lower in the queue to pay for restudy costs. 

Making Progress through the Interconnection Queue Based on Milestones Instead of 

First-In, First-Out: Setting defined milestones can allow projects to leap frog over others in the 

queue that have not yet achieved the milestones. The Midwest ISO’s new generation 

interconnection procedures include use of such milestones and other RTOs and ISOs are 

considering use of them as well. Potential milestones include proof of site control, completion of 

data requirements, equipment ordering or purchasing, or a power purchase agreement. The 

specifics matter greatly, and complexities arise because of the different types of business models 

companies pursue (i.e., merchant plants that don’t rely on a power purchase agreement as 

compared to an independent power producer or a utility-owned plant) and different technologies. 

Therefore, some either/or alternatives will likely have to be provided with each milestone.32

Improving or Eliminating the Initial Feasibility Study: Some have suggested that 

dropping the initial feasibility study could save time, as the power flow modeling and short 

circuit analysis is duplicated in greater detail in the system impact study. In some cases, 

transmission providers allow developers to roll the feasibility study into the system impact study 

at their option, sometimes requiring a commitment from the developer to follow a pre-defined 

timeline for bringing projects into operation. The Midwest ISO opted to improve their feasibility 

 

Furthermore, generators may enter the interconnection queue in order to receive the necessary 

data from the interconnection studies (i.e., transmission network upgrade costs) as an input for 

bidding solicitations. The Midwest ISO’s optional study process is an example of a process 

designed to avoid this dilemma. 

Depending on the specifics, wind companies may face some difficulties if items such as 

data requirements are tightened. Under Order 661, the companion to Order 2003, wind 

companies have six months to provide detailed electrical design specifications after filing an 

interconnection application. As noted earlier, CAISO has eliminated this six-month window, 

and reducing or eliminating this window is apparently under discussion at some of the other 

RTOs and ISOs. Transmission providers have argued that the lack of detailed information 

makes it difficult to more precisely study proposed wind projects, but the changes in wind 

technology and wind turbine models can make it difficult for wind developers to pick a turbine 

and stay with it through the interconnection study process. Wind companies also state they need 

base case data from the RTO or ISO to determine what specific wind turbine they will need to 

meet the needs of the grid. In addition, potential provisions such as requiring early-stage 

documentation of equipment orders before proceeding through the interconnection queue may 

also prove difficult for wind companies. Given the near-term lack of wind turbines, unless wind 

companies have locked in a supply of wind turbines in advance, as some have done, it is difficult 

to guarantee the availability of a turbine too far in advance of construction.

 32 ISO/RTO Council, ISO/RTO Council White Paper on Interconnection Queue Management Process, January 

2008.
39

study process through providing greater levels of information up-front in their queue reform 

initiative. 

Open Season: Under this concept, a transmission provider holds an open season for new 

transmission capacity, whereby transmission customers and generators interested in purchasing 

new transmission capacity put in financial bids. Should enough bids be submitted and enough 

transmission capacity subscribed, new transmission can be constructed. The open season is 

modeled after the natural gas industry, which uses it to fund natural gas pipelines.

Both BPA and the Wyoming Infrastructure Authority (WIA) have implemented different 

versions of open seasons. BPA used an open season to whittle down a backlog in requests for 

BPA transmission service and to determine who would be interested in financing new 

transmission capacity. Along with WAPA and Trans-Elect, WIA is sponsoring the WyomingColorado Intertie 345-kV transmission project that could transfer 850 MW from Wyoming to 

Colorado. WIA held an open season earlier in 2008 to subscribe capacity to the line, and two 

wind companies committed to 585 MW. WIA is offering the remaining 265 MW through an 

open access transmission tariff and will hold a subsequent auction if demand exceeds the 265 

MW of available capacity. Besides BPA and WIA, the Midwest ISO is also considering holding 

an open season and may file a proposal with FERC in early 2009.33

As indicated, there has been some apparent success with using open seasons to whittle 

down the backlog in the queue and to locate subscribers for new transmission capacity. That 

said, it is not clear whether there will be sufficient interest for open seasons to always work, as 

transmission customers may not want to commit financing for transmission that may not be 

available for several years, particularly if there is a possibility that transmission may be financed 

through other cost recovery mechanisms. Indeed, an earlier BPA open season to support the 

McNary-John Day 500-kV transmission line was unsuccessful when several participants 

withdrew their applications.34

The use of clustering for interconnection studies has had mixed results to date. 

Clustering can reduce study timelines and increase efficiency by studying projects as a group and 

sizing transmission projects to meet the aggregate need. However, clustering can increase study 

timelines and costs if projects drop out, forcing the transmission provider to conduct what can be 

multiple restudies. In some cases, the cluster may span a large geographic region, adding to the 

complexity of the generator interconnection studies. One example is the Midwest ISO’s Group 5 

 

Improving Clustering Processes: Order 2003 allows transmission providers to study 

interconnection requests as a cluster, rather than each individual project serially. Several ISOs 

and RTOs use clustering − PJM groups projects through windows that close every four months 

(recently decreased from six months). NYISO groups projects by year, provided that the 

generation developer provides a reliability impact study that has been approved by NYISO’s 

Operating Committee and has met at least one regulatory milestone towards obtaining 

environmental permits or approvals. 

 33 Federal Energy Regulatory Commission, Order Conditionally Accepting Tariff Revisions Addressing Queue 

Reform. 124 FERC ¶61,183 (August 25, 2008). 34 Bonneville Power Administration, “McNary – John Day Open Season Information.” 

http://www.transmission.bpa.gov/PlanProj/Transmission_Projects/mcnary/mjdosi.cfm. (Accessed September 5, 

2008).
40

cluster that included 36 wind projects and one coal plant and covered an area of 200 miles by 

300 miles in Iowa and Minnesota. The group study began in May 2006, and the feasibility study 

was completed in September 2006. The initial system impact study was not completed until 

October 2007. The stability results were challenged and subsequently re-analyzed in early 2008. 

The Group 5 study was also hampered by about 40 higher-queued projects that collectively 

required about 80 transmission network upgrades prior to operation of the Group 5 projects. 

Some of the negative aspects of clustering can be mitigated by organizing project clusters 

around similar electrical characteristics, rather than by the time the applications were filed, and 

through requiring generators to post deposits equal to the upgrade costs once those costs are 

determined. NYISO requires generators to post security equal to the upgrade costs to obtain an 

interconnection agreement; alternatively, the generator can decline the cost allocation assignment 

and enter the next cluster.35

Transmission providers have also received FERC approval for one-time waivers of 

timetables, thereby allowing the use of clusters to help clear out their interconnection queues or 

to conduct more specialized studies. CAISO received a waiver from FERC to do a 33-month 

cluster study on over 4,000 MW of proposed wind projects in the Tehachapi region of California. 

CAISO received FERC approval for a waiver for interconnection requests received before June 

2, 2008, in order for CAISO to finish work on projects in more advanced stages of the 

interconnection studies.

 CAISO’s new generation queue process will also require generation 

developers to post security equal to the upgrade costs or $500,000, whichever is greater. 

36

Providing Priority to Certain Generating Projects in Interconnection Queue: Generators 

that successfully participate either in forward-capacity market auctions or in competitive 

resource solicitations may be impeded by other generating projects that have a higher position in 

the generator interconnection queue. Moreover, the capacity auctions or bidding solicitations 

may result in several projects entering the interconnection queue, only to withdraw or suspend 

their project if they are unsuccessful. Nevertheless, the transmission provider must at least begin 

processing each interconnection queue application without prejudice or pre-judging the 

feasibility of a request. Some have suggested allowing projects in state integrated resource plans 

or winning projects in bidding solicitations to “jump the queue.”

 

37

Transmission Cost Allocation: Who should pay for transmission network upgrades made 

necessary from interconnecting a generator or generators is a protracted and long-running debate. 

Although an oversimplification, the debate has generally occurred along the lines of those who 

believe that generators should pay all of the costs for upgrading the transmission network 

through interconnection (“participant funding”), and those that assert that upgrades benefit and 

improve the reliability of the network as a whole and, therefore, should be paid for by all 

 Moving generating projects 

forward in the queue because of winning a competitive bid or qualifying for a capacity market 

auction might be incorporated in a milestone-based interconnection queue process. 

 35 New York ISO, Status Report of the New York Independent System Operator, Inc., on Interconnection Queuing 

Issues, Docket AD08-02, April 21, 2008. 36 Federal Energy Regulatory Commission, California Independent System Operator, 118 FERC ¶ 61,226, order 

granting clarification, 120 FERC ¶ 61,180 (2007). 37 Remarks of The Honorable Ron Binz, Colorado Public Utilities Commission, FERC Technical Conference on 

Interconnection Queues, December 11, 2007.
41

transmission customers. Another approach is to assign costs to beneficiaries of the transmission 

upgrades, although these can be difficult to determine as the beneficiaries may change over time.

FERC tried to take the middle ground in Order 2003 by requiring generators to pay the 

upfront costs of transmission network upgrades, but then requiring transmission providers to 

reimburse generators over time with either transmission credits or financial transmission rights. 

As noted earlier, FERC allowed RTOs and ISOs to have “independent entity” variations from 

Order 2003. The Midwest ISO adopted a 50-50 policy of requiring generators to pay 50 percent

of the costs of generator-related transmission network upgrades, while SPP adopted a policy of 

allowing two-thirds of the costs of transmission network upgrades to be allocated to the zones 

directly benefitting from the upgrade (as determined through modeling) and one-third spread to 

all transmission customers in SPP.

FERC, the Midwest ISO, and SPP adopted these cost allocation mechanisms in order to 

ensure that generators consider grid location in filing interconnection applications, i.e., to incent 

generators to locate along less constrained transmission lines, as well as to provide a preference 

for more viable projects to move forward. Arguably, what may have happened is that generators, 

in an attempt to avoid or minimize incurring significant transmission network upgrade costs, 

choose to file multiple interconnection applications, which prompts restudies once those 

applications are suspended or withdrawn. 

A revisiting of region-specific transmission cost allocation methods may be forthcoming. 

The Midwest ISO is considering reopening a stakeholder process on its 50-50 methodology. 

Earlier, the International Transmission Company (ITC)/Michigan Electric Transmission 

Company and the American Transmission Company, both of whom operate inside the Midwest 

ISO, successfully petitioned FERC to revert to FERC Order 2003 generator reimbursement 

policy for generator interconnections located within their service territory that are designated as 

either a network resource or have a power purchase agreement of one year or longer.38 Since 

receiving FERC approval, ITC has received 13 new interconnection requests representing 4,500 

MW of capacity.39 ITC has since received approval from FERC to extend the Order 2003 

reimbursement policy to its ITC Midwestern transmission service area that encompasses parts of 

Iowa, Illinois, Minnesota, and Missouri.40

Other regions are pursuing more defined carve-outs from their cost allocation policies. 

As discussed previously, SPP’s ‘balanced portfolio’ approach has been approved by FERC and 

will act to spread transmission costs to all customers in SPP for a limited set of transmission 

portfolios that provide positive cost benefits to all customer zones in SPP.41

 38 Federal Energy Regulatory Commission, Int’l Transmission Co., 120 FERC ¶ 61,220 (2007), reh’g denied, 

123 FERC ¶ 61,065 (2008) and Am. Transmission Co., 120 FERC ¶ 61,221 (2007), reh’g denied, 123 FERC ¶ 

61,065 (2008) (American Transmission).

 Separately, SPP’s 

Regional State Committee is devising a cost allocation proposal for network transmission for 

designated wind resources. Finally, CAISO is implementing its location-constrained resource 

39 National Wind Coordinating Collaborative, Transmission Update, June 2008. 

http://www.nationalwind.org/pdf/NWCCTransmissionUpdateJune2008FINAL.pdf (accessed November 5, 2008). 40 Federal Energy Regulatory Commission, Order Accepting Tariff Sheets and Requiring Compliance. 124 FERC ¶ 

61,150 (August 7, 2008). 

41 Federal Energy Regulatory Commission. Order Accepting Tariff Revisions, as Modified. 125 FERC ¶ 61,054 

(October 16, 2008). 
42

interconnection policy that, for regions with high quality location-constrained resources, will 

spread the initial costs of large-scale transmission facilities to serve those resource areas across 

all load in CAISO (subject to a cap of 15 percent on the total net high-voltage transmission plant 

investment in CAISO and other conditions), then have generation projects pay a proportional 

share as they come on-line. 

VII. Summary 

Applications for generator interconnection to the grid have surged in recent years across 

the country. Wind projects have filed the most applications, spurred in large part by state 

renewable portfolio standards and the increasing competitiveness of wind power. The large 

increase in generator interconnection applications has been somewhat unexpected and has 

strained resources of transmission providers. As a result, processing time for generator 

interconnection applications has generally increased.

FERC held a technical conference on generator interconnection queues in December 

2007, and in March 2008 directed the nation’s RTOs and ISOs to file periodic status reports of 

their generator interconnection queues. FERC’s reasoning is that the issue with generator 

interconnection queues appears most pronounced at RTOs and ISOs. To date, FERC has 

approved the Midwest ISO’s and CAISO’s queue reform filings. Other RTOs and ISOs are 

preparing queue reform initiatives for filing later in 2008 or 2009. Common themes include a 

significant increase in required deposits for all or nearly all aspects of a generator 

interconnection (i.e., feasibility study, system impact study, facilities study, and the large 

generator interconnection agreement), transitioning from first-in, first-out to a milestone-based 

form of processing interconnection applications, reducing or eliminating the three-year period 

allowed for suspending projects, and requiring more information from generators.

There is broad support generally across all sectors of the electric power industry for 

reforming generator interconnection queues, but given the multiple number of business models 

for developing power projects, exactly how the reforms should be designed and implemented is 

complex. If converting to a milestone-based process, one strategy for addressing disparate 

business models is to provide multiple options for meeting a particular milestone. Separately, 

there also is relatively broad support for increasing deposits, although if not done carefully, it 

may inadvertently act as a deterrent to small projects or small companies. The Midwest ISO’s 

approach of prorating deposits to the size of the project may help in this regard.

Above all, it is important to link queue reform initiatives with more proactive 

transmission expansion planning and addition of new transmission. Although the increase in 

generator interconnection applications has contributed to clogged interconnection queues, lack of 

transmission capacity also cannot be overlooked. Without new transmission, the queue reform 

initiatives may simply lead to a faster rejection of the generator interconnection application. 

Therefore, coupling queue reform initiatives with a re-examination of transmission cost 

allocation policies, as the Midwest ISO is doing, or combining queue reform initiatives with new 

transmission initiatives such as network transmission pricing for wind and balanced portfolio 

transmission expansion, as with SPP, is likely necessary to succeed in alleviating clogged 

generator interconnection queues.
APPENDICES

A-1

A. BONNEVILLE POWER ADMINISTRATION

Similar to other regions, the Bonneville Power Administration (BPA) also has 

experienced a sharp rise in interconnect requests, the majority of which are from wind. In 2005, 

BPA received 11 generator interconnection requests worth about 2,300 MW, eight of which were 

for wind projects representing 900 MW. In 2006, BPA received 26 requests worth 4,700 MW 

and 25 of those were for wind projects representing 4,600 MW. In 2007, BPA received a total of 

31 generation interconnection requests, 29 of which were for wind power projects. At the end 

of 2007, BPA had 52 active requests in its queue for a total of 12,580 MW, with 47 of those 

requests being for wind power and representing 10,420 MW.1

Generator Interconnection

Queue Process 

BPA maintains two separate queues, one for generator interconnection and one for 

transmission service.

2

1. Interconnection Request – $10,000 deposit plus evidence of site control or an additional 

$10,000. The interconnection customer (IC) must identify if they are opting for network 

resource or energy only interconnection. Additionally, since BPA is a federal entity and 

therefore, subject to the National Environmental Policy Act (NEPA), an IC must execute 

an environmental study agreement so that BPA can perform the required NEPA 

environmental reviews.

BPA is a federal entity and therefore, does not fall under FERC jurisdiction. However, 

for FERC rules and regulations to apply at BPA connections to other transmission systems, BPA 

submits and receives approval of its OATT. BPA’s FERC-approved generator interconnection 

process very closely follows FERC Order 2003:

2. Feasibility Study – $10,000 deposit, BPA will endeavor to complete within 45 days.

3. System Impact Study – $50,000 deposit plus evidence of site control, completion in 

90 days.

4. Interconnection Facilities Study – deposit of $100,000 or the estimated monthly cost, 

whichever is greater. BPA will endeavor to complete within 90 days at 20 percent

accuracy or within 180 days if 10 percent accuracy as requested.

5. LGIA – $250,000 deposit plus continued evidence of site control plus one or more of the 

following (as applicable):

(1) Execution of a contract for the supply or transportation of fuel.

 1 All data taken from BPA’s published queue.

2 BPA, Attachment L: Standard Large Generator Interconnection Procedures from BPA Open Access Transmission 

Tariff, issued on October 3, 2008.
A-2

(2) Execution of a contract for the supply of cooling water.

(3) Execution of a contract for the engineering for, procurement of major equipment 

for, or construction of, the facility.

(4) Execution of a contract for the sale of electric energy of capacity from the facility.

(5) Application for an air, water, or land use permit.

Transmission Interconnection Network Open Season3

In an effort to expedite its queue process for transmission requests, BPA introduced its 

new cluster-based network open season procedure. BPA filed its tariff to implement the network 

open season process with FERC in March 2008, followed by some amendments in May 2008. 

FERC issued a declaratory order on June 13, 2008, accepting tariff revisions to implement the 

network open season procedures.4

Following the open season, BPA will study all valid transmission requests as a cluster to 

determine aggregate system impacts, facility requirements, and estimated construction costs. The 

open season cluster study approach is all-inclusive and replaces the previous individual 

feasibility, system impact, and facility studies. All study costs will be borne by BPA, which has 

set the following timeline: within eight months, BPA must decide if it can provide the requested 

service at embedded cost rates; and within 36 months of making the above determination, BPA 

must have completed the NEPA studies. If BPA determines it will miss these deadlines but that it 

BPA will conduct network open seasons at least annually for all long-term firm 

transmission service requests on its transmission network. Each customer must sign a Precedent 

Transmission Service Agreement (PTSA) to remain in the queue. The PTSA is modeled after 

similar precedent agreements use in the natural gas industry, where pipeline developers must 

subscribe sufficient demand in order for construction to go forward. Under BPA’s open season, 

customers subscribe in advance for transmission capacity (i.e., through a PTSA), allowing BPA 

to determine if there is sufficient demand for transmission in an area for them to proceed with 

construction. Customers must provide a security deposit along with the PTSA, equivalent to oneyear’s worth of the requested service. While point-to-point customers will generally submit a 

security deposit, network integration customers have the option to designate a new network 

resource through an attestation and exempt themselves from the security requirement. 

The PTSA obligates customers to take the transmission service if BPA fulfills the 

following conditions: (a) determines that it can provide the requested service at its embedded 

point-to-point and network integration rates, and (b) completes its required NEPA obligations 

and determine that the results are acceptable for building the required facilities. BPA is a federal 

agency and is required to conduct environmental reviews of all projects. 

 3 BPA, “2008 Network Open Season, Version 2,” April 17, 2008 and FERC Filing Docket No. NJ08-7:

http://www.transmission.bpa.gov/business/IssuesPolicySteeringCmttee/default.cfm?page=ipqm

4 FERC Docket No. NJ08-7-000, Declaratory Order, June 13, 2008: 

http://www.transmission.bpa.gov/business/IssuesPolicySteeringCmttee/documents/FERC_Order_Granting_NOS_T

ariff_Changes.pdf
A-3

can eventually complete the request, it will notify customers of the delay, and each customer will 

be given the option of terminating their PTSA. Once the studies are complete, BPA will arrange 

financing for planning, designing, and constructing the required transmission facilities. To 

recover costs, BPA will determine the benefits that will accrue to the integrated network from the 

new facilities and allocate that portion of costs to the network. The remaining costs will be 

recovered from the subscriptions made by the PTSA customers. 

After the network open season, BPA will restack the queue in queue order for 

transmission requests for which a PTSA was finalized, with all other requests being considered 

as withdrawn. Cluster studies will then be based on this restacked queue. However, after the 

network open season window closes, BPA will again accept transmission requests on an 

individual basis and continue processing requests in queue order, if transmission capacity 

becomes available. BPA will also continue to process transmission requests that have no or 

de minimus impacts on available transmission capacity as individual requests. Transmission 

requests still in the queue that have not been processed by the time of the next network open 

season window will be included in that network open season. BPA also has a provision for 

accepting clustered requests outside the network open season process. A group of customers can 

make a cluster study request at any time, but all study costs must be borne by the customers. 

Additionally, any customers that withdraw from the process will still be liable for their portion of 

study costs. Since the cluster study is all-inclusive and represents all previous studies from 

feasibility to facility, cluster study costs can be substantial. 

BPA’s first network open season ran from April 15 to May 15, 2008. All customers that 

previously requested transmission services or submitted a transmission request by May 15 

received a PTSA. Customers then had until June 16 to sign and return the PTSA and until 

June 27 to provide a security deposit in the form of a letter of credit, a deposit into an escrow 

account, or a cash deposit to BPA. Customers that chose not to execute the PTSA were removed 

from the BPA queue but may reapply at any time and will be eligible to participate in any 

subsequent network open season. The first network open season results were released on July 7, 

2008. A total of 153 completed PTSAs were executed for a total of 6,410 MW from 28 

participating customers who had posted a total of $83,238,144 worth of deposits.5 BPA notes in 

the results that 4,716 MW (74 percent) are associated with wind development with an average 

weighted transmission service request duration of 13.65 years. Independent power producers 

accounted for 100 requests worth 4,327 MW and utilities for 53 requests worth 2,083 MW. BPA 

also noted they had declined 153 requests totaling 7,299 MW because they did not meet the 2008 

NOS obligations. 

 5 Bonneville Power Authority, “2008 Network Open Season Results,” July 7, 2008. 
B-1

B. CALIFORNIA INDEPENDENT SYSTEM OPERATOR1

Compliance with FERC Order 2003

The California Independent System Operator’s (CAISO) Large Generator 

Interconnection Procedures (LGIP), established in compliance with FERC Order No. 2003, has a 

centralized interconnection study procedure through which each project is reviewed and 

analyzed serially for its impact on the regional transmission system. However, it took several 

years for CAISO’s tariff to come into compliance with Order 2003; FERC accepted the LGIP 

and LGIA in May 2006. 

One issue that initially complicated the process was the definition of a Regional 

Transmission Organization (RTO) and whether or not CAISO was to be considered as an RTO. 

Under Order 2003, non-independent transmission providers were limited to the use of the pro 

forma LGIP and LGIA as provided in the Order. However, FERC allows RTOs flexibility in 

structuring interconnection agreements and study practices, and in transmission cost allocation. 

Ultimately, CAISO and FERC resolved that CAISO was to be considered as an independent 

entity treated in the same manner as an RTO.2

Under the LGIP and LGIA tariffs, effective May 24, 2006, analytic activities are shared 

by CAISO and California’s PTOs. The centralized, serial study system analyzed the higher 

queued projects first, requiring that the analysis be largely completed prior to initiating the study 

of an “electrically related” project placed lower in the queue. This was true for each of the three 

studies: feasibility study, system impact study, and facilities study. The number of studies that 

could be underway at any particular time depended on the ability of analysts to be able to 

complete the studies in a reasonable time, based on the point of interconnection, the number of 

electrically-related projects with pending interconnection requests, the availability of 

transmission capacity, and the amount of restudy that was required if higher-queued projects 

withdrew. However, section 13.4 of CAISO Tariff Appendix U, Standard Large Generator 

Interconnection Procedures, does allow third party consultants to assist in performing studies. 

Once CAISO was recognized as an independent entity, CAISO revised its process to 

better meet FERC’s direction in Orders 2003, 2003-A, 2003-B, and 2003-C. On January 5, 2005, 

CAISO filed its LGIP in compliance with Orders 2003 and 2003-A. At the same time, CAISO 

also filed a LGIA in conjunction with the California Participating Transmission Owners (PTOs), 

San Diego Gas and Electric, Southern California Edison, and Pacific Gas and Electric. One 

month later, on February 5, CAISO issued an additional filing to FERC further modifying its 

LGIP to comply with Order 2003-B. Because of these filings, CAISO established a single 

interconnection queue and a single pro forma interconnection agreement and centralized study 

process for the entire CAISO service territory.

 1 The California ISO did not respond to requests to review this appendix. The information in this appendix is based 

on the authors’ understanding of the California ISO’s generator interconnection procedures. 

2 In a 2002 Order, Order Concerning Governance of the California Independent System Operator, 100 FERC 

¶61,059 at p 1-2 (2002), FERC determined that CAISO had failed to meet the “independence” status deemed 

necessary to be formally classified as an RTO. 
B-2

The interconnection customer (IC) can request that CAISO utilize a third party consultant to 

perform the interconnection study under the direction of CAISO if the study could not be 

completed within 120 days of signing the interconnection study agreement. The use of a third 

party consultant is limited to situations where CAISO finds that it will help accelerate the study 

process. 

CAISO is currently overwhelmed with interconnection requests and there is a long 

backlog of projects. Recognizing the need to revise the interconnection request procedures, 

FERC suggested that CAISO engage stakeholders in a process to reform to the LGIP and prepare 

a subsequent filing to revise the relevant sections of CAISO tariff. 

Status of the Queue

As of April 18, 2008, there were 265 active interconnection requests representing 

approximately 77,614 MW in the CAISO queue (Table B-1). By comparison, there were 173 

projects in the queue as of December 31, 2007 for approximately 57,686 MW. Thus, in the first 

four months of 2008, there was a 53 percent increase in the number of projects requesting 

interconnection studies. 

Table B-1

Current Size of the Interconnection Queue

# of projects # of projects

Active projects in the queue 265 77,614

Active renewable projects in the queue 183 48,114

Active projects in feasibility study stage 102 33,379

Active projects in system impact study stage 55 18,418

Active projects in facilities study stage 37 9,209

Active projects in LGIA negotiation stage 36 12,560

Projects not yet data adequate but have submitted 

interconnection request 35 4,048

Renewable projects not yet data adequate but that have 

submitted interconnection request 31 2,150

Source: Grant Rosenblaum, Senior Counsel of CAISO, Interconnection Status Report of the California Independent System 

Operator, submitted to FERC in Docket AD08-2-000, April 21, 2008, p. 2. 

Nearly 60 percent of all active projects are located in Southern California Edison’s (SCE) 

service territory. The large number of requests within the SCE territory has become the limiting 

factor for processing studies serially and moving projects along in the interconnection queue. 

Under a serial study approach, CAISO could process approximately 20 studies at any one time, 

taking approximately 6 months to completely study a project all the way through the facilities 

study analysis. This estimate is because there are five distinct electrically related geographic 

areas in the SCE territory and that four studies might be performed simultaneously for each area. 

Assuming that each study takes 6 months to complete, it would take approximately 3.3 years to 

complete all of the studies currently listed as active in the CAISO queue. 
B-3

Nearly 70 percent of the projects in the queue are renewable energy projects. 

Complicating matters further is that a great number of the proposed renewable energy project 

interconnection requests are located within the same geographic location, typically areas with 

significant wind resources. Three transmission corridors—Tehachapi, East of Lugo, and Devers 

Valley—account for nearly 40,000 MW of the proposed projects, more than 80 percent of the 

renewable projects in the queue, and more than half of all projects proposed. This large number 

of proposed renewable energy projects can be attributed in large part to the California renewable 

portfolio standard (RPS) that requires California’s investor-owned utilities, community choice 

aggregators, and electric service providers to have 20 percent renewable energy in their portfolio 

by 2010. 

Move to Clear the Serial Queue and Transition to Cluster Studies

This Generator Interconnection Process Reform (GIPR) process began in January 2008 

when CAISO published an issues paper and held the first of many stakeholder meetings. 

This process continued throughout the first half of 2008 and resulted in CAISO filing its final 

proposal with FERC on July 28, 2008.3 FERC approved this filing via letter order on September 

26, 2008.4

The TWRA is California’s largest wind resource area and is expected to generate at least 

4,500 MW from wind power facilities. To study the interconnection of TWRA to the CAISO 

grid, CAISO requested to modify the LGIP accepted by FERC in July 2005. Section 4.2 of the 

LGIP provides for the study of interconnection requests serially or in clusters for all 

interconnection requests received within a period not to exceed the queue cluster window of 180 

calendar days. Furthermore, Section 4.2 provides that CAISO may agree to separately study an 

interconnection request based upon the electrical remoteness of the proposed generating facility. 

Unlike a typical interconnection study, the Tehachapi interconnection study focused exclusively 

 

The GIPR changes the interconnection study process from a serial study to a cluster 

study. Clustering allows CAISO to study all interconnection requests received during a “Queue 

Cluster Window” as a group, rather than serially, for conducting the system impact study.

Section 4.2 of the CAISO’s LGIP (Appendix U to the CAISO Tariff), effective May 25, 2006, 

grants CAISO authority to use “clustering” to process interconnection requests. CAISO has only 

exercised this authority once, with special permission from FERC, for the limited purpose of 

studying the Tehachapi Wind Resource Area (TWRA).

The Tehachapi Transmission Project that was examined as part of the CAISO South 

Regional Transmission Plan (CSRTP) as the least-cost solution for developing transmission 

infrastructure that would interconnect planned generation projects in the TWRA to the CAISO 

grid. Rather than extend the grid to Tehachapi in a piece-meal, costly manner, CAISO sought to 

identify and group a number of proposed projects so that the expansion of Southern California 

Edison’s (SCE) transmission system would be appropriately sized to handle the large number of 

projects contemplated for the region. 

 3 CAISO, “California Independent System Operator Corporation Generator Interconnection Process Reform Tariff 

Amendment,” filed with FERC, July 28, 2008. 4 FERC, “Order Conditionally Approving Tariff Amendment,” Docket No. ER08-1317-000, September 26, 2008.
B-4

on identifying network upgrades necessary to interconnect the project to the CAISO grid in an 

integrated manner. The study did not include the cost of any direct connection facilities, i.e., 

radial wind collector systems that interconnect the individual generation projects to the grid, and 

that these facility interconnection costs would be the responsibility of generation developers 

following a separate, more traditional serial interconnection study process. The full cost and 

ownership of the transmission network facilities associated with the Tehachapi Transmission 

Project are to be assigned to SCE and recovered through the CAISO Transmission Access 

Charge. 

CAISO proposed to deviate in several respects from a typical clustered interconnection 

study. Specifically, CAISO requested and was granted a waiver to establish an extended thirtythree month window for the cluster study as necessary to obviate the need for duplicative and 

redundant incremental studies and to allow for greater efficiency in the design of necessary 

network upgrades. This allowed sufficient time for potential developers to submit 

documentation for planned wind projects that were uneconomic and not possible, barring 

transmission network expansion to the region. 

The estimated cost of this 5-year project is $1.8 billion. The cost includes the addition 

and upgrades of several transmission lines, but excludes the cost of Interconnection Facilities. 

The CSRTP identified five alternative plans of service, but each of them cost more than the 

proposed plan, with no additional benefits. Beginning in early 2008, the first segment of the 

project is planned to be in-service by December 2008, with the other ten segments being 

completed and in-service by November of 2013. 

On April 8, 2008, CAISO issued a Market Notice indicating the process through which 

CAISO plans to transition from a serial interconnection review to the cluster approach. CAISO is 

creating three study groups to proceed through a transition to the cluster study: the Serial Study 

Group, the Transition Cluster, and the Initial GIPR Cluster. CAISO was issued a waiver on July 

14, 2008, that allows an expedited process for interconnection projects that have signed system 

impact study agreements as well as those with pending or approved power purchase agreements.5

• Projects characterized as late-stage interconnection requests, defined as those that have 

executed an Interconnection System Impact Study (ISIS) agreement with a results due 

date prior to May 31, 2008,

Those interconnection requests that are currently included in the serial study queue will 

be processed as part of the “Serial Study Group.” Selection for the Serial Study Group is based 

on interconnection status and not queue position. Projects have to meet one or more of the 

following criteria:

• Existing power purchase agreements that are approved or pending approval from the state 

regulatory authority, and 

• Interconnection requests that have received land use approvals from local, state, or 

federal agencies, as applicable.

 5 FERC, Order on Petition for Tariff Waiver, re: California Independent System Operator, ER08-960, July 14, 2008.
B-5

Based on these criteria, the Serial Study Group is projected to include 85 of the projects 

in the queue, 60 of which are in the serial study phase or later. The Serial Study Group should 

include approximately 25 percent of the proposed renewable energy projects, slightly more than 

12,000 MW. Some renewable energy projects expected to move forward with the Serial Study 

Group include 17 projects representing 4,413 MW seeking interconnection to the Tehachapi 

Renewable Transmission Project and 5 projects seeking interconnection to the Sunrise Power 

Link for a total of 1,760 MW.6

• A new, signed, interconnection process agreement,

The Transition Cluster will include the remaining early stage interconnection requests, 

and those that do not meet the criteria to be placed in the Serial Study Group, but that have 

validated interconnection requests received prior to June 2, 2008. CAISO plans to suspend the 

study activities for those projects in the transition cluster until all studies in the Serial Study 

Group are completed. Based on the estimated timing to complete the Serial Study Group 

requests, CAISO expects to begin work on the Transition Cluster requests by November 2008, 

with all studies completed by July 2009. Projects placed in the Transition Cluster will be 

required to provide the following:

• Any missing technical data not previously provided, for example, preferred point 

of interconnection, voltage delivery, electrical design specifications, and 

equipment specifications,

• Specified deliverability status of either full capacity or energy only, 

• Proof of site control for each interconnection request in the form of ownership of 

leasehold documents, development rights, or other legal documentation providing 

rights and access to the property, and 

• `, subject to refund net of any study and administrative costs with a completed 

interconnection agreement. 

Project developers currently in the queue who do not provide the information and funds 

listed above will be withdrawn from the queue. 

All interconnection requests that are received by CAISO after June 2, 2008, will be 

placed in the Initial GIPR Cluster study group and subject to a temporary suspension. CAISO’s 

LGIP tariff limits the cluster window to 180 days, however, CAISO requested a waiver from 

FERC to extend the window for the Initial GIPR Cluster from June 2, 2008, to July 31, 2009, to 

coincide with the conclusion of the expected study period of the Transition Cluster. CAISO does 

not anticipate or intend on processing interconnection requests received during the initial queue 

cluster window until the interconnection requests submitted prior to June 2008 are fully studied

as part of either the Serial Study Group or the Transition Cluster Study Group.

 6 Stephen Rutty, Manager Grid Assets, CAISO, Declaration of Stephen Rutty in Support of Petition for Waiver of 

Tariff Provisions to Accommodate Transition to Reformed Large Generator Interconnection Procedures, submitted 

to FERC, May 15, 2008. 
B-6

Interconnection Process7

The new interconnection request system 

establishes a ten-step process through which 

interconnection requests will be studied. The ten steps 

are listed in Table B-2 along with the approximate 

timelines for each step. According to CAISO, an 

interconnection agreement will be executed 

approximately 2 years after the close of the queue 

window. 

Just two four-month cluster windows will be 

opened each year. The first opens April 1st and closes 

July 31st, and the second opens October 31st and 

closes January 31st of the following year. During these 

windows, ICs will submit an interconnection request 

with an application and $250,000 deposit, site control 

documents, expected in-service date, technical data, 

and deliverability status (energy only or capacity and 

energy). In a significant change, ICs are limited in 

when and how they may modify the in-service date. 

There are three opportunities to modify the in-service 

date: within 5 days of the scoping meeting; prior to the 

initiation of Phase II studies; and, at the meeting to 

discuss the Phase II results. Extensions of the 

commercial operation date are limited to a maximum 

of 3 years, however, the IC must still meet all financial 

commitments, and CAISO notes that suspension does 

not materially alter the IC’s financial exposure. ICs 

that do not follow these guidelines may be withdrawn 

from the queue, forfeiting their position. 

After closing the queue window, validating applications, and conducting all scoping 

meetings, CAISO will group projects in the cluster based on interconnection points and shared 

transmission needs based on engineering judgment (Step 4). Different base cases will be 

developed to focus on a stressed dispatch level for each group while evaluating balance loads 

and resources. Results and variables of the base case scenarios will be provided on a passwordprotected CAISO webpage. 

Under the GIPR, interconnection studies will consist of a Phase I Interconnection Study 

and a Phase II Interconnection Study. The feasibility study, performed under the prior 

interconnection study process, and the optional study will no longer be required and have been 

removed from the tariff. The GIPR has arranged Phase II studies to closely coordinate them with 

 7 The information in this section is from the proposed LGIP Tariff: CAISO, “California Independent System 

Operator Corporation Generator Interconnection Process Reform Tariff Amendment,” filed with FERC July 28, 

2008.

Table B-2 

CAISO 

Generator Interconnection 

Process Reform (GIPR)

 

Month IR Process Deposit

1

1. Queue Window $250,000

deposit 

fully 

refundable

2

3

4

5 2. IR Validation

6 3. Scoping Meeting

7 4. Grouping Base Case

$100,000 

no longer 

refundable

8

5. Phase I Cluster Studies

9

10

11

12

13 6. Results Meetings

14 7. Financial Commitments 

15 IC Posts 20% LOC

Full 

$250,000 

no longer 

refundable

16

8. Phase II Study: 

Project Refinement and 

Facilities Study

17

18

19

20

21

22

23

24

25

26 9. Results Meetings

27 10. Interconnection 

Agreement 28

29

IC = Interconnection Customer

LOC = Letter of Credit
B-7

CAISO’s annual Transmission Planning Process and to facilitate this, will aim to have Phase II 

scheduled so that it is completed within 330 days from January 1st of each year.

The new procedures also have a provision for certain projects to move forward in an 

expedited manner. This is aimed at giving generation projects located in an area that is 

independent of other projects (i.e., not needing to be clustered) a way to move ahead to 

construction more quickly. A project developer can request to enter the Accelerated Project 

Refinement and Facility Study Process after the completion of their particular Phase I study if 

they meet the following criteria:

• The interconnection request was not grouped with any others during the Phase I 

study process or was identified as having an interconnection point that accesses 

currently available transmission capacity.

• The IC can show that the established study timelines will not allow the project to 

meet its in-service date.

Interconnection Study Fees and Financial Security for Network Upgrades

In an effort to limit interconnection requests to only those projects that are economically 

and technically viable, CAISO has made significant increases to interconnection fees. Prior to 

the GIPR, ICs were required to provide a $10,000 deposit along with their application.8

(1) For private land: either ownership of, a leasehold interest in, or a right to develop the land 

on which the facility will be located consisting of a minimum of 50 percent of the 

required acreage; or, an option to purchase or acquire a leasehold interest in the above.

 All or 

part of the deposit was refunded if the project was withdrawn and study costs were less than the 

deposit. Under the new system, ICs will have to provide a $250,000 refundable deposit at the 

time that they submit their interconnection request, and an additional $250,000 deposit if they are 

unable to provide documentation of ‘site exclusivity,’ a modified definition of site control. 

During the stakeholder process, the Federal Bureau of Land Management (BLM) expressed 

concerns with the definition of site control. Due to this feedback, CAISO has created a new 

category termed site exclusivity that includes separate criteria for private and public lands. 

Documentation requirements are as follows:

(2) For public land: includes any lands controlled or managed by any federal, state, or local 

agency. The IC must have a final, non-appealable permit, license, or other right to use the 

property for generating electricity in the acreage reasonably expected to accommodate 

the facility, and additionally, an exclusive right to use public land under management of 

the BLM must be in a form specified by the BLM. 

After about 19 months from when the interconnection application is filed, the IC is no longer 

able to request a refund because the fee is used to cover the cost of the studies. 

 8 An additional $10,000 refundable deposit was required if demonstration of site control (e.g., lease or ownership 

documents) is not provided with the application.
B-8

Those projects that are placed in the Transitional Cluster or the Initial GIPR Cluster will 

also be subject to the higher fees. Those projects in the late stages of interconnection study to be 

included in the Serial Study Cluster will not have to pay the higher fee. 

The estimated costs of a project’s network upgrades are estimated as part of the Phase I 

Interconnection Study, according to per unit cost assessments provided by the applicable 

transmission owner prior to the April 1 queue cluster window opening. Within 90 days of an IC 

entering the Phase II Study period, and prior to definitively assigning responsibility for financing 

network upgrades, the IC must post financial security for 20 percent of the estimated total cost 

responsibility assigned to the IC in the Phase I study, or $500,000, whichever is greater. Within 

180 days of publication of the Phase I Study report, the IC must post financial security for 100 

percent of the total cost responsibility of the project, as estimated in the Phase I study, or 

$500,000, whichever is greater. 

According to Section 9.4 of the revised LGIP tariff, in the event that a project is 

withdrawn after posting its financial security, the IC is still required to satisfy the cost 

responsibility for the network upgrades assigned to the customer in Phase I of the 

interconnection study. There are conditions under which a partial recovery of financial security is 

allowed, including: 

• Failure to secure a power purchase agreement,

• Failure to secure a permit,

• Increase in costs to network upgrades as a result of the Phase II study that are 

greater than 30 percent of the estimated Phase I cost responsibility, and

• Increased costs due to a CAISO-required change in interconnection point. 
C-1

C. ELECTRIC RELIABILITY COUNCIL OF TEXAS

The Electric Reliability Council of Texas (ERCOT) coordinates all transmission planning 

and development on a regional basis in most of Texas. In 2005, ERCOT received a total of 44 

interconnection requests worth approximately 12,000 MW, and 31 of those requests were from 

wind projects representing 5,000 MW.1 In 2006, ERCOT received a total of 94 requests worth 

55,000 MW with 54 of those for wind projects representing 12,000 MW.2 During 2007, ERCOT 

received 129 interconnection requests representing approximately 62,000 MW of capacity. 

Seventy projects went through the full interconnection study phase and nine interconnection 

agreements representing 3,900 MW were signed. As of December 10, 2007, ERCOT was 

tracking a total of 91,551 MW worth of interconnection requests in various stages of the 

process.3 Installed capacity at the end of 2007 was approximately 81,000 MW. With load growth 

projected at 2.1 percent annually to 2013, this is far more generation capacity than will be 

required to be built in the ERCOT region.4

Generation Interconnection Process5

 1 Communications with ERCOT, December 2007.

2 Ibid.

3 ERCOT Report on Existing and Potential Electric System Constraints and Need, December 2007. 4 Ibid.

5 Information in this section from: System Planning, Transmission Services, “Generation Interconnection or Change 

Request Procedure,” ERCOT, August 2004.

ERCOT coordinates the generation interconnection process and oversees the study 

requirements on behalf of the transmission providers in its jurisdiction. The actual 

interconnection agreement, however, is ultimately the responsibility of the transmission 

providers and the interconnection customer (IC). The affected transmission providers and the IC 

negotiate and sign the interconnection agreement at the end of the study phase. The Public Utility 

Commission of Texas (PUCT) has designed the transmission development cost allocation system

and they must approve transmission projects. The PUCT has designated transmission 

development as a social good and costs - both upgrades and generation interconnections - are 

delegated to load. Transmission providers are required to build facilities to interconnect 

generators (with PUCT approval) and costs are ultimately rolled into rates through ERCOT-wide 

postage-stamp transmission rates. ERCOT coordinates and provides independent review for 

Regional Planning Groups (RPG) made up of stakeholders, market participants, or other 

interested parties in an open process. Projects are presented to the affected planning groups for 

review and feedback. ERCOT assesses all generation and transmission additions through its 

Power System Planning Charter and Process, including all input from the planning groups. 

Stage 1: Screening Study

The first stage of the interconnection process under ERCOT is the screening study phase. 

An IC begins the interconnection process by submitting an interconnection request, preliminary 

data, and a non-refundable security screening study fee. The fees are based on the size of the 

generation project as follows:
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• 10 to 74 MW - $1,000

• 75 to 149 MW - $2,000

• 150 to 249 MW - $3,000

• 250 to 499 MW - $4,000

• 500 MW and greater - $5,000

A separate request is required for each individual interconnection location, in-service 

date, and total plant capacity at that location. The screening study is a steady-state screening 

study, including power flow and transfer studies applied to the proposed in-service year to 

determine the feasibility of the site, the amount of known generation in that area, and the level of 

expected generation that may be utilized from the project. The results of the screening study will 

tell the project developer if that particular site is able to accommodate the proposed project, or 

will provide an estimate of the magnitude of transmission network upgrades and additions 

necessary for the project to achieve full potential. The timeframe for completion of the screening 

study phase is from three to 90 days of receipt of all necessary request items. ERCOT provides 

the information to the IC, which then has 180 days to notify ERCOT if it wishes to move ahead 

to the next study stage. If notice is not received within that time frame, ERCOT will consider the 

request cancelled and no longer valid.

Stage 2: Full Interconnection Study

Once notice of intent to proceed is received, ERCOT schedules a meeting with the IC and 

the primary transmission provider. Other interested transmission providers are invited to 

participate, if desired. Together, these entities decide on a path forward with respect to study 

requirements, timelines, deposit requirements, and cost estimates. The primary transmission 

provider maintains a lead role and other transmission providers or ERCOT provide any 

additional analysis that may be required. Prior to the start of the interconnection study, the IC 

must submit a model fee of $15 per MW and proof of site control. The model fee is used to 

develop stability models for generators and to update ERCOT’s current set of models to reflect 

equipment additions. The IC is responsible for paying the cost of the full interconnection study, 

and the primary transmission provider bills the IC directly. 

Site control is demonstrated through showing that the company, an affiliate, or a trustee 

has one or more of the following:

• Is fee-simple owner of the real property to be used for the site;

• Holds a valid written leasehold interest in the site;

• Holds a valid written option to purchase or obtain a leasehold for the site;

• Holds a duly executed written contract to purchase or obtain a leasehold interest 

for the site.

The IC must maintain site control throughout the duration of the study up to the signing of the 

interconnection agreement. If the IC loses site control, it has 30 days to regain it or ERCOT will 

consider the request withdrawn.

Following the establishment of eligibility, the IC and affected transmission providers 

have 60 days to complete the study scoping process and sign a study agreement outlining 
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assumptions, timetables, cost estimates, and requirements for interconnection. Once the 

agreement is signed, the full interconnection study stage begins and includes the following steps:

(1) Steady State & Transfer Analysis Study – within 10 to 90 days

(2) System Protection Analysis – within 10 to 30 days after study (1)

(3) Dynamic Analysis – within 10 to 90 days after study (2)

(4) Facilities Study – within 10 to 90 days

Once all the above studies are completed, the parties will meet to examine the results. 

The IC and transmission providers then have 180 days to negotiate and complete an 

interconnection agreement at which time the project will be considered ‘confirmed’. 

A generation project in the ERCOT region is not considered public and details are not posted on 

the ERCOT site until that project achieves confirmed status. 

FERC Order 2003 Compliance

ERCOT does not have to comply with Order 2003 since ERCOT is not regulated by 

FERC other than on issues arising under the Energy Policy Act of 2005. That said, the ERCOT 

interconnection process follows a similar format. The screening study is almost the same as the 

feasibility study set out in Order 2003, but ERCOT requires smaller deposit amounts and sets the 

study time limit at 90 days as opposed to 45 days. The other studies required under Order 2003 

have been combined in the full interconnection study as a package and ERCOT can take up to 

210 days to complete all the study parts. ERCOT requires a deposit partially based on generator 

size, which can result in total amounts smaller or larger than those set out in Order 2003. 

ERCOT does not allow project suspensions and does not maintain a public queue, considering 

projects confidential until an interconnection agreement is executed or a public letter is issued by 

the owner. Additionally, costs are allocated to ERCOT load rather than to ICs, and as a result, 

projects and transmission upgrades meeting voltage level or cost criteria are assessed by ERCOT 

through its RPG process. Transmission construction, both for generator interconnections and 

network upgrades below the criteria, does not need to undergo the RPG process, but still must be 

approved by the PUCT.

Clustering - Texas Competitive Renewable Energy Zones

Texas has perhaps the most successful renewables portfolio standard in the nation, in 

terms of new renewable energy capacity. As of January 2008, ERCOT is tracking over 41,000 

MW of wind generation interconnection requests in various stages of the process.6 In January 

2007, the Texas RPS was revised to include a type of clustering for wind energy development 

called Competitive Renewable Energy Zones (CREZ).7

 6 System Planning Division, “Monthly Status Report to Reliability and Operations Subcommittee for December 

2007,” ERCOT, December 2007.

7 Public Utility Commission of Texas, Public Utility Regulatory Act, Section 25.174. 

http://www.puc.state.tx.us/rules/subrules/electric/25.174/25.174.pdf

 CREZs consist of designated areas with 

large wind generation potential that lack adequate transmission. Transmission will then be 

developed for the zone to connect multiple wind generators, as opposed to being built for one 

particular project. An ERCOT study identified 25 potential zones, and in October 2007, the 
C-4

PUCT issued an interim order granting CREZ designation to six of those zones.8 The PUCT 

announced that these six zones, located around Amarillo, Abilene, and McCamey, met the 

criteria established by the Public Utility Regulatory Act 2007 – sufficient renewable energy 

resources, suitable land areas, and a significant level of financial commitment displayed by 

generation developers. The PUCT directed ERCOT to conduct a CREZ Transmission 

Optimization Study on four different wind scenarios involving potential wind generation levels 

in the CREZs, to determine what transmission needs to be/should be built to access the zones. 

The optimization study released in April 2008 outlined cost estimates for the transmission 

requirements. The scenarios ranged from 5,150 MW of wind spread across the six zones to 

17,956 MW, with costs estimated at $2.95 billion to $6.22 billion. In August 2008, the PUCT 

issued an order approving a transmission development plan that could result in 18,456 MW of 

transfer capacity from the CREZs at a projected cost of $4.93 billion.9

 8 Public Utility Commission of Texas, PUC Docket No. 33672, Interim Order, October 2007.

9 Public Utility Commission of Texas, Order, PUC Docket No. 33672, “Commission Staff’s Petition for Designation 

of Competitive Renewable Energy Zones,” August 2008.
D-1

D. ISO NEW ENGLAND

ISO-New England’s interconnection queue has experienced growth rates similar to other 

regions, though unlike most areas, wind power accounts for only a small portion of the 

interconnection requests. Natural gas is the major driver in New England generation 

development, followed by a mix of other renewables that include biomass, hydropower, and 

landfill gas (LFG). In 2005, ISO-NE received 16 interconnection requests for a total of 1,550 

MW. In 2006, that number had risen to 56 requests for a total of 8,640 MW, with 28 of them for 

natural gas generation. That number held steady for 2007, with a total of 57 requests for 10,710 

MW, 32 of which were for natural gas projects and 19 for a variety of other renewables (LFG, 

hydro, wood); only 5 requests were for wind power projects. At the end of 2007, ISO-NE had 

approximately 19,100 MW of active projects in its queue, more than half of the ISO’s total 

installed capacity, which is approximately 37,500 MW.

Generator Interconnection Queue Process1

ISO-NE will use all reasonable efforts to complete the feasibility study within 45 days 

and will notify the IC if unable to do so. After completing the feasibility study, ISO-NE will 

provide a draft copy to the IC and schedule a meeting to discuss the results, to be held within ten 

The ISO-NE generator interconnection process is initiated by an interconnection 

customer (IC) submitting an interconnection request and providing a $10,000 deposit that will be 

applied towards subsequent study costs. An IC may submit multiple requests for each site but 

must provide a separate interconnection request and deposit for each one. The interconnection 

request must provide an expected initial synchronization date for the generation facility that is 

within seven years of the request; however, if the project needs additional time, the IC can 

submit evidence to that affect and negotiate a longer time period. Within five business days, 

ISO-NE will acknowledge the request by providing a feasibility study agreement, and within ten 

days scheduling the initial scoping meeting to be held within 30 days. At the scoping meeting, 

the parties will exchange pertinent data, determine potential points of interconnection, and 

estimate timelines for conducting the necessary studies. The IC then has five days to notify ISONE that it will proceed with the project and provide the completed study agreement noting the 

definitive point(s) of interconnection to be studied. Along with the completed study agreement, 

the IC must demonstrate it has site control or provide an additional $10,000 deposit that will also 

be applied towards study costs. 

Feasibility Study

ISO-NE assigns a queue position when it receives an interconnection request based on 

the time and date it first received the initial interconnection request. The IC can withdraw from 

the queue at any time but will be liable for any study costs incurred to date. ICs also have the 

option of waiving the feasibility study after the initial scoping meeting with ISO-NE and 

proceeding straight to the system impact study. 

 1 Procedures in this section from: ISO New England Inc., “Schedule 22 – Standard Large Generator Interconnection 

Procedures (LGIP),” issued January 8, 2005.
D-2

business days. The feasibility study will include an initial good-faith cost estimate. If a re-study 

is required due to a higher queued project withdrawing from the queue, ISO-NE will notify the 

IC and conduct the re-study within 60 days. Re-study costs throughout the interconnection 

process are the responsibility of the IC.

System Impact Study

Following the finalization of the feasibility study, ISO-NE will furnish the IC with a 

system impact study agreement. The IC then has 30 days to return the executed agreement along 

with all required technical data, a demonstration of site control, and a deposit. The deposit will 

be the lesser of $50,000 or the estimated cost. ISO-NE will make reasonable efforts to complete 

the impact study within 90 days and following completion will provide a draft of the system 

impact study and schedule a meeting to discuss the results, to be held within the next 10 business 

days. Within five days following meeting, the IC must notify ISO-NE as to whether or not it 

intends to continue with the project. The IC has the option of requesting an interconnection 

facilities study or waiving the interconnection facilities study and moving to expedited 

interconnection. If the IC chooses expedited interconnection, the project will move directly to the 

LGIA and must commit to meeting the following milestones, within an agreed timeframe:

1. Obtain siting approval.

2. Conduct engineering of interconnection facilities as approved by the interconnection 

transmission owner.

3. Order long lead-time materials.

4. Set an initial synchronization date.

5. Set a commercial operation date.

The IC has the option of signing an Engineering and Procurement Agreement (discussed 

later in this section) in order to meet some of the above requirements. 

Optional Interconnection Study

Following completion of the system impact study, an IC has the option of requesting an 

additional interconnection study that is designed to provide additional data respecting expected 

costs for interconnecting the project to the grid. The cost for this study will be borne by the IC 

and requires an additional $10,000 deposit. The timeframe for completing an optional study will 

be mutually agreed to between ISO-NE and the IC. 

Interconnection Facilities Study

Within three business days following the system impact study meeting, ISO-NE will 

furnish the IC with an interconnection facilities study agreement and a good faith cost estimate. 

If the IC has chosen to proceed with the facilities study (as opposed to withdrawing, requesting 

an optional study, or choosing expedited interconnection), it has 30 days to return the fully 

executed agreement along with all required technical data and a deposit. If the estimated cost is 

less than $100,000, the deposit will be in the amount of the estimate. If the estimate cost is 

greater than $100,000, the deposit will be $100,000 or the IC’s portion of the estimated monthly 
D-3

cost of the facilities study. ISO-NE will make reasonable efforts to complete the facilities study 

within 90 days and then deliver a draft to the IC and schedule a meeting to discuss results, to be 

held within the next 10 business days. 

Engineering and Procurement Agreement

The Engineering and Procurement (E&P) Agreement is an optional agreement between 

the transmission owner and the IC (ISO-NE is not involved) that can be entered into in advance 

of executing the LGIA in order to get a project moving forward. An E&P agreement authorizes 

the relevant transmission owner to begin engineering work and long lead-time materials 

procurement for construction of the required interconnection facilities. 

Large Generator Interconnection Agreement

Following either the system impact study meeting or the facilities study meeting, 

depending on which path the IC has chosen, the IC has 30 days in which to comment on the 

reports results. Fifteen days following the comment period ISO-NE (together with the 

transmission owner) will, unless otherwise agreed upon in an E&P agreement, deliver a draft 

LGIA to the IC. The IC then indicates an interest in executing the LGIA and after that, ISO-NE 

issues a final LGIA, all within the next 30 days. Alternatively, the IC can request a negotiation 

proceeding if it disagrees with the results. Following the execution of the LGIA, the IC must,

within 15 days, provide evidence of site control and post a non-refundable $250,000 deposit that 

will be applied towards the future construction costs. The IC must also show that one or more of 

the milestones within the LGIA has been achieved. These milestones include:

1. Execution of a contract for the supply or transportation of fuel.

2. Execution of a contract for supply of cooling water.

3. Execution of a contract for engineering, procurement of major equipment, or for 

construction (can be accomplished through signing an E&P Agreement). 

4. Execution of a contract for the sale of energy or capacity from the facility.

5. Application for an air, water, or land-use permit.

Cost Allocation

In ISO-NE, all study and re-study costs due to higher queued project withdrawals, and 

both interconnection facility costs and network upgrade costs, are the responsibility of the IC. 

If the network upgrades result in increased transmission capability, the IC will receive firm 

transmission rights for that net increase in transmission capability. 

Clustering

The ISO-NE Schedule 22 – LGIP did not originally contain provisions for clustering 

studies as it was thought unnecessary.2

 2 ISO New England Inc., “FERC Order 890 Compliance Filing,” April 15, 2008.

 FERC issued Order 890 Final Rule in February 2007 

requiring all ISO and RTO’s to add tariff language for clustering for transmission 

interconnection requests—ISO-NE still conducts studies for generator interconnections on a 
D-4

serial basis. As a result, on April 15, 2008, the ISO-NE filed amendments to Schedule 22 –

LGIP, including provisions allowing the ISO to open a cluster window for transmission 

interconnection requests by announcing the start and end dates, if it chooses to do so.3 The ISONE clustering provision applies only to system impact studies, thereby allowing the ISO to 

conduct impact studies as a group if necessary. To date, however, ISO-NE does not seem to have 

utilized this provision and re-iterated in a 2008 FERC filing that cluster studies were not a good 

solution in the region.4

ISO-NE Schedule 22 – LGIP follows Order 2003 procedures, study cost, and study time 

guidelines almost exactly, with the addition of some unique features such as the expedited 

interconnection process. However, ISO-NE does not allow projects to enter suspended status per 

Order 2003 during the study phase. Once an LGIA is in effect, the IC can, upon giving notice to 

the ISO, enter suspended status for up to three years but is liable for any construction/preconstruction costs incurred to date. If the IC does not recommence work within the three-year 

period, ISO-NE will consider the LGIA terminated.

FERC Order 2003 Compliance

5

ISO-NE filed its generator interconnection tariff reform proposal with FERC on October 

31, 2008.

Proposed Reforms

6

1. Interconnection Request: Proposing to increase the deposit from $10,000 to 

$50,000 and require a demonstration of site control. Any unused portions of the 

 The filing proposes to change both the generator interconnection process and certain 

aspects of Forward Capacity Market (FCM) participation. ISO-NE recently introduced an FCM 

and the first auction was held in February 2008 for delivery of capacity into 2010/11. This first 

auction highlighted the issue of queue backlog as projects participating in the FCM were faced 

with uncertainty as to whether they can meet the 2010/11 target due to being held up in the ISONE queue. In addition, the FCM relied on interconnection queue position to determine the 

priority between generating projects that shared the same transmission capacity. This was not 

viewed as ideal, and as a result, ISO-NE formed the Forward Capacity Market/Generator 

Interconnection Process Stakeholder Group in mid-2007 to examine and propose reforms to the 

generator interconnection process that would allow for better coordination with the FCM. The 

Stakeholder Group held a series of meetings from September 2007 through April 2008, and on 

June 11, 2008, issued a set of proposed queue reforms that were subsequently incorporated into 

the tariff filing. The proposed reforms include creating categories for Conditional Qualified 

Capacity Resources and Long-Lead Resources (discussed below) and the following changes to 

the interconnection queue:

 3 Ibid.

4 ISO New England Inc., “ISO New England Inc.’s Interconnection Queuing Practices Status Report,” FERC Docket 

No. AD08-2-000,” April 21, 2008. 5 ISO New England Inc., “Schedule 22 – Standard Large Generator Interconnection Procedures (LGIP),” Issued 

January 8, 2005.

6 ISO New England, “Joint Filing of Proposed Revisions to the Generator Interconnection Process and Forward 

Capacity Market Participation Provisions Set Forth in the ISO New England Inc. Transmission Markets and Sevices 

Tariff,” filed with FERC October 31, 2008. 

http://www.iso-ne.com/regulatory/ferc/filings/2008/oct/er09-____-000_10-8-31_fcm_queue.pdf
D-5

deposit will be refundable if the project withdraws within ten days of the scoping 

meeting. 

2. Feasibility Study: Proposing to make the deposit equal to 100 percent of the 

estimated study costs. Upon completion of the feasibility study, any funds 

remaining will be applied to the system impact study or refunded if the project 

withdraws.

3. System Impact Study: ICs could choose between three options for the required 

deposit. These options are:

a) The greater of 100 percent of the estimated study costs or $250,000.

b) The lower of the estimated study costs or $50,000, plus copies of all 

relevant major permit applications.

c) The lower of the estimated study costs or $50,000, plus demonstration of 

‘at risk’7

4. Interconnection Facilities Study: ICs could choose one of the following three 

options:

project expenditures in at least an amount equal to the amount in 

(a) above. 

a) The greater of 25 percent of the estimated study costs or $250,000.

b) The lower of $100,000 or the estimated monthly share of the study 

costs, plus copies of all relevant major permit applications.

c) The greater of $100,000 or the estimated study costs, plus 

demonstration of ‘at risk’ project expenditures in at least an amount 

equal to the amount in (a) above.

5. Large Generator Interconnection Agreement: ICs would have two options 

depending on whether or not the facilities study was waived. These options are:

a) If the facilities study was waived, then the IC must provide a deposit equal 

to estimated cost of the engineering studies that would have been a part of 

the facilities study, commit to an agreed-upon upgrade expenditure 

schedule, and provide copies of all relevant major permit approvals.

b) If the facilities study was conducted, then the IC can provide a deposit 

equal to 20 percent of the cost of the estimated construction costs as 

calculated in the facilities study, commit to the remaining schedule of 

upgrade expenditures, and include milestones for the completion of major 

permit approvals.

Additionally, the reform proposal has provisions for allowing a project to choose an 

energy-only or a capacity resource interconnection. If a project chooses the energy-only option, 

it cannot participate in the FCM auction. For a project to qualify as a capacity resource in the 

FCM, it must apply for interconnection as such. If it wishes to, the project can receive energy-

 7 ‘At risk” expenditures are those expenditures that could not be recovered if the project is terminated; e.g., lease 

payments, permit costs, non-refundable equipment deposits. 
D-6

only interconnection service until any necessary network upgrades are in place. The reform 

proposal also includes new categories for capacity resources in an attempt to base queue 

positioning and progress on FCM economics rather than date and time of request.8

ISO-NE has proposed this option for large projects with longer development cycles than 

the time between the auction and the delivery year. These projects need a way of securing a 

transmission interconnection at a certain point in their development for them to be able to 

proceed. An IC with a proposed generating facility that has a summer net electrical output of 100 

MW or greater may request that it be considered a Long-Lead Resource (LLR) when filing its 

interconnection request. ISO-NE will examine the details surrounding the request and make a 

determination to grant or deny the LLR designation. ICs with a proposed generating facility 

under 100 MW can also petition ISO-NE for LLR designation. An LLR resource will then be 

eligible to participate in an FCA and secure an interconnection at a certain stage of project 

development. This will include an LLR being required to submit and follow a schedule of 

development and continue providing specific amounts of financial assurance, until it clears in an 

FCA. 

Conditional Qualified Capacity Resources

This category is being proposed as an option for allowing lower queued capacity 

resources to participate in Forward Capacity Auctions (FCA). A capacity resource that has 

overlapping impacts (competing for the same transmission capacity) with higher queued projects 

may still ‘conditionally qualify’ for an FCA along with the higher queued project. The higher 

queued project would be considered the primary resource and the lower queued, the conditional 

resource. If the primary resource clears in the FCA, then the conditional resource cannot. If the 

primary resource withdraws from the FCA or fails to post financial deposits, then the conditional 

resource would become the primary resource and could clear in the auction. Under this proposal, 

a higher queued resource cannot block a lower queued resource from participating in an FCA by 

applying for the auction and then withdrawing prior to clearing. 

Long-Lead Resources

 8 ISO New England Inc., “Summary of the Forward Capacity Market (FCM) / Generator Interconnection Process 

Stakeholder Group,” presentation to the Joint MC/RC/TC, June 11, 2008.
E-1

E. THE MIDWEST INDEPENDENT SYSTEM OPERATOR

Compliance with FERC Order 2003

FERC Order 2003 allowed independent transmission providers, e.g., recognized RTOs, 

the flexibility to deviate from the pro forma LGIP and the LGIA as needed to meet their regional 

needs. On June 20, 2004, the Midwest Independent System Operator (Midwest ISO) proposed 

several variations to the LGIP and LGIA that were filed with, and ultimately accepted by FERC 

on July 8, 2004. The majority of the variations from the pro forma tariffs under Order 2003 

customize the agreements to include the transmission owner as a signatory to the agreements. 

The Midwest ISO’s more substantive modifications to FERC’s LGIA and LGIP pro forma tariffs 

include the deferral of transmission credits for network upgrades in certain situations, payment 

for reactive power, compensation for rescheduling maintenance at the request of the Midwest 

ISO, and modifications to various definitions. 

Within their June 20, 2004, filing to FERC, the Midwest ISO requested the right to 

perform studies out-of-queue order based upon: the electrical remoteness of the proposed 

facility; or at the mutual request and agreement of the interconnection customer (IC) and the 

Midwest ISO. The Midwest ISO also proposed a group study format instead of the cluster study 

approach set forth in Order 2003. The Midwest ISO based its request on the expansive 

geographic scope of the RTO’s footprint, adding that it is inefficient to process interconnection 

requests together as a group (or cluster) according to time of receipt and with no regard to 

geographic location. The Midwest ISO believed that an interconnection request in an area with a 

short, light queue should not be held up waiting for a formal system-wide queue window to 

close. The Midwest ISO describes its group study as a single study that is more complex and 

allows the RTO to consider a more efficient set of expansions that would accommodate the 

group in a more cost-effective manner than considering individual upgrades. The Midwest ISO 

proposed conducting group studies under the following conditions:

• When a backlog of interconnections develops with electrically connected projects;

• Upon the request of a group of ICs;

• In connection with a state-sanctioned resource solicitation process; and

• To coordinate studies of interconnection requests on non-Midwest ISO system 

operator systems that might also impact operations on the Midwest ISO system. 

FERC rejected The Midwest ISO’s proposal to perform out-of-order and group studies as 

well as the request to extend the study period to 180 days from 90 days as established in the pro 

forma tariff. FERC stated that “queue windows with regular, fixed, opening and closing dates 
E-2

are essential to an orderly process.”1

1. Feasibility study, consisting of a power flow analysis and potentially a short circuit

and stability analysis as needed or requested by the IC or transmission provider; 

 The Midwest ISO requested rehearing of FERC’s rejection 

of the proposed group study process, and out-of-queue-order studies. In its rehearing request, the 

Midwest ISO clarified that it does not intend to have “mini-queues” in its region and that it has 

sufficient resources to begin group studies soon after the receipt of several interconnection 

requests that are within a short time frame and in close proximity. The Midwest ISO proposed 

that the group studies would be performed based on queue position, in close proximity in time 

and in space, without regard to the nature of the underlying interconnection service arguing that 

they provide efficient, effective and flexible processing of projects to the benefit of all ICs. In its 

filing to FERC, the Midwest ISO suggested that using the queue cluster window suggested by 

FERC’s pro forma tariff would add up to 180 days to the time to process an interconnection 

request. Additionally, the Midwest ISO transmission owners argued that FERC’s rejection of the 

proposed variations relating to group studies and out-of-queue-order studies could preclude 

certain transmission owners from complying with state resource solicitation processes, and thus,

improperly imposes FERC’s authority over these state-regulated programs. 

In its Order on Rehearing, Clarification, and Compliance Filing issued October 28, 2004, 

FERC reversed its prior decision, conceding to allow the group studies. However, the Midwest 

ISO was required to keep to the timelines established in FERC Order 2003. Furthermore, FERC 

required the Midwest ISO to honor requests by ICs that wish to move ahead with the study 

process as a stand-alone project. Under the revised LGIP, an IC may retain both an individual 

queue position and a group-study position. The result of the debate over group studies was to 

allow, and in some instances require, both a group study and a stand-alone project study and 

analysis. It seems that the negotiation to allow both group studies and individual studies may 

have created an environment encouraging duplicate interconnection requests and interconnection 

requests for multiple projects responding to an RFP process where only the winning project will 

be economically feasible. The high number of duplicate entries provided a high number of 

suspensions and withdrawals from the queue. 

Under the FERC-approved LGIP, the IC initiated the study process by submitting a valid 

application. A complete application included a $10,000 deposit; application form “Appendix 1”

of the LGIP tariff; and either demonstration of site control or a posting of an additional deposit 

of $10,000. After a valid application is completed, the Midwest ISO held a scoping meeting to 

discuss the project with the IC and the affected transmission owners. Following the scoping 

meeting, there were five steps to the interconnection process for the Midwest ISO: 

2. System impact study, including more detailed short circuit analysis, stability analysis, 

and a power flow analysis;2

 1 Order Accepting in Part and Rejecting in Part Compliance Filings to Oder Nos. 2003 and 2003-A., Issued July 8, 

2004 in Docket Nos. ER04-458-000 and ER04-458-001, p. 46. 2 1. Any stability analysis performed in a system impact study may include transient stability, large and small signal, 

sub-synchronous stability, dynamic voltage stability, mid-term and long-term stability, voltage flicker analyses, and 

excessive neutral current.

 
E-3 

3. Facility study, specifying and estimating the cost of the required equipment, 

engineering, procurement and construction work, including the electrical switching 

configuration needed to physically and electrically connect the interconnection 

facilities to the transmission or distribution system; 

4. Optional study as requested by the IC to evaluate varying MW injection levels; and 

5. An executed interconnection agreement, including either evidence of continued site 

control, or posting of $250,000 non-refundable additional security, as well as 

evidence of other project milestones, including fuel or water supply contracts, 

engineering and construction contracts, and copies of air, water, or land use permits. 

The Midwest ISO Group Studies

Overview 

The Midwest ISO adopted procedures for group interconnection studies in 2002. These 

studies were intended to group into a single interconnection study requests that are close in 

geographic location and time proximity. Four group studies were completed, Group Study 5 

(described below), and Group Study 6 (1500 MW in 21 requests; 20 wind and 1 biomass) were 

underway when the Midwest ISO made its reform filing. Additionally, prior to undertaking the 

queue reform process early in 2008, the balance of the interconnection queue was given 

preliminary assignment to Group Studies 7 through 22 with approximate start of study dates 

ranging out to 2022. 

Group 5

 Figure E-1

The Midwest ISO performed a group study Area Covered by Group V Study 

of interconnection of 2,860 MW of new generation, the 

Group 5 projects, to the Midwest ISO transmission 

system. The projects, 36 wind plants and one 750-MW 

coal plant, are distributed through an area 

approximately 200 miles by 300 miles in Iowa and 

Minnesota. Queue dates for projects in this group 

range from July 2004 to May 2006. 

The Group 5 study began in May 2006, and the 

feasibility study was completed in September 2006. 

The initial system impact study was not completed until 

October 2007. Stability results were challenged and 

subsequently re-analyzed in early 2008. 

The large number of unresolved higher queued 

interconnection requests has been a major challenge to 

implementing Group 5 projects. There are nearly 40 

higher queued requests that are in various stages short 

of operation (facility study, interconnection agreement 
E-4

completed, suspended, etc.).

3

The Midwest ISO has more pending projects and capacity in its interconnection queue 

than any other RTO or ISO. Currently there are 83 GW of generation in 402 active requests in 

the Midwest ISO queue.

 These higher queued projects have nearly 80 associated separate 

transmission upgrades that may need to be constructed prior to construction and operation of 

Group 5 projects.

Status of the Queue

4

 Using the literal interpretation of the FERC Order 2003 first-in-firstout process and excluding group studies, it would take approximately 425 years to clear the 

current Midwest ISO interconnection queue.

5

 Even with use of group studies and a ‘semiparallel’ process, where studies for sequential queue positions are overlapped in time, it is 

estimated that processing of current requests would not be completed until 2050. Figure E-2

shows the number of new entries by fuel type in 2007, and the cumulative total of projects in the 

queue as of December 31, 2007. The number of requests for generator interconnection in the 

Midwest ISO has increased rapidly in recent years, due in large part, to state renewable portfolio 

standards (RPSs). There were more than 200 generator interconnection requests initiated in 2007 

with an additional 135 requests added to the queue in the first half of 2008. This is a significant 

increase over the number of requests received in 2006 (more than 60 percent), and more than 

twice the requests received each year from 2002 to 2005.6

Figure E-2

Projects in the Midwest ISO Queue by Fuel Type

Wind power projects requesting interconnection in the Midwest ISO footprint have 

grown enormously, with the number of wind projects in the queue doubling from the end of 2006 

 3 As of March 1, 2008.

4 Midwest ISO Initiates Queue Reform Proposal, Midwest ISO Press Release, June 26, 2008. 5 Eric Laverty, Senior Manager, Transmission Access Planning, Midwest ISO, Interconnection Process Task Force 

Update, presentation provided on March 18, 2008 as part of the AWEA/CanWEA Wind and Transmission 

Workshop, slide 2. 

6 Proposal to Revise Generator Interconnection Procedures, Midwest ISO While Paper (Draft 1), January 23, 2008. 
E-5

to the end of 2007. Interconnection requests for wind power generation are nearly 70 GW of the 

total 83 GW in the queue. Much of the wind generation in the Midwest ISO footprint is located 

in remote areas, anywhere from 200 to 600 miles away from loads. For example, Buffalo Ridge, 

a region in the southwestern the Midwest ISO footprint, has over 22,000 MW of wind project 

interconnection requests, however, the current Midwest ISO transmission plan includes only 

1,900 MW of additional planned transmission capacity by 2014.7

In September 2007, the Midwest ISO created a stakeholder committee called the 

Interconnection Process Task Force that reports to the Midwest ISO Planning Advisory 

Committee. Stakeholders, including transmission owners, load serving entities, generation 

developers, and state regulatory staff worked to identify solutions to reduce time and increase 

certainty in the generator interconnection process. The Task Force proposed a milestone-based 

approach that could allow projects to proceed based on readiness rather than solely on queue 

order. The Midwest ISO formally filed their proposal with FERC on June 26, 2008. On August 

25, 2008, FERC issued an order conditionally accepting the reform filing effective immediately.

Primary factors leading to the current queue backlog included the low cost of queue 

entry, no cost for suspension, and lack of needed transmission expansion to support generator 

interconnection. With the low cost of entry at the beginning of the process and no cost for 

suspension at the end, participants were encouraged to enter the queue early and often. The 

logjam was amplified by the high number of interconnection requests in areas where the grid is 

weak and transmission upgrades are needed.

The Midwest ISO Queue Reform

8

The main differences of the new process when compared to the previous process include

how projects meet the milestones, the different paths a project can take through the process, the 

addition of a “fast lane” for interconnection agreements that are relatively simple, increased 

study deposit fees, and increased suspension penalties. A central theme of the queue reform is to 

minimize the uncertainty of the process regarding project withdrawals, suspensions, and the need 

for restudy. 

 

FERC largely accepted the proposed filing, requiring only minor modifications on a few issues, a 

list of metrics to evaluate the effectiveness of the queue reforms, and submission of annual 

reports on the queue changes for the next three years. FERC did rule that the Midwest ISO had 

not provided sufficient evidence to justify the proposed change to how energy resource 

interconnections will be handled. The Midwest ISO asserted that energy resource customers had 

an unfair advantage over network customers because energy resource customers do not have to 

factor in network upgrade costs in submitting energy bids. The Midwest ISO had proposed 

energy resource customers either finance network upgrade to resolve transmission constraints 

and be subject to a cap on output, or enter into an alternative dispatch arrangement with the local 

control area. FERC ruled that the Midwest ISO did not provide adequate justification for their 

proposed changes to the energy resource interconnection service and rejected them without 

prejudice.

 7 Ibid.

8 FERC, “Order Conditionally Accepting Tariff Revisions Addressing Queue Reform,” Docket No. ER08-1169-

000, August 25, 2008.
E-6

The new generator interconnection process uses milestones as the basis for moving 

projects through the queue. The milestone process is divided into four phases (see Figure E-3

below): Pre-Queue (yellow), Application Review (green), System Planning and Analysis (light 

blue), and Definitive Planning (dark blue). There is also an optional study process for projects 

that are not ready to enter the Definitive Planning phase. 

The Pre-Queue phase, which is unlike any phase in the previous process, will provide the 

customer with an overview to the process, timeline, and expectations. Designed to facilitate a 

dialogue between the Midwest ISO and the IC, the Pre-Queue phase includes a variety of 

interconnection education and training materials, contour maps indicating incremental transfer 

capability on the system, and an estimate of the time it will take to proceed through the 

interconnection queue at a given location. The Pre-Queue phase includes project-specific 

meetings and interaction between the Midwest ISO and the IC as well as participation in 

regularly scheduled Midwest ISO public information sessions. As part of the pre-queue phase, 

the IC will collect application data prior to formally submitting the application and 

interconnection request. A non-refundable $5,000 application fee is required at the end of the 

pre-queue phase, along with the submission of the application, in order to achieve milestone one 

(M1) and as a prerequisite to moving to the Application Review phase. Proof of site control, or a 

$100,000 deposit in lieu of site control, is also required at this time. The $100,000 deposit is 

refunded at the time that site control is demonstrated so long as it is prior to the Definitive 

Planning phase. 

The Application Review phase modifies and expands upon the feasibility study required 

under the previous process. This second phase includes review and clarification of the 

application and an initial screening to determine the path the project will take in the 

Figure E-3 – The Midwest ISO Generator Interconnection Process
E-7

interconnection study process. The Application Review milestones (M2) are technical (generator 

and project models, one-line diagrams) and non-technical (deposits and documentation). The 

deposits are scaled based on the size of the project. A Midwest ISO review of prior study costs 

demonstrates that while there is not a linear correlation between study costs and project size, 

there is a step function so that larger projects have higher study costs than smaller projects. There 

is a base level of work for all requests related to running the initial models but as a project 

increases in size, it becomes likely that more costly solutions requiring more complicated 

engineering analysis and design will be required. The Midwest ISO now has eight deposit levels 

(Table E-1) with any unused portions of the study deposit to be refunded should the project 

withdraw prior to entering the Definitive Planning Phase. 

Table E-1

Schedule for Pricing Study Deposits

Paid at Application Review

Project Greater than 

....

(MW)

Project Less than 

or Equal to.... 

(MW)

Deposit Amount

0 6 $10,000

6 20 $20,000

20 50 $30,000

50 500 $60,000

500 1000 $90,000

1000 unlimited $120,000

As part of the Application Review phase, the Midwest ISO will conduct a feasibility 

study to determine whether the transmission system is “ready,” or capable of accommodating the 

interconnection request. The results of the feasibility study will determine if the addition of the 

facility would result in transmission constraints that exceed a pre-determined level. The Midwest 

ISO will evaluate up to three points of interconnection (or voltage levels) as part of the feasibility 

study. Based on the results of the feasibility study, the IC will indentify a single point of 

interconnection and the voltage level to be studied through the rest of the process. 

If constraints fall within a pre-determined level, the system is found to be ready and the 

project will bypass the system planning and analysis studies, instead moving directly to the 

Definitive Planning phase. This typically means that the project is located in a relatively 

unconstrained area and that any minimal transmission upgrades can be resolved in the first stage 

of the Definitive Planning phase. Otherwise, the project will continue through the System 

Planning and Analysis phase where a system impact study will determine the nature of the 

upgrades required for their interconnection prior to entering the Definitive Planning phase 

(Figure E-4). Alternatively, if the feasibility study finds that the constraints are within the 

acceptable limit, i.e., they do not exceed the pre-determined level, and the IC is not ready to 

proceed to the Definitive Planning phase, the IC can request an optional study to get an 

indication of their cost obligation. The scope of the optional study is similar to that of the system 

impact study, but the results are non-binding. Interconnection feasibility studies will be done at 

regular intervals (approximately every six weeks) and timed to allow entry to the scheduled 

Definitive Planning phase process. The milestones that must be completed prior to moving 

beyond the Application Review phase include: 
E-8

1. Complete application and associated application fee,

2. Proof of land/site control or additional deposit, and

3. Applicable study deposits received.

In the System Planning and Analysis phase, a group system impact study (including 

thermal, short circuit, and stability analyses) will be conducted (see Figure E-5.) The study is 

conducted by Midwest ISO staff or consultants to the Midwest ISO, or some combination of the 

two. This phase is similar to the previous system impact studies, except that projects located in 

constrained areas will no longer hold up projects that are not constrained and could otherwise 

move forward. Under the new queue process, group studies will be the default (previously group 

studies were ‘permitted’). The Midwest ISO will assemble study groups at periodic intervals 

based on electrical proximity and common constraint impacts. In the event that a project drops 

out of the queue after being selected as part of a group study, the Midwest ISO will seek to

identify the next eligible, similarly sized project located in the same general area to backfill the 

group study and avoid restudies. The queue position can change throughout the process until the 

project goes into the final Definitive Planning phase. Within a study group, the queue positions 

will be determined based on the order for which the final milestone for each project is met.

Network upgrade costs will be allocated based on the MW impact from each project on the 

constrained facility.

Customer 

Not Ready 

Stop

Optional 

Study 

Figure E-4 – Review Process for Generator 

Interconnection Applications 

The Midwest 

ISO receive 

Interconnection 

Request and 

Deposit

The Midwest 

ISO data 

review, 

clarification, 

and request

System Planning and 

Analysis

Midwest 

ISO

feasibility 

study 

Go To Definitive 

Planning Process

 The Midwest

 ISO Check 

 Customer 

 Readiness 

PreQueue 

Phase
E-9

From 

Application 

Review

Midwest 

ISO

forms 

study 

groups 

Midwest 

ISO and/or 

contractor 

conduct 

studies 

Review 

Study 

Results 

Study 

Group 

Constraint 

Mitigation 

Review

Customer Ready 

Customer Not Ready 

Stop

Proceed to 

Definitive 

Planning 

Phase

Finalize 

Report and 

Customer 

Decision

Entry into the Definitive Planning phase requires satisfaction of additional milestones and 

deposits. All milestones and deposits must be met within 10 days prior to the start of the next 

Definitive Planning phase. If an IC is not prepared, they may sit out one cycle of the Definitive 

Planning phase without having to re-submit an application and re-do the feasibility study. The 

Definitive Planning phase will start on a periodic basis, but specific study window start dates 

have not been defined. To address the problem of restudy costs, the IC is required to pay a 

deposit of twice the expected study costs in the Definitive Planning phase (Table E-2). If the 

project withdraws after entering this phase, the additional study deposit will be used to offset the 

restudy costs of projects lower in the queue that are electrically connected and impacted by the 

withdrawal. Unused portions of the additional deposit would be returned to the IC. Furthermore, 

once an IC has executed an interconnection agreement, it is expected that the project will meet 

the agreed upon construction schedule and project milestones. Suspension of a project is only 

allowed in cases of force majeure, and even then, the IC must put forward a deposit equal to the 

larger of the cost of the network upgrades or $5 million, so that projects within the group and 

placed lower in the queue are not negatively impacted by the suspension. However, the Midwest 

ISO allows up to six months from the completion of the system planning and analysis review and 

the start of the facilities study in the Definitive Planning phase, and another three months after 

the facilities study is completed and before the LGIA is executed, for the IC to address any 

project-specific issues and to market its capacity.

Figure E-5 – System Planning and Analysis
E-10

Table E-2

Schedule for Pricing Study Deposits Paid at Definitive Planning Phase

Project Greater 

than ....

(MW)

Project Less than 

or Equal to.... 

(MW)

Deposit Amount

0 6 $40,000

6 20 $100,000

20 50 $150,000

50 100 $210,000

100 200 $260,000

200 500 $360,000

500 1000 $440,000

1000 unlimited $520,000

Other milestones to enter Definitive Planning phase include a detailed stability model; the 

definitive, final point of interconnection; one-line diagrams showing the facility and associated 

electrical equipment; the definitive capacity size of the project; and recertification of site control 

(see Figure E-6). At this point, if the IC cannot establish site control, they may not enter the 

Definitive Planning phase without losing the $100,000 deposit paid at the time when the 

application was first submitted. After the first stage of the Definitive Planning phase is 

complete, the transmission provider will request the following items, which the interconnection 

customer has 30 days to provide: security for the cost of network upgrades estimated in the 

system planning and analysis review and an execution of a contract for the sale of energy or 

capacity, or notification from the appropriate state agency that the facility is included in a state 

resource plan; and demonstration that turbines have been ordered. Processing the data requests 

quickly and expeditiously meeting the milestones may allow an IC to move up in the queue. 

Figure E-6 – Definitive Planning Process 

Not valid

From Systems 

Planning and 

Analysis 

Negotiate 

Interconn. 

Agreement 

(IA) 

Execute IA 

and 

Construction 

Agreement

Project 

in 

Service

Force Majeure

Suspension: 

Customer Pays for 

Upgrades

Customer Ready 

Customer Not Ready 

STOP

Definitive 

Planning 

Continues 

‘Milestone’

Finalize 

Report and 

Customer 

Decision

From 

Application 

Review

The Midwest 

ISO 

determines 

scope of 

restudy 

The 

Midwest 

ISO

Review 

Systems 

Impact 

Study 
E-11

Move to Clear the Queue and Transition to New Study Process

ICs that have been assigned a queue position prior to the effective date of the revised 

LGIP (August 25, 2008) will retain their queue position. However, in order to maintain their 

position and avoid being removed from the queue, ICs must meet certain minimum 

requirements. Specifically, ICs had 60 days in which to complete their current interconnection 

process, withdraw from the queue, or decide to continue moving forward under the revised study 

procedures according to the process and milestones established in the new LGIP. The ICs also 

had to provide any applicable deposits at the levels required in the revised LGIP within 60 days. 

Should the IC decide to withdraw from the queue, they could do so within the 60-day period 

without penalty. 

Interconnection requests with an executed system impact study agreement that have 

unresolved constraints identified through the current stability and analysis study process will 

have to execute a feasibility study under the revised LGIP, moving back to the Application 

Review phase. Through this process, the IC will need to update the previously submitted 

interconnection request and application to conform to new data and deposit requirements. 

Next Steps

The Midwest ISO Transmission Planning

The recent influx in queue requests is due in part to the development of state RPS 

policies. In the Midwest ISO footprint, seven states currently have RPS policies and one state 

has a renewable energy goal.

9

• Make the benefits of a competitive energy market available to customers by providing 

access to the lowest possible electric energy costs.

 The current RPS policies will create a demand for approximately 

20 GW of new renewable generation in the next 10 to 15 years. Much of this demand will be 

met by the development of new wind power facilities that are typically located in remote regions 

where the transmission system may be weak. Attempts to accommodate the need for planning

regional transmission expansion through the generation interconnection queue have been 

problematic and unsuccessful. Without planning backbone transmission for long-term energy 

delivery needs, the backlogs in the queue will likely continue, even with the queue reform 

process. The Midwest ISO is working to identify transmission projects through a regional 

transmission planning process in order to interconnect remotely located generation resources 

such as wind. The Midwest ISO terms these projects Regionally Planned Generation 

Interconnection Projects (RPGIP).

The Midwest ISO Board of Directors’ planning principles to support the concept of 

regional planning and are stated as follows: 

• Provide a transmission infrastructure that safeguards local and regional reliability.

 9 FERC Renewable Energy Standards, December 5, 2008. http://www.ferc.gov/market-oversight/mktelectric/overview/elec-ovr-rps.pdf .
E-12

• Support state and federal renewable energy objectives by planning for access to all such 

resources (e.g. wind, biomass, demand-side management).

• Create a mechanism to ensure investment implementation occurs in a timely manner.

• Develop a transmission system scenario model and make it available to state and federal 

energy policy makers to provide context and inform the choices they face.

10

The Midwest ISO is currently involved in number of transmission planning activities 

including: reliability (5 to 10 year North American Electric Reliability Corporation (NERC)

Reliability Assessment), targeted studies (Narrowly Constrained Areas, Regional Generation 

Outlet, ITC 765, Southwestern Indiana Economic Transmission); and long-term (the Midwest 

ISO Transmission Expansion Plan, Joint Coordinate System Plan).

The Midwest ISO’s Transmission Expansion Planning (MTEP) is done on overlapping 

annual and biennial cycles. The fourth regional expansion plan, MTEP-07, was approved by the 

Midwest ISO Board of Directors in February 2007.11

• Perform reliability assessment of the Midwest ISO integrated transmission system

 The three primary objectives of the MTEP 

are:

• Review transmission owning members transmission plans and make sure that appropriate 

projects are reviewed and recommended to the Midwest ISO Board of Directors for 

approval

• Develop transmission plans to improve market performance

MTEP-08, which the Midwest ISO Board of Directors approved in December 2008, includes 

evaluation of four distinct economic futures (reference, environmental, renewable, and limited 

fuel). The renewable future is based on an assumption that 20 percent of the Midwest ISO 

region’s energy resources will come from wind power.

Furthermore, the Midwest ISO launched the Regional Generation Outlet study in April 

2008 to identify near and mid-term regional transmission requirements needed to support 

renewable energy standards in the Midwest ISO footprint.12

 10 Planning Objectives Discussion, Midwest ISO Panning Advisory Committee meeting, December 5, 2007. 

 A key objective of this study is to 

identify specific transmission facilities (i.e., regionally planned generation interconnection 

projects) which can be recommended to the Midwest ISO Board for approval in the MTEP-09. 

A second phase of this work will focus on current lack of The Midwest ISO-wide consensus on 

appropriate cost allocation for transmission facilities driven by state renewable energy policies.

http://www.midwestiso.org/publish/Document/5d42c1_1165e2e15f2_-7ee80a48324a?rev=1. 11 MISO Transmission Expansion Planning, http://www.midwestiso.org/page/Expansion+Planning. 12 MISO Regional Generation Outlet study, http://www.midwestiso.org/publish/Folder/6871db_117a25bcaa6_-

798d0a48324a.
F-1

F. NEW YORK INDEPENDENT SYSTEM OPERATOR1

The New York Independent System Operator (NYISO), a not-for-profit corporation 

established in 1999, operates New York’s bulk electricity grid, administers the state’s wholesale 

electricity markets, and provides reliability planning for the state’s bulk electricity system. Like 

other RTOs and ISOs, the NYISO has seen an increase in the number of interconnection requests 

submitted since the Standard Large Facility Interconnection Procedures (LFIP) went into effect 

in August 2004. During 2005, the NYISO received 47 interconnection requests, 30 of which 

remained in the queue. In 2006, 35 additional requests were received by the NYISO, 25 of which 

remained in the queue. And in 2007, the NYISO received 38 additional requests, 31 of which 

remained in the queue. Of the 120 total interconnection requests received by the NYISO from 

2005 through 2007, 75 (62.5 percent) were for wind generation projects.

As of April 15, 2008, NYISO’s interconnection queue contained 138 separately queued 

projects, representing more than 26,000 MW of proposed generation and 5,820 MW of proposed 

transmission.

Generator Interconnection Queue Process2

Within five days following the meeting, the IC must specify the desired point of 

interconnection and any reasonable alternative points. NYISO will then provide the 

interconnection feasibility study agreement (IFSA) containing a good faith cost estimate for 

completion. The IC has 30 days to execute the IFSA and provide a $10,000 deposit along with 

all required technical data. NYISO will use all reasonable efforts to complete the study within 45 

NYISO receives, processes, and analyzes interconnection requests, assigns queue 

positions to interconnection customers (IC), and then works with the affected transmission 

owners to complete the required interconnection studies. 

Interconnection Request

An IC begins by submitting an interconnection request along with a $10,000 deposit, 

demonstration of site control or an additional $10,000, and all the required data. A separate 

interconnection request must be submitted for each site but an IC may submit multiple requests 

for a single site if, for example, the IC wishes to have the same site evaluated at different voltage 

levels. NYISO assigns the queue position based on the date and time of receipt of the valid 

completed interconnection request. A scoping meeting will be held within 30 days at which time 

the parties will discuss alternative interconnection options and potential feasible points of 

interconnection.

Interconnection Feasibility Study

 1 The New York ISO declined to review this appendix. The information presented here is based on the authors’ 

understanding of the New York ISO’s generator interconnection procedures. 

2 Information in this section: New York Independent System Operator, Inc., “Standard Large Facility 

Interconnection Procedures,” FERC Electric Tariff, last updated: July 1, 2008. Accessed August 25, 2008.
F-2

days. If a higher queued project drops out of the queue, or if some other modification is made, 

NYISO may determine that a re-study is necessary. The IC is responsible for all costs associated 

with a re-study. NYISO, the transmission owner, and the IC may agree to forego the feasibility 

study, in which case NYISO will initiate an interconnection system reliability impact study to 

which the $10,000 deposit will be applied.

Interconnection System Reliability Impact Study 

Following the feasibility study results meeting (or if the feasibility study has been 

waived), NYISO shall provide an interconnection system reliability impact study agreement

(ISRISA). The IC must execute the agreement within 30 days and provide a $50,000 deposit 

along with demonstration of site control. The impact study consists of a short circuit analysis, a 

stability analysis, and a power flow analysis and will ultimately provide a list of facilities that are 

required because of the interconnection request. The NYISO will utilize existing studies to the 

extent practicable when it performs the study. NYISO reserves the right to study interconnection 

requests serially, or in clusters, for the system reliability impact study. Clustering will be 

implemented based on queue position with NYISO including requests that were received within 

a period not to exceed 180 days. NYISO will make every reasonable effort to deliver the 

completed impact study within 90 days of receipt of the agreement or within 90 days of the close 

of the queue cluster window if clustering is used. 

Interconnection Facilities Study

Interconnection facilities studies (IFS) in NYISO are coordinated with the Annual 

Transmission Reliability Assessment (ATRA). ICs included in each ATRA are referred to as 

being studied in that “class year” and ICs with IFS agreements made prior to the start of the 

ATRA are included in the class year studies (discussed in more detail in the next section). Thirty 

days prior to the start of date of the ATRA, NYISO provides IFS agreements to “eligible 

developers” who have not already received an agreement for the next class year. An eligible 

developer refers to an IC that (1) has not been in a prior class year and satisfies the criteria for 

inclusion in the ATRA, or (2) has been in a prior class year and NYISO assigned the project to 

the next class year or, the IC had elected to enter the next class year. The IC must execute the 

agreement by (1) the start date of the ATRA or (2) within 30 days following receipt of the 

agreement, whichever is the later date. The IC must provide all required technical data and 

$100,000, or the IC’s portion of the estimated monthly cost of the study, whichever is greater. As 

was the case with the system reliability impact study, NYISO will utilize existing studies to the 

extent practicable when it performs the class year facilities study.

Engineering and Procurement Agreement

The Engineering and Procurement (E&P) agreement authorizes the transmission owner to 

begin engineering and procurement of long lead-time items necessary for the establishment of 

the interconnection. The E&P agreement is an optional procedure and will not alter the IC’s 

queue position or in-service date.
F-3

Optional Interconnection Study 

When an IC initiates an interconnection system reliability impact study, they may also 

request that NYISO perform a reasonable number of concurrent optional studies. Any optional 

studies performed are solely for informational purposes. NYISO will provide the IC with an 

optional interconnection study agreement that will:

• Specify the technical data that the IC must provide for each phase of the optional study;

• Specify the IC’s assumptions as to which interconnection requests with earlier queue 

priority dates will be excluded from the optional study case; and

• NYISO’s estimate of the cost of the optional study.

Standard Large Generator Interconnection Agreement 

NYISO and the transmission owner(s) will offer the developer a draft standard LGIA. 

Following execution of the facilities study agreement and at the request of the IC, NYISO and 

the transmission owner(s) may begin negotiations with the IC on the LGIA and its appendices. 

Upon completion of the negotiation process, the final LGIA is provided to the IC within 15 

business days. Within 15 business days of receiving the final LGIA, the IC must provide NYISO 

and the transmission owner(s) either reasonable evidence of continued site control, or an

additional, non-refundable $250,000 deposit which will be applied to future construction costs. 

NYISO Initiatives to Address Interconnection Queuing Issues

NYISO is experiencing some delays in the completion of interconnection studies because

of the more involved study process coupled with the substantial growth in the number of projects 

in the queue. Further complicating the processing of pending interconnection requests are the 

frequent requests from ICs to modify their project proposals. NYISO has found that the pro 

forma technical requirements and the detailed base case requirements contained in the tariff do

not allow it to customize the interconnection study to a particular project.

Rather than modifying the interconnection queue process itself, NYISO has made 

changes to how it administers the interconnection queue. When the LFIP went into effect, 

NYISO restructured its planning department to create a group dedicated to processing 

interconnection requests. Additional administrative and technical personnel were hired to support 

the work of this new group. Even with a more robust staff, NYISO has had to expand its use of 

outside consultants and often requests individual transmission owners to perform portions of the 

interconnection studies as the sheer volume of work generated by the interconnection requests is 

more than NYISO can handle in-house. 

On top of the staffing increases and use of consultants, NYISO conducted a 

comprehensive study of the administrative processes required under the LFIP. Specific process 

improvement measures were identified that have allowed NYISO to expedite the scheduling of 

scoping meetings for projects entering the interconnection queue. The process improvement 

measures include:
F-4

1. NYISO will provide the IC with an unexecuted version of the IFSA within five 

days of receipt of the IC’s designation of the point of interconnection,

2. NYISO and the transmission owner(s) will execute the IFSA within 30 days of its 

receipt by the IC, and

3. NYISO and the transmission owner(s) will execute the ISRISA within 30 days of 

its receipt by the IC.

Finally, in 2005, NYISO and the New York State Energy Research and Development 

Authority completed a joint study that evaluated the ability of the New York Control Area’s 

transmission infrastructure to support installed wind generation up to 3,300 MW. The study is 

currently being updated to evaluate the impact of higher levels of wind generation on the 

transmission system by load zone. The updated study will focus on four primary issues: (1) 

performance evaluation of wind generation; (2) a centralized wind forecasting system for greater 

than 3,300 MW; (3) operating and planning strategies; and (4) reviewing market risk changes to 

accommodate wind energy. The anticipated completion date for the study update is December 

31, 2008.

NYISO Clusters: The Class Year Facilities Study

NYISO has had a form of clustering in place since FERC approved its open access 

transmission tariff (OATT) in 2004. Attachment S of the NYISO OATT outlines detailed 

procedures to allocate the costs of network upgrades amongst a group of proposed projects 

known as a ‘class year’. Under Attachment S, NYISO conducts an annual transmission reliability 

assessment to identify the network system upgrades required for all generation and merchant 

transmission projects that are included in a class year cluster. Each project in a class year shares 

in the then currently available electrical capability of the transmission system and each is 

allocated a share of the cost of the network system upgrades based on the pro rata impact of its 

project.

When submitting its compliance filings with Order No. 2003, NYISO expanded the study 

performed under Attachment S to a clustered interconnection facilities study. For a project to 

enter a class year, it must satisfy two milestones by March 1 of that year. 3

1. The project must have a tariff-compliant interconnection system reliability impact study 

that has been approved by NYISO’s operating committee.

2. The project must satisfy a “regulatory” milestone that indicates progress towards 

obtaining the necessary environmental permits or approvals. The applicable regulatory 

milestone depends on the nature of the project; however, satisfying the milestone 

demonstrates that a significant step in project development has been completed.

 3 New York ISO, “Status Report of the New York Independent System Operator, Inc., on Interconnection Queuing 

Issues,” Docket No. AD08-2-000, April 21, 2008. 
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Eligibility for a class year is not limited to the strict first-come, first-served constraints of an 

interconnection request’s queue position. Once a project receives its assigned cost allocation, it 

must decide, within a specified period, whether or not to accept it. A project that accepts its cost 

allocation must post security in the full amount of its allocated share before moving onto an 

interconnection agreement. Pending certain limitations, a project that does not accept its cost 

allocation responsibilities may remain in the queue and enter a subsequent class year.

Two components of the class year process have aided in the administration of the 

interconnection queue. First, requiring that ICs meet two milestones before entering the class 

year allows them to move through the interconnection process at different speeds, regardless of 

the relative queue position of its interconnection request or status of projects ahead of it in the 

queue. Second, requiring that an IC post security at the completion of the class year facilities 

study provides ICs some level of certainty regarding their system upgrade costs, while 

minimizing the likelihood that one project’s costs could increase as a result of another project 

dropping out after the study is complete.

FERC Order No. 2003 Compliance

NYISO’s LFIP was approved by FERC and went into effect on August 6, 2004. While 

the LFIP by and large follows the pro forma procedures under Order No. 2003, they did retain 

NYISO’s cost allocation process that allows NYISO to evaluate network upgrades required by 

generators on a system-wide basis. The cost allocation process is a type of cost clustering,

through which NYISO conducts a facilities study for a group of projects, the class year for each 

ARTA, identifies the total network system upgrades required to interconnect the new facilities 

reliably, and then allocates the cost of those upgrades amongst the class year members according 

to each project’s contribution.

Additional Proposed Reforms

Through an internal process, NYISO identified areas within both the LFIP and 

Attachment S that could be improved through tariff amendments. The proposed amendments will 

be brought through the NYISO stakeholder process. They include, but are not limited to:

1. Clarifying the interconnection request form to streamline the process of obtaining 

required data from developers;

2. Modifying base case requirements for interconnection feasibility studies and system 

reliability impact studies to allow for the increased use of “off-the-shelf” base cases;

3. Eliminating unnecessary analysis now called for under Attachment S by making the IC

responsible for the increased costs of network system upgrades caused by a change to the 

design or operating characteristics of its own project and for costs for items outside the 

scope of the class year facilities study; and

4. Establishing clear metrics for identifying and removing speculative projects.
F-6

NYISO has begun working with stakeholders to review and identify additional tariff 

modifications that will improve the interconnection study process. It is anticipated that the 

discussions will eventually lead to a tariff filing under Section 205 of the Federal Power Act to 

reform NYISO’s interconnection study process.
G-1

G. PJM INTERCONNECTION

As with other RTO and ISO queues, PJM’s generation interconnection requests have 

grown in the last few years. In 2005, PJM received a total of 116 generator interconnection 

requests worth approximately 18,000 MW, 66 of which were for wind projects representing 

6,300 MW. In 2006, PJM received 146 requests worth 31,000 MW, with 60 of those for wind 

projects worth 8,000 MW. PJM received 170 interconnection requests in 2007 representing 

almost 38,000 MW of generation; 57 of these were for wind projects worth 22,871 MW. By the 

end of 2007, PJM had 355 requests in various stages of study and construction in their queue, 

representing over 74,000 MW of generation, with wind power projects accounting for 162 

requests worth over 35,000 MW.1

Queue Process

PJM’s existing capacity at the end of 2007 was approximately 

165,000 MW.

2

Through 2007, the PJM generator interconnection process utilized a form of time-based 

clustering. PJM previously conducted studies (in groups) twice a year following a six-month 

application window. In November 2007, PJM submitted a filing to FERC requesting to change 

the twice-yearly cluster windows to four times per year.3

The interconnection process begins with the filing of an interconnection request. The IC 

must provide a fully completed feasibility study agreement along with the required project data. 

PJM’s deposit requirement used to be $10,000, but has recently been increased to values that are 

commensurate with the size of the project and the timing of the application. ICs are required to 

provide a non-refundable deposit of $10,000 for requests made during the first month of the 

cluster window; $20,000 for requests made during the second month; and, $30,000 for requests 

made in the last month. Additionally, ICs are required to provide an initial per MW deposit that 

will be credited towards feasibility study costs. The study deposit is $100 per MW for requests 

This change was approved by FERC 

via letter order in January 2008. The windows for receiving applications now run from February 

1st to April 30th, May 1st to July 31st, August 1st to October 31st, and finally November 1st to 

January 31st of the following year. Additionally, the feasibility study phase was extended from 

60 days to 90 days in the filing and, thus, begins on the first day of the month following the close 

of the cluster window. This cluster window system feeds into the PJM Regional Transmission 

Expansion Planning (RTEP) process. Generator interconnection requests are studied in 

geographically arranged clusters within each time-based window. PJM allows interconnection 

customers (IC) to request that their projects be put on suspended status for a maximum 

cumulative total of three years, but only after the execution of an Interconnection Construction 

Service Agreement.

Feasibility Study

 1 All interconnection data taken from PJM published queue. 2 Information in this section from: System Planning Division, “PJM Manual 14B: PJM Regional Planning Process,” 

PJM, October 2007 and PJM Open Access Transmission Tariff Effective 10-8-08. Accessed October 29, 2008. 

http://www.pjm.com/documents/downloads/agreements/tariff.pdf

3 PJM Interconnection, “PJM Interconnection, L.L.C., Docket NO. ER08-280-000,” November 30, 2007.
G-2

made in the first month; $150 per MW for requests made in the second month; and, $200 per 

MW for requests made in the final month. The IC is then assigned a queue position within the 

current interconnection window. When the window closes, the projects that received queue 

positions in that time period are studied in clusters. The feasibility studies for that window are to 

be completed within 90 days of the beginning of the study cycle (May 1st for the window closing 

April 30th). The feasibility study consists of a rough approximation of the transmission related 

costs for each project. Upon completion of the feasibility studies, PJM will conduct scoping 

meetings with each IC, presenting the results. An IC then has 30 days to decide to move forward 

with the project by filing a completed system impact study agreement.

In addition to the increased deposit requirements, PJM will conduct initial scoping 

meetings with all ICs. Scoping meetings will be held within 45 days for requests received within 

the first month of the cluster window; within 30 days for requests in the second month; and, 

within 20 days for requests in the last month. At the scoping meeting, an IC can identify two 

potential points of interconnection for their project, a primary and a secondary. The primary 

point of interconnection will be used for the feasibility study and the secondary point will be 

used to conduct a sensitivity analysis. An IC will then have the option to use either the primary 

or secondary point of interconnection in the system impact study phase. If an IC fails to attend 

the scoping the meeting and provide the necessary information, or inform PJM of its desire to 

waive the scoping meeting, PJM will consider the request withdrawn.

System Impact Study

If an IC wishes to proceed with the project, it must provide the system impact study 

agreement, all required data, proof of initial applications for any required air permits for the 

project, and a $50,000 deposit. If the IC fails to provide the above within 30 days following the 

date at which PJM issued the feasibility study results, PJM will consider the request withdrawn. 

Clustered impact studies are conducted for all projects opting to continue during the next study 

cycle, beginning 30 days following the end of the feasibility study phase for each cluster. PJM 

aims to complete the impact studies within 120 days of the start date, but if this is not possible, 

PJM will contact ICs and inform them of the new anticipated completion date. The system 

impact study is a comprehensive regional analysis of the impact of adding all the new generation 

projects within the cluster study window to the PJM system. The study will identify all necessary 

generator attachment facilities, local upgrades, and general network upgrades, along with 

estimates of the costs involved and the allocation of those costs. 

Once the impact studies are completed, PJM will inform the ICs of the results. ICs then 

have 30 days to request up to two optional studies if they require more information to make a 

decision to continue. Within 30 days of receiving the final study results, the ICs must execute a 

facilities study agreement with PJM, along with a deposit of $100,000 or the estimated amount 

of the IC’s costs for the first three months of study work, whichever is greater. PJM will then 

determine if there is a need to conduct updated impact studies, taking into account any project 

withdrawals. The final results of the impact study cycle are then rolled into the annual RTEP 

process for inclusion in the RTEP plan that is submitted to the PJM Board of Managers for 

approval.
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Interconnection Facilities Study

The final stage consists of detailed facilities studies for the set of projects within each 

time-based window that have elected to continue through to the interconnection phase. The 

facility studies will provide details of the engineering design work required to construct 

transmission facilities. The study will also outline PJM’s good-faith estimate of the cost 

responsibilities of each participant and the time required to complete each project’s required 

facilities and upgrades. Cost responsibility as allocated through the facilities study and the RTEP 

process identifies two types of costs:

1. Direct connection attachment facilities – the equipment required for the generator to 

get to the point of interconnection with the PJM grid. All direct connection facilities 

costs are borne by the particular generation project.

2. Network reinforcements – these are all the grid upgrades required to accommodate 

the new generation from all the projects in the plan. Project owners are subsequently 

reimbursed for these costs through the receipt of firm transmission rights. Cost 

allocations for network upgrades are based on the cost for resolving reliability issues 

associated with the generation projects. If the cost of the network upgrades for 

resolving any single reliability violation is estimated to be less than $5,000,000, then 

all costs are allocated amongst the projects in each geographic study cluster according 

to the percent impact that each project contributes to network upgrade requirements. 

If the cost of network upgrades associated with any single reliability violation is 

estimated to cost greater than $5,000,000, then: 

i. The transmission providers must identify the first project that triggers the 

additional cost.

ii. Costs for the relevant network upgrades are then allocated to that first 

project and all the projects following it in the interconnection queue, 

according to their pro rata contribution.

Interconnection Service Agreement and Construction Service Agreement

Following completion of the study stages, an IC has 60 days to execute an 

interconnection service agreement. This must include a letter of credit or other form of security 

in an amount equal to the estimated costs allocated to their project and all required technical 

data. Additionally, ICs must demonstrate that the following have been obtained:

• Fuel and/or water delivery agreement if needed;

• Control of rights-of-way for fuel and/or water connections if needed;

• Any local, county, state site permits required; and

• Signed memoranda of understanding for major equipment.

If an IC disagrees with the terms in their interconnection service agreement, or is unable 

to negotiate terms in the agreement which are acceptable to all parties, they may request to have 

an unexecuted service agreement filed with FERC, or may request initiation of a dispute 
G-4

resolution process. Coincident with or following the execution of the service agreement, the IC 

must execute a construction service agreement within 90 days of receiving the agreement for 

execution, if PJM and the affected transmission owner(s) determine that such an agreement is 

necessary. Execution of a construction service agreement will allow work to commence on the 

engineering, design, and construction of the required facilities. PJM allows an IC to design, 

construct and install some portions of the required transmission facilities if the IC and the 

transmission owner(s) can reach agreement on the terms of this construction under the ‘option to 

build’.

Wind Interconnection and Capacity Status

PJM allows ICs to choose whether they wish to be considered an energy-only resource or 

a capacity resource. Capacity resources are subsequently allowed to participate in PJM’s 

capacity market. Study requirements and the upgrades developed for the two types of resources 

differ, dependant upon the reliability requirements associated with each type of resource and, 

hence, costs may be different. PJM allows wind power projects to apply for capacity resource 

status and then models new wind projects with a class average capacity value, currently set at 13 

percent. The class average capacity value for wind is determined annually by the collection 

capacity factor of wind generation in PJM between the hours of 2 p.m. to 6 p.m., inclusive, 

between June through August. A wind project may request a different capacity factor be used if 

adequate supporting data can be provided.4

Proposed Reforms5

1. A $20,000 non-refundable deposit plus $100 per MW, maximum $120,000.

The PJM Regional Planning Process Working Group (RPPWG) is examining further 

reforms to the interconnection process. For example, a reform under discussion is an increase to 

the system impact study deposit that would link it to the size of the project. Options presented 

have included: 

2. A $30,000 non-refundable deposit plus $300 per MW, maximum $300,000.

Additionally, the RPPWG is examining changes to the facility study aimed at moving 

projects faster through the planning process, adding milestones to demonstrate financing, 

including a non-refundable deposit based on project size, and providing a higher level of 

certainty. The specifics of these changes are still under discussion and are subject to change. 

FERC Order 2003 Compliance

The PJM interconnection process mostly follows Order 2003 standards, adapting them 

for the particular form of clustering that fits with the PJM regional planning process. 

 4 System Planning Department, “PJM Manual 21: Rules and Procedures for Determination of Generating 

Capability,” PJM, April 2008.

5 PJM Regional Planning Process Working Group materials. Accessed December 3, 2008. 

http://www.pjm.com/committees/working-groups/rppwg/rppwg.html
H-1

H. SOUTHWEST POWER POOL1

The Southwest Power Pool (SPP) is an RTO designed to ensure reliable supplies of 

power, adequate transmission infrastructure, and competitive wholesale prices of electricity. SPP 

has members in nine states—Arkansas, Kansas, Louisiana, Nebraska, Mississippi, Missouri, 

New Mexico, Oklahoma, and Texas—for which it oversees compliance enforcement and 

reliability standards development. SPP has experienced significant increases in new 

interconnection requests in the last two years. At the end of 2007, there were 128 projects 

representing 30,129 MW in the queue. As of July 22, 2008, there were 205 active generator 

interconnection requests, which represent a 64 percent increase as compared to 2007. Those 205 

generator interconnection requests amount to almost 51,143 MW (see Table H-1).

Nearly 85 percent of the projects in the queue are renewable energy projects. Of these, 

all but one of the renewable energy projects are wind projects. The projects are fairly evenly 

distributed among Kansas, Missouri, New Mexico, Oklahoma, and Texas. Just two of the 

states—New Mexico and Texas—have a renewable portfolio standard, and may not directly 

account for the drastic increase in projects. The significant increase in wind projects may more 

directly be attributed to uncertainty in the availability of the federal production tax credit and 

above-average wind resources within the SPP footprint.

Table H-1 – SPP Interconnection Queue2

No. of 

Projects MW

Feasibility Study Requested 89 26,564.1

Feasibility Study Completed or In-Progress (1) 25 6,835.2

Active Projects in Impact Study Stage (Completed or In-Progress) 13 2,455.0

Active Projects in Facility Study Stage (Completed or In-Progress) 13 2,485.2

Active Projects – Interconnection Agreement (IA) Pending 10 2,367.5

Active Projects – IA Fully Executed (Commercial Operation, 

On Suspension, On Schedule) 53 10,035.9

Active Wind Projects in the Queue 174 42,941.1

Active Other Renewable Projects in the Queue 1 16

Active Projects in the Queue – Total 205 51,142.9

Compliance with FERC Order No. 2003

SPP was granted preliminary RTO status on February 10, 2004, and final RTO status on 

October 1, 2004. Their compliance filing (i.e., Order No. 2003) was accepted by the FERC on 

June 21, 2004. SPP’s LGIP, established in compliance with FERC Order 2003, consists of a 

 1 The Southwest Power Pool was unable to provide review comments. The information presented here is based on 

the authors’ understanding of the Southwest Power Pool’s generation interconnection procedures. 

2 As of July 22, 2008.
H-2

centralized study process. Each proposed project is reviewed and analyzed, with respect to the 

other projects earlier in the queue, to assess the impact on the regional transmission system.

Generation Interconnection Queue Process3

 3 Information in this section from: Southwest Power Pool, “Open Access Transmission Tariff for Service Offered by 

Southwest Power Pool: Attachment V, Standard Large Generator Interconnection Procedures,” FERC Electric Tariff 

with revisions approved through December 1, 2008, accessed December 3, 2008.

SPP coordinates the generation interconnection process and oversees the study 

requirements on behalf of the transmission providers in its jurisdiction. Under the LGIP and 

LGIA tariffs, the SPP serves as the primary coordinator of analytic activities; however, the 

studies themselves may be performed by SPP, transmission owners, or external contractors. 

While SPP’s generation interconnection process is structured such that the projects higher in the 

queue are analyzed first, if an interconnection customer (IC) fails to meet designated timelines 

during the process, their queue position will be deemed withdrawn by SPP.

The SPP tariff contains provisions for SPP to perform cluster studies but to date, SPP has 

opted to use a serial study format. In its current form, SPP’s sequential queue process consists of 

the following:

Interconnection Request

An IC submits an interconnection request along with a refundable $10,000 deposit and 

demonstration of site control or an additional $10,000. The request must specify the type of 

interconnection desired: energy resource or network service. A scoping meeting will be held at 

which time a point of interconnection and feasible alternative points will be discussed. SPP will 

assign the IC a queue position based on the date and time the interconnection request was 

complete.

Interconnection Feasibility Study

Following the scoping meeting, SPP will provide a feasibility study agreement with a 

cost estimate for completion. The IC has 30 days to execute the agreement and provide the 

required data along with a $10,000 deposit. The IC and transmission owner(s) may choose to 

forego the feasibility study, in which case the $10,000 deposit will be applied to the costs of the 

system impact study. SPP will use reasonable efforts to complete the study within 45 days.

Interconnection System Impact Study

Within three days following the feasibility study results meeting, SPP will provide a 

system impact study agreement along with a cost estimate and time frame for completion. The IC 

has 30 days to execute the agreement along with demonstration of site control and a $50,000 

deposit. SPP will use reasonable efforts to complete the study within 90 days.
H-3

Interconnection Facility Study

Within three days following the impact study results meeting, SPP will provide a 

facilities study agreement along with a good faith estimate of the cost and timeframe for 

completion. The IC has 30 days to execute the agreement and provide the required technical data 

along with a $100,000 deposit or the IC’s portion of the estimated monthly cost of the study, 

whichever is higher. SPP will use reasonable efforts to complete the study within (1) 90 days at 

+/- 20 percent of cost or (2) 180 days at +/- 10 percent of the cost, as requested by the IC. If a 

higher queued project drops out of the queue, or if modifications are made to a higher queued 

project then a re-study is required. SPP will notify the IC in writing of such a requirement and 

any associated costs shall be borne by the customer.

Engineering & Procurement Agreement

This is an optional agreement that allows a transmission owner to begin engineering and 

procurement of long lead-time items.

Large Generator Interconnection Agreement

Following the results meeting and any needed negotiations, the IC must execute an LGIA 

and provide evidence of continued site control or post $250,000 non-refundable additional 

security. The IC must also provide evidence that one or more of the following (as applicable) has 

been achieved:

• Execution of a contract for supply or transportation of fuel.

• Execution of a contract for cooling water.

• Execution of a contract for engineering for, procurement of major equipment for, 

or construction of, the facility.

• Execution of a contract for the sale of electric energy or capacity from the facility.

• Application for air, water, or land use permits.

SPP’s Proposed Revisions to the Queue Process4

 4 Information in this section from: SPP Generation Queuing Task Force Documents, accessed December 3, 2008. 

In early 2008, SPP formed the Generation Queuing Task Force (GQTF) whose mission is 

to accelerate the processing of large generator interconnection requests. The GQTF consists of 

transmission owners, renewable developers and marketers, and SPP staff. The group began 

meeting monthly, both in-person and via conference call, in March 2008. The existing queue 

process will be revised to consist of milestones that generators will have to meet before moving 

forward; essentially moving away from a first come, first served approach to a queue 

management approach. In addition, SPP plans to propose significant increases in required 

deposits and other associated fees. These proposed reforms are currently in the final approval 

phases at SPP, and SPP plans to submit a proposed tariff amendment to FERC by March 2009.

http://www.spp.org/section.asp?group=1227&pageID=27
H-4

The proposed interconnection procedure contains a Pre-Application Phase, an 

Application Review Phase that contains sets of milestones and three different queues depending 

on which study stage the project is in, and a final Facilities Study Phase. 

1. Pre-Application Phase

This is an optional phase where SPP will provide all the required information to an IC

that wishes to perform their own feasibility study. A non-disclosure agreement will be 

required.

2. Application Review Phase

This phase contains three different queues and depending on which set of milestones an

IC meets, the IC will be placed in one of the following three queues:

(1) Feasibility Study/Screening Process

An IC may submit a request for an optional feasibility study. Feasibility studies 

will be performed once every three months for the requests received during a 

three-month window. The IC does not receive a binding queue number but will be 

assigned to the Feasibility Queue. ICs must meet Milestone Set 1: $10,000 

deposit and basic study materials.

(2) Preliminary Impact Study

ICs will be able to submit a request during a six-month window and will be 

assigned a Preliminary Planning Queue number. ICs must meet Milestone Set 2: 

• Deposit based on project size:

o Less than 100 MW – $40,000 

o Between 100 MW and 800 MW – $60,000

o Greater than 800 MW – $90,000

• Documentation of site control.

• Detailed study data.

(3) Definitive Planning Process

ICs that are able to meet a more inclusive set of milestones can proceed straight to 

this stage that will begin every six months. Under this process, ICs will be 

assigned to the Definitive Planning Queue. ICs must be able to meet Milestone 

Set 3 as listed below:

• Study Deposit based on project size:

o Less than 75 MW – $75,000

o Greater than 75 MW – $150,000

• Definitive point of interconnection.
H-5

• Definitive plant size in MW. No decrease in plant capacity is allowed after 

the study is completed.

• Site control.

• Detailed study materials.

• Additionally, one of the following milestones must be met:

o Security equal to $2,000/MW of the plant size (refundable at a 

commercial operation or withdrawal). 

o A power purchase agreement or similar hedge type agreement, or 

a signed statement attesting that the project is included in an 

applicable state resource plan, or other information to indicate the 

project will qualify as a designated network resource in SPP.

o A purchase order for generating equipment specific to project in 

the queue position (not a blanket order) or a signed statement 

attesting the facility is included to be supplied with turbines.

o Application for an air permit.

o Application for a Federal Aviation Administration permit.

3. Facility Study Phase 

An IC must have progressed through to the Definitive Planning Phase to be eligible for a 

facilities study. The IC has 30 days after receiving the definitive impact study results to 

meet one of the milestones in Milestone Set 4. If this cannot be accomplished, the request 

will be withdrawn and the IC must re-enter the process at the next Definitive Planning 

window. The list of milestones in Milestone Set 4 is as follows:

• Letter of credit or payment for estimated network upgrades.

• A power purchase agreement or similar hedge type agreement, or a signed 

statement attesting that the project is included in applicable state resource plan, 

or other information to indicate the project will qualify as a designated network 

resource in SPP.

• A purchase order for generating equipment specific to the project in the queue 

position (not a blanket order) or a signed statement attesting the facility is 

included to be supplied with turbines.

• Application for an air permit.

• Application for a Federal Aviation Administration permit.

Upon completion of the Facility Study Phase, the IC is provided a draft standard LGIA 

with appendices, at which time it has 60 days to negotiate with SPP and the transmission 

owner(s). SPP plans to continue to allow ICs to suspend processing of their queue application for 

a cumulative period of up to 18 months after completion of the Facility Study Phase, but ICs will 

still be required to pay for their allocated cost of shared network upgrades. 
I-1

I. WESTERN AREA POWER ADMINISTRATION

Western Area Power Administration is a Federal agency that markets and delivers 

reliable, cost-based hydroelectric power and related services within a 15-state region of the 

central and western U.S. Its role is to transmit electricity from multi-use water projects, which 

includes 57 power plants operated by the Bureau of Reclamation, U.S. Army Corps of Engineers 

and the International Boundary and Water Commission. Together, these plants have an installed 

capacity of 10,395 megawatts.

In order to fulfill its role, Western owns and operates more than 17,000 miles of 

transmission lines that are used to deliver federal power on a project-specific basis to preference 

customers throughout its 1.3 million square mile region. Some of Western’s transmission 

facilities are interconnected to project-specific transmission and distribution facilities, for 

example large federal facilities, and others are interconnected to third party transmission lines, 

for example utility transmission systems that step down to distribution lines for delivery of retail 

power. 

Western’s transmission system overlays nine of the 10 windiest states in the nation, 

leading to increased interconnection requests by wind power developers. As of January 2008, 

Western had already interconnected 305 MW of wind, with more than 69 additional study 

requests in the queue, totaling more than 14,000 MW of renewable generation. Representative 

projects include an 8.3 MW wind farm in Wyoming to a 50 MW wind farm in South Dakota. 

Western also receives two to three interconnection requests from larger fossil fuel-fired facilities 

each year. As with other transmission providers, recent increases in interconnection requests 

have strained Western’s system planning resources. Western is currently evaluating its 

interconnection process. 

Western is not a public utility subject to FERC jurisdiction under Sections 205 and 206 of 

the Federal Power Act.1

While not a public utility subject to FERC Order 888, Western is a transmitting utility

subject to Sections 211-213 of the Federal Power Act which grants authority to FERC regarding 

the interconnection and wheeling of electric power. Order No. 2003 provides that nonjurisdictional utilities (such as Western) that wish to maintain safe-harbor open access tariffs 

It is therefore not subject to the open access requirement of Order Nos. 

888 and 2003, which are broadly applicable to public utilities. Western does voluntarily file an 

OATT with the FERC under the safe harbor reciprocity conditions provided through Order No. 

888. Under this procedure, Western may voluntarily submit to FERC a transmission tariff and a 

request for a declaratory order that the tariff meets the FERC comparability (nondiscrimination)

standards. If FERC finds that such a tariff contains terms and conditions that substantially 

conform or are superior to those in the pro forma OATT contained in Order No. 888, and the 

LGIA and LGIP pro forma tariffs provided in Order No. 2003, FERC will deem it to be an 

acceptable reciprocity tariff and will require public utilities to provide open-access transmission 

service upon request to that particular non-public utility. This reciprocity is necessary to deliver 

power to some federal power customers without a direct interconnection to Western’s system. 

 1 Sections 205 and 206 are specific to issues related to rates and charges and the power of FERC to regulate rates 

and charges. 
I-2

must adopt an LGIP and an LGIA that “substantially conforms to or are superior to” FERC’s pro 

forma documents. Subsequently, on January 26, 2005, Western filed revisions to its nonjurisdictional open access transmission tariff to incorporate changes to the LGIP and LGIA to 

conform, as much as possible, to the pro forma tariffs provided in FERC Order No. 2003. 

However, as a federal government entity subject to the laws and provisions that regulate the 

operation and administration of government agencies, Western is not able to comply with 100 

percent of the pro forma tariffs. Included with their January 26, 2005 filing of the LGIA and 

LGIP documents, Western provided a cover letter that lists the exceptions and proposed 

modifications to the pro forma documents. The more significant modifications proposed by 

Western are listed below: 

1. Any language referencing compliance under Sections 205 and 206 of the Federal Power 

Act were deleted. 

2. As a non-profit federal power marketing agency subject to Executive and 

Congressional oversight regarding staffing, funding, and authorization limits, Western 

may not have sufficient resources to meet the timeframes proposed in the pro forma 

LGIA. Western proposed modifying the LGIA and LGIP to include language saying 

that Western may meet all deadlines using “reasonable efforts.”

3. Western has added language to the LGIP that allows the Interconnection Customer 

additional flexibility in locating the point of interconnection. 

4. The pro forma LGIP has a provision whereby the Interconnection Customer may only 

be charged the amount of the construction cost estimates provided by the Transmission 

Provider, even if the costs to interconnect are higher, leaving the Transmission Provider 

to pay the difference. However, a key requirement of the Federal Anti-Deficiency Act 

restricts Western from obligating funds that have not yet been congressionally

appropriated or authorized for expenditure. Consequently, Western added language 

stating that, regardless of the provided estimates, Western will charge the 

Interconnection Customer for all actual amounts and if Western overestimates the 

charges, it will refund the dollars against actual dollars spent. Similarly, Western added 

language that requires Interconnection Customers to pay for the cost of negotiations, 

and revised articles referring to payment of “liquidated damages.” 

5. Western is required by law to conduct a mandatory environmental analysis. Thus, the 

LGIP was revised to condition Western's offering of an Engineering and Procurement 

Agreement or a final LGIA upon Western's determination that it may proceed with 

construction under the National Environmental Protection Act. 

6. The pro forma LGIA allows the LGIA to remain in effect for a period of 10 years from 

the effective date or a longer (indefinite) period at the request of the Interconnection 

Customer. Western found that this language could obligate the federal government to 

rebuild aging Interconnection Facilities without prior Congressional appropriations or 

authorization to expend funds. This section was subsequently modified to limit the 

maximum term of the LGIA to 40 years, at the written request of the customer. 
I-3

7. Western revised the LGIP and LGIA to reflect its general requirement to comply with 

Department of Energy standards and directives related to physical infrastructure 

security, as well as “Good Utility Practices.”

8. The pro forma LGIA allows Western to inspect any facilities being constructed by the 

Interconnection Customer, but does not pass the costs of those inspections on to the 

other party as required by longstanding Western policy. Accordingly, Western modified 

the LGIA (Article 5.2) to require the Interconnection Customer to pay Western's costs 

for inspection.

9. As a Federal entity, Western does not, as a general rule, pay taxes. Language in that 

regard has been removed from the tariff.

10. The 20-year network upgrade crediting period limit set forth in Order No. 2003-B could 

obligate Western to make a balloon payment at the end of the 20-year period without 

having first obtained the necessary Congressional appropriations or authorization for 

expenditure of funds. Western clarified that it will provide credits for network upgrades 

under the LGIA without any restriction as to the period of time so that there is no risk 

of having to make a balloon payment to repay the balance for network upgrades. 

11. The LGIA was revised to require advanced payment for all work related to network 

upgrades. As written, the pro forma LGIA would have required Western to accept a 

guarantee, a surety bond, letter of credit or other form of security in lieu of actual 

payment for procuring, constructing, and installing Network Upgrades. However, 

Western does not accept a provision of security to perform such services; rather, it 

requires advance payment to do so consistent with the Federal Contributed Funds Act. 

12. Western modified the invoice provisions to clarify that Western will not pay interest on 

money owed to the Interconnection Customer except as expressly provided for in the 

LGIA. 

FERC issued a declaratory order in August 2005 that found Western’s LGIA and LGIP 

tariff provisions acceptable with the exception of one modification. The one exception was 

changes made to termination language under Attachment J, Section 1 that allowed the 

transmission customer to terminate the agreement upon ninety days’ notice of a rate change. 

Western states that, when it filed its original OATT, it had not yet developed separate rates for 

transmission and ancillary services that would require Western to adjust its rates on a routine

basis. Western found the blanked termination clause to add too much risk of violating federal 

provisions and requested that the termination be allowed only in instances where Western 

changes the formula through which rates are set. With some modifications to terminology and 

definitions, this provision was later accepted by FERC and the Western LGIA and LGIP were 

accepted for under safe harbor granting Western reciprocity that is necessary for Western’s role 

as a power marketer and in wheeling power. 
F1146-E(10/2008)

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1. REPORT DATE (DD-MM-YYYY)

January 2009

2. REPORT TYPE

Subcontract Report

3. DATES COVERED (From - To)

4. TITLE AND SUBTITLE

Generation Interconnection Policies and Wind Power: A Discussion 

of Issues, Problems, and Potential Solutions

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

5b. GRANT NUMBER

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6. AUTHOR(S)

K. Porter, S. Fink, C. Mudd, and J. DeCesaro

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NREL/SR-550-44508

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WER9.6501

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Exeter Associates, Inc., 5565 Sterrett Place, Suite 310, Columbia, MD 

21044

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LAM-8-77548-01

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National Renewable Energy Laboratory

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NREL

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National Technical Information Service

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13. SUPPLEMENTARY NOTES

NREL Technical Monitor: David Corbus

14. ABSTRACT (Maximum 200 Words)

This report describes the adoption and implementation of FERC Order 2003 and the reasons for the sharp rise in 

generation interconnection filings in recent years.

15. SUBJECT TERMS

Wind; FERC; regulation; grid integration; system integration; interconnection; utilities; power generators; ISO; 

capacity.

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