Fuel Assurance
Operating and Capital Costs
for Generation in NYCA
REDACTED
prepared for
New York Independent System Operator
May 22, 2013
100 SUMMER STREET, SUITE 3200
BOSTON, MASSACHUSETTS 02110
TEL 617-531-2818
FAX 617-531-2826
DISCLAIMER
This report was prepared by Levitan & Associates, Inc. (LAI) for the New York
Independent System Operator, Inc. (NYISO). The views and conclusions
expressed in this study represent those of LAI and do not necessarily represent
those of the NYISO. No official endorsement by the NYISO is intended or
should be inferred
TABLE OF CONTENTS
Introduction ..................................................................................................................................... 5
Executive Summary ........................................................................................................................ 7
Primary Observations .................................................................................................................. 7
Oil Infrastructure Capability ....................................................................................................... 9
Cost of Dual Fuel Capability .................................................................................................... 10
Cost of Firm Gas Transportation .............................................................................................. 12
Financial Analysis ..................................................................................................................... 14
Existing Dual-Fuel Capacity in NYCA......................................................................................... 21
Capital District .......................................................................................................................... 21
Lower Hudson Valley ............................................................................................................... 22
New York City .......................................................................................................................... 24
Long Island ............................................................................................................................... 27
Minimum Oil Burn Compensation Programs ........................................................................... 28
Incremental Capital and Operating Costs for Dual-Fuel Capability ............................................. 30
Scope of Analysis...................................................................................................................... 30
Generation Types .................................................................................................................. 31
Locations ............................................................................................................................... 31
Dual Fuel Capability Scope .................................................................................................. 31
Distillate Oil Delivery and Storage ........................................................................................... 33
Combined Cycle Analysis ......................................................................................................... 35
Simple Cycle Analysis .............................................................................................................. 37
Incremental Costs of Firm Natural Gas Transportation ................................................................ 40
Capital District .......................................................................................................................... 41
Dominion............................................................................................................................... 42
Tennessee .............................................................................................................................. 44
Iroquois ................................................................................................................................. 46
Lower Hudson Valley ............................................................................................................... 48
Millennium ............................................................................................................................ 48
Algonquin .............................................................................................................................. 50
Iroquois ................................................................................................................................. 51
Tennessee .............................................................................................................................. 52
New York City .......................................................................................................................... 53
Iroquois ................................................................................................................................. 54
Tennessee .............................................................................................................................. 55
Texas Eastern ........................................................................................................................ 55
Transco .................................................................................................................................. 56
Long Island ............................................................................................................................... 58
Iroquois ................................................................................................................................. 58
Transco .................................................................................................................................. 59
New York Facilities System Service in Zone J and Zone K ..................................................... 59
Summary of Rate Estimates ...................................................................................................... 61
Levelized Annual Cost Comparison ............................................................................................. 62
Modeling Approach .................................................................................................................. 62
Economic and Financial Assumptions ...................................................................................... 64
Results ....................................................................................................................................... 67
Conclusions ............................................................................................................................... 77
2
TABLE OF FIGURES
Figure 1. Dual-Fuel and Gas-Only Capacity by Zone ................................................................. 10
Figure 2. Pipelines Serving NYCA .............................................................................................. 13
Figure 3. Levelized Annual Cost Comparison – Capital District ................................................ 16
Figure 4. Levelized Annual Cost Comparison – LHV................................................................. 17
Figure 5. Levelized Annual Cost Comparison – NYC ................................................................ 18
Figure 6. Levelized Annual Cost Comparison – Long Island ...................................................... 19
Figure 7. Zone F Generator Locations ......................................................................................... 21
Figure 8. Zones GHI Generator Locations ................................................................................... 23
Figure 9. Zone J Generator Locations .......................................................................................... 24
Figure 10. Zone K Generator Locations ...................................................................................... 27
Figure 11. ULSD Prices ............................................................................................................... 33
Figure 12. ICF Study Oil Storage Tank Costs ............................................................................. 35
Figure 13. Zone F Pipelines ......................................................................................................... 42
Figure 14. Dominion Supply Points to Zone F ............................................................................ 43
Figure 15. Tennessee Supply Points / Interconnections to Zone F .............................................. 45
Figure 16. Iroquois Supply Point to Zone F ................................................................................. 47
Figure 17. Zones G-H-I Pipelines ................................................................................................ 48
Figure 18. Millennium Supply Path to Zones G-H-I ................................................................... 49
Figure 19. Path to Algonquin in Zones G-H-I ............................................................................. 51
Figure 20. Tennessee Supply Path to Zones G-H-I...................................................................... 52
Figure 21. Zone J Pipelines .......................................................................................................... 53
Figure 22. Supply Path to Iroquois in Zone J .............................................................................. 54
Figure 23. Texas Eastern Supply Path to Zone J ......................................................................... 55
Figure 24. Transco Supply Path to Zone J ................................................................................... 56
Figure 25. Zone K Pipelines......................................................................................................... 58
Figure 26. Assumed Energy Price Ranges for Capital District .................................................... 67
Figure 27. Differential Revenue Requirements for Dual Fuel Capability ................................... 71
Figure 28. Differential Revenue Requirements for Firm Transportation .................................... 72
Figure 29. Differential Revenue Requirements for Firm Transportation v. Status Quo .............. 73
Figure 30. Capital District Incremental Revenue Requirement Components .............................. 74
Figure 31. LHV Incremental Revenue Requirement Components .............................................. 75
Figure 32. NYC Incremental Revenue Requirement Components .............................................. 76
Figure 33. Long Island Incremental Revenue Requirement Components ................................... 77
3
TABLE OF TABLES
Table 1. Relative Economics of Cases by Plant Type, Location, and Strategy ............................. 9
Table 2. Differential Costs for Dual Fuel Capability – Combined Cycle .................................... 11
Table 3. Differential Capital Costs for Dual Fuel Capability – Simple Cycle............................. 12
Table 4. Firm Interstate Pipeline Transportation Estimates by Zone........................................... 14
Table 5. Zone F Oil Storage Capacity.......................................................................................... 22
Table 6. Zone F Generators Gas Transportation .......................................................................... 22
Table 7. Zones G-H-I Oil Storage Capacity................................................................................. 23
Table 8. Zones GHI Generators Gas Transportation ................................................................... 24
Table 9. Zone J Oil Storage Capacity .......................................................................................... 25
Table 10. Zone J Generators Gas Transportation......................................................................... 26
Table 11. Zone K Oil Storage Capacity ....................................................................................... 27
Table 12. Zone K Generators Gas Transportation ....................................................................... 28
Table 13. Summary of 2013 Dual Fuel Capability Incremental Costs (Capital District) ............ 30
Table 14. Differential Capital Costs for Dual Fuel Combined Cycle .......................................... 36
Table 15. Differential Fixed O&M Costs for Dual Fuel Combined Cycle .................................. 37
Table 16. Differential Variable O&M Costs for Dual Fuel Combined Cycle ............................. 37
Table 17. Differential Capital Costs for Dual Fuel Simple Cycle ............................................... 38
Table 18. Differential Fixed O&M Costs for Dual Fuel Simple Cycle ....................................... 39
Table 19. Differential Variable O&M Costs for Dual Fuel Simple Cycle................................... 39
Table 20. Firm Interstate Pipeline Transportation Estimates by Zone......................................... 61
Table 21. Carrying Charge Rates ................................................................................................. 65
Table 22. Assumed 2013 Fuel Commodity Prices ....................................................................... 66
Table 23. Levelized Revenue Requirement Results – Capital District ........................................ 68
Table 24. Levelized Revenue Requirement Results – LHV ........................................................ 69
Table 25. Levelized Revenue Requirement Results – NYC ........................................................ 69
Table 26. Levelized Revenue Requirement Results – Long Island ............................................. 70
4
INTRODUCTION
The primary objective of Task 1 of the Levitan & Associates (LAI) Fuel Assurance Study
prepared for the New York Independent System Operator (NYISO) is to establish a
knowledge base on the relative cost of using either backup oil or, in the alternative, obtaining
firm natural gas supply. NYISO’s increased reliance on natural gas as the primary generation
fuel coupled with potential unit retirements in the New York Control Area (NYCA) have
raised reliability issues regarding the delivery of natural gas to generators throughout the
region, in particular, downstate New York. With the exception of certain contingencies, gasfired generators can assure gas delivery through the use of primary firm transportation (FT)
on interstate pipelines and, where applicable, the New York Facilities System (NYFS)
operated by Con Edison Co. of New York, Inc. (Con Edison) or National Grid Co. (NGrid).
However, most gas-fired generators in NYCA do not hold FT entitlements from liquid natural
gas sourcing points to the meter station. The extent to which substantial pipeline
improvements and new pathways to accommodate the flow of Marcellus shale gas will lessen
concerns over grid security objectives is part of Task 2 of the Fuel Assurance Study.
LAI has examined the relative cost and benefit associated with alternative means of achieving
fuel assurance objectives for a large, state-of-the-art combined cycle plant or peaking plant
located in the Capital District (Zone F), the Lower Hudson Valley (LHV or “Zones G-H-I”),
New York City (NYC or “Zone J”) and Long Island (Zone K). LAI has centered our research
on the cost of providing fuel assurance through dual-fuel capability, including the requisite
financial charges related to oil inventory management during critical conditions. For gas-fired
combined cycle and simple cycle plants, low-sulfur distillate oil products are the most
common backup fuel, since they can be stored on-site for long periods, produce moderate air
emissions, and can be re-supplied through established transportation networks, i.e., truck, rail,
pipeline or barge. For new plants, given emissions restrictions, LAI has assumed that the
backup fuel will be ultra-low sulfur diesel (ULSD). The dual-fuel capable facility is
presumed to be permitted for 720 hours of operation per year on ULSD. Tank size generally
assumes approximately five days’ full load operation.
LAI has evaluated the incremental cost of obtaining a primary FT entitlement from a liquid
sourcing point to the aforementioned zones. Based on recent filings at the Federal Energy
Regulatory Commission (FERC) and other information available to LAI, we have derived the
unit cost corresponding to the maximum daily quantity (MDQ) of firm transportation from a
liquid sourcing point to the delivery point of a gas-fired generator. For NYC and Long Island,
LAI has included the cost of local facility improvements and other tariff components
necessarily incurred by the generator in order to render a “quasi-firm” transportation service
from the pipeline citygate to the delivery point. From a character of service standpoint, such
quasi-firm local transportation service is almost always available, except during cold snaps or
operational contingencies when Con Edison and/or NGrid is regasifying LNG from one or
more satellite tanks located on the NYFS. In performing the Task 1 analysis, emphasis is
placed on the quantification of the levelized annual cost of achieving fuel supply assurance
for each Zone and applicable generation technology.
The Task 1 report includes four sections, as follows:
 First, we summarize the existing dual-fuel capacity in NYCA;
5
 Second, we assess the cost of providing fuel assurance through dual-fuel capability
and fuel oil supply provisions;
 Third, we derive the incremental cost for obtaining a primary FT entitlement along
discrete pathways to the aforementioned Zones; and,
 Fourth, we present the financial results of the comparison of dual-fuel capability or
pipeline transportation under a range of scenarios.
6
EXECUTIVE SUMMARY
Primary Observations
The main points are these:
 Fuel assurance objectives across NYCA are promoted a number of ways: first,
generators arrange secondary firm or interruptible transportation arrangements with
pipelines and/or local distribution companies (LDCs); second, generators throughout
the Capital District, LHV, NYC and Long Island maintain oil back-up storage
inventory to maintain plant availability when pipeline or LDC deliverability
constraints arise; and, third, local reliability rules on the NYFS administered by
NYISO require the use of oil in order to safeguard against contingency events. Gasfired generators’ reliance on non-firm transportation arrangements coupled with the
vast oil tankage capability in the aforementioned zones promote, but do not guarantee,
fuel assurance during critical conditions, in particular, cold snaps.
 The majority of gas-fired generators in NYCA do not have firm pipeline or LDC
transportation entitlements. Instead, gas-fired generators arrange short term, capacity
releases from marketers and/or LDCs, or schedule interruptible transportation directly
from the pipeline. Across the Capital District, LHV, NYC and Long Island, this
transportation procurement strategy has been sufficient to maintain gas deliverability
throughout the year, except during the peak heating season when pipeline congestion
events sometimes result in significant curtailments or interruptions. Reliance on backup fuel is therefore required to ensure plant performance when pipelines post Critical
Notices. Generators’ reliance on residual fuel oil and/or ULSD is thus integral to
NYISO’s ability to satisfy grid reliability objectives.
 While New York’s oil infrastructure is large, oil inventory management depends on
energy and capacity prices, penalty exposure, and a generator’s risk management
policy. Whether or not current energy prices and penalty exposure induce generators
to maintain sufficient oil inventory to perform throughout a five day cold snap is
outside the scope of this report. Notwithstanding LAI’s primary task objectives, we
note that potential tariff reforms oriented around increased penalties for nonperformance due to fuel constraints would likely motivate oil inventory management
practices that safeguard against fuel limitations during extreme weather events. Other
market hindrances may also impair the use of residual oil on short notice.
 The total incremental cost to add dual fuel capability for a 600-MW combined cycle
plant varies from $19 million in the Capital District to $24 million in NYC. The cost
to add oil storage in the LHV is about the same as in the Capital District. The cost to
add oil storage on Long Island is about the same as NYC. Regardless of location, the
cost of erecting field tanks is a comparatively small portion of the all-in cost.
Incremental fixed and variable O&M costs associated with staffing and managing
ULSD in storage are low. The total incremental cost to add dual fuel capability for a
simple cycle plant varies from $7.9 million in the Capital District to $9.3 million in
NYC.
7
 There is presently a pipeline building boom in New York State to accommodate the
flow of natural gas from Marcellus to the market center in downstate New York. A
number of pipelines in central and upstate New York have undertaken construction
initiatives to reverse the flow into Ontario. Improved deliverability conditions on
Dominion, Millennium, Spectra’s Texas Eastern and Algonquin pipelines, as well as
Iroquois, Transco, and Tennessee, portend improved deliverability for core and noncore customers alike by Q4-2013. The addition of major new pipeline resources
across NYCA will likely improve the “quality” and availability of non-firm
transportation options for gas-fired generators in the Capital District and NYC,
thereby promoting fuel assurance objectives.
 At this juncture,, the anticipated abundance of high-quality non-firm deliverability into
the LHV and NYC is likely to deter generators from committing to firm natural gas
transportation service in their own name, even though such transportation
arrangements represent a rational economic choice based on recent historic pricing
and curtailment exposure.
 Market developments in the LHV associated with the retirement of the 495 MW
Danskammer units and the potential retirement of Indian Point nevertheless raise
complex questions about pipeline infrastructure adequacy to serve new conventional
resources. Gas-fired generators on Long Island remain dependent on Transco and
Iroquois, and on NGrid for local transportation. The timing of any additional pipeline
receipt point capability on Long Island into the NYFS is unclear at this juncture.
 Based on recent historical experience, for new combined cycle plants in the Capital
District and LHV, a dual fuel strategy is not economic in relation to non-firm
transportation. For new combined cycle plants in the Capital District and LHV, an allgas firm transportation strategy is economic in relation to non-firm transportation with
or without ULSD in back-up. For new combined cycle plants in NYC and Long
Island, a dual fuel strategy is in-the-money when the baseline pipeline transportation
strategy for comparison sake is non-firm.1 On the NYFS, all local transportation is
non-firm, thereby requiring dependence on upstream firm or non-firm transportation
coupled with ULSD in back-up. A strategy of firm upstream transportation is
economic for NYC and neutral for Long Island.
 Based on recent historical experience, for new peakers a dual fuel strategy is not inthe-money in the Capital District or LHV when the baseline pipeline transportation
strategy for comparison sake is non-firm. For peaker plants in the Capital District, an
all-gas firm transportation strategy is economic in relation to non-firm transportation
plus ULSD in back-up, while the same comparison is uneconomic in the LHV. Given
the need for ULSD back-up in NYC and Long Island regardless of upstream character
of service, firm upstream transportation to these zones for peakers is uneconomical.
The relative economics of the different cases are summarized in Table 1 below.
1
A non-firm natural gas transportation strategy without dual-fuel capability would not be allowed under Con
Edison’s tariffs or under NYISO administered reliability rules.
8
Table 1. Relative Economics of Cases by Plant Type, Location, and Strategy
Plant
Type
Combined
Cycle
Gas
Turbine
Strategy
IT Gas Only
IT with DF
FT
IT Gas Only
IT with DF
FT
Capital
District
Good
Inconclusive
Best
Good
Inconclusive
Better
LHV
NYC
Good
Inconclusive
Better
Good
Inconclusive
Worse
Not Allowed
Required
Better
Not Allowed
Required
Worse
Long
Island
Not Allowed
Required
No Better
Not Allowed
Required
Worse
Oil Infrastructure Capability
Oil storage capacity in the Capital District, LHV, NYC and Long Island is extremely large in
relation to generation nameplate, reflecting utility and state regulatory fuel assurance
objectives that have evolved over the last half century. The amount of nameplate generation
that is gas-only versus dual fuel capacity in each of the zones is shown in Figure 1. Almost
3,000 MW of dual fuel capable units are located in the Capital District with a total storage
capability of about 17 million gallons. Oil infrastructure in the Capital District is all distillate
or ULSD. In the LHV, about 2,000 MW of dual fuel capable units have total storage capacity
over 68 million gallons, the preponderance of which is residual fuel oil. In NYC, about 7,600
MW of dual fuel capable units have total storage capacity about 77 million gallons, about
47% is residual fuel oil and the other 53% is kerosene, ULSD, or distillate. On Long Island,
about 3,600 MW of dual fuel capable units have total storage capacity over 113 million
gallons, the majority of which is residual fuel oil located at the Northport generating station.
Less than 10% of total oil storage on Long Island is distillate or ULSD inventory for peaking
or combined cycle generation – the rest is residual fuel oil.
9
Figure 1. Dual-Fuel and Gas-Only Capacity by Zone
10
9
Summer Capability (GW)
8
7
6
5
Gas-Only Capacity
Dual-Fuel Capacity
4
3
2
1
0
Capital District
Lower Hudson Valley
New York City
Long Island
Cost of Dual Fuel Capability
The cost of adding oil backup capability to a new generation plant varies by zone and
generation technology. In performing this analysis, LAI relied on studies of the Cost of New
Entry (CONE) in New York and PJM to develop a consistent set of capital and operating
costs for simple cycle and combined cycle facilities with and without dual fuel capability.
Both semi-rural and urban settings were evaluated. We then supplemented the NYISO and
PJM study data with conversations with General Electric and other vendors to isolate specific
cost data associated with dual fuel capability.
Table 2 summarizes the incremental capital costs and incremental fixed operating costs
associated with dual fuel capability for each of the New York zones considered in this study.
For the combined cycle plant, we have assumed a new 600+ MW nameplate consisting of two
General Electric Frame 7FA.05 combustion turbines with heat recovery steam generators
(HRSGs) and a single steam turbine. The estimated power island (gas turbine manufacturer)
scope costs of $5.1 million (2013 dollars) are based on discussions with General Electric, and
include manifold and burner systems, additional controls, atomizing air system, and provision
for water injection (for NOx control). Costs of $2.8 million for large, field erected storage
tanks for both ULSD (3.9 million gallons) and demineralized water (2.8 million gallons) are
based on a survey of studies and regulatory filings. Balance of plant costs are derived from
the PJM CONE study and include supporting fuel oil system and demineralized water system
pumps, piping, and controls. We find that the establishment of dual fuel capability increases
the capital cost of a combined cycle facility by 3.2% to 3.4% over the cost of a gas-only
10
facility. Differential fixed O&M costs are driven by the need for additional plant staff and by
property taxes and insurance. Dual fuel capability results in an increase in fixed O&M
expense of about 2.7% over the cost for a gas-only facility.
Dual fuel capability does not affect variable costs when the facility is burning natural gas.
When ULSD is fired, variable O&M costs are increased primarily by faster accrual of
“factored fired hours,” which determine gas turbine major overhaul intervals. Water supply
and treatment costs to support water injection for NOx control are also significant. The
variable O&M cost increment is applicable only to those hours in which ULSD is fired.
Depending on location, variable O&M expense on ULSD ranges from $1.92/MWh to
$2.28/MWh above the corresponding variable cost on natural gas. Importantly, we note that
this estimate does not include the working capital cost of maintaining a full inventory of
ULSD, the potential fixed annual costs for reserving ULSD delivery capability, or the variable
cost of the delivered ULSD commodity.
Table 2. Differential Costs for Dual Fuel Capability – Combined Cycle
(2013 $)
Zone
Capital Costs ($ million)
Power Island
Field Erected Tanks
Balance of Plant
Subtotal
Financing Costs
Total Incremental Cost
Incremental Unit Cost
Fixed O&M Cost
($ 1,000 / year)
Incremental Unit Cost
Capital District
LHV
NYC
Long Island
$ 5.1
$ 2.8
$ 9.8
$17.7
$ 1.3
$19.0
$29/kW
$ 5.1
$ 2.8
$11.0
$18.9
$ 1.4
$20.3
$31/kW
$ 5.1
$ 2.8
$14.4
$22.3
$ 1.7
$24.0
$37/kW
$ 5.1
$ 2.8
$13.7
$21.6
$ 1.6
$23.3
$36/kW
$ 563
$0.86/kW-yr
$ 593
$0.90/kW-yr
$1,508
$2.30/kW-yr
$ 691
$1.05/kW-yr
Table 3 provides a similar summary of incremental capital costs and incremental fixed
operating costs associated with dual fuel capability for each of the New York zones for a new
200 MW simple cycle facility. For the simple cycle facility, LAI has assumed generation
nameplate consisting of two General Electric aeroderivative LMS100PA combustion turbines.
The incremental power island scope cost of $3.1 million is based on discussions with General
Electric. A 1.5 million gallon field-erected tank is provided for ULSD storage at a cost of
$1.1 million. Balance of plant costs include supporting fuel oil system pumps, piping, and
controls. The total increase in capital cost is approximately 2.8% of the total capital cost for a
gas-only facility. Again, incremental fixed O&M costs for dual fuel capability are driven by
the need for additional plant staff and by property taxes and insurance on the increased plant
asset base, about 3% of the gas-only cost.
As with the combined cycle plant, variable O&M costs when operating the simple cycle
facility on ULSD are increased primarily by faster accrual of “factored fired hours” which
determine gas turbine major overhaul intervals. This increment in variable cost ranges from
about $0.76/MWh to $0.78/MWh over the four zones.
11
Table 3. Differential Capital Costs for Dual Fuel Capability – Simple Cycle
(2013 $)
Zone
Capital Costs ($ million)_
Power Island
Field Erected Tanks
Balance of Plant
Subtotal
Financing Costs
Total Incremental Cost
Incremental Unit Cost
Fixed O&M Cost
($1000 / year)
Incremental Unit Cost
Capital District
LHV
NYC
Long Island
$ 3.1
$ 1.1
$ 3.2
$ 7.4
$ 0.5
$ 7.9
$44/kW
$ 3.1
$ 1.1
$ 3.6
$ 7.8
$ 0.5
$ 8.3
$45/kW
$ 3.1
$ 1.1
$ 4.5
$ 8.7
$ 0.6
$ 9.3
$52/kW
$ 3.1
$ 1.1
$ 4.4
$ 8.6
$ 0.6
$ 9.2
$50/kW
$ 250
$1.38/kW-yr
$ 259
$1.41/kW-yr
$ 665
$3.68/kW-yr
$ 295
$1.61/kW-yr
Cost of Firm Gas Transportation
Primary firm transportation is available to serve gas-fired generation in the Capital District,
LHV, NYC and Long Island. The extensive pipeline network serving New York State (Figure
2) allows for multiple transportation paths to each zone examined in this analysis. New York
State also has significant conventional underground gas storage resources in upstate New
York, which significantly improves deliverability across the consolidated network of pipelines
serving core and non-core customers throughout the region. Not pictured in Figure 2 are the
many upstream storage fields in Pennsylvania that serve Transco, Texas Eastern, Tennessee,
Dominion, and the other pipelines doing business across NYCA. Good access to traditional
storage at the Dawn Storage hub in Ontario, Leidy and Ellisburg in Pennsylvania, and the
Dominion Oakford fields improves the economics of firm transportation, while expanding the
range of new pipeline pathways linking the lower cost Marcellus shale formation to delivery
points in the aforementioned zones.
12
Figure 2. Pipelines Serving NYCA
The selected transportation paths for each zone are shown in Table 4, with estimated rates for
the interstate pipeline components based on the costs of previous expansions – NYFS costs
are not included in these estimates.
13
Table 4. Firm Interstate Pipeline Transportation Estimates by Zone
Zone
Selected Path
Dominion
(from South Point)
Millennium 
Algonquin
Tennessee 
Texas Eastern
( NYFS)
Millennium 
Algonquin 
Iroquois
( NYFS)
F
G-HI
J
K
100%
Load
Factor
Rate
($/Dth)
Combined Cycle
Annual
Unitized
Fixed
Variable
Charges
Charge
($ millions/year) ($/MWh)
Simple Cycle
Annual
Unitized
Fixed
Variable
Charges
Charge
($ millions/year) ($/MWh)
$0.6159
$23.8
$0.16
$9.7
$0.22
$1.0920
$43.6
$0.04
$17.8
$0.05
$1.1255
$45.0
$0.03
$18.4
$0.03
$1.6325
$65.2
$0.05
$26.7
$0.07
Financial Analysis
To provide an overview of the incremental costs of providing fuel assurance for new
generation facilities, LAI performed an economic/financial analysis using the basic techniques
and financial assumptions used by NERA in the 2010 NYISO Demand Curve Reset Study
(NYISO Study).2 We present the incremental costs in 2013 constant dollars per kW-year of
capacity. Before illustrating the financial results for different fuel assurance strategies, it is
necessary to review briefly the relevant cost categories defined below:
1. Recovery of Incremental Capital – The incremental capital costs shown in the tables
above are converted to an annual revenue requirement using real capital recovery
factors. The real capital recovery factor reflects the assumed capital structure, debt
interest, required after-tax equity return, and economic life, as well as zone- and
technology-appropriate assumptions for effective income tax rates and tax
depreciation rates.
2. Inventory Carrying Cost – The annual revenue requirement associated with carrying a
working capital balance to cover the cost of ULSD maintained in inventory. The
inventory value is assumed to increase with inflation, and revenue requirements for the
zones reflect appropriate effective income tax rates.
3. Pipeline Reservation Charges – Annual charges to secure firm delivery on interstate
pipelines, based on maximum daily quantity and relevant pipeline tariffs.
2
“Independent Study to Establish Parameters of the ICAP Demand Curve for the New York Independent System
Operator”, NERA Economic Consulting, September 3, 2010.
14
4. NYFS Minimum Bill Obligation Charges – For NYC and Long Island, the annualized
cost of delivery tariff elements subject to a Minimum Billing Obligation (MBO) in the
event the facility dispatches below the MBO threshold.
5. Incremental Fixed O&M – The incremental fixed O&M costs shown in the tables
above.
6. ULSD Delivery Capacity – The annual cost of reserving delivery capacity for ULSD,
based on the cost of financing a fleet of trucks.
7. Net Energy Margin – The annual offset against the incremental costs identified above
to reflect the potential additional hours of dispatched operation and energy revenues,
offset by variable costs. Dispatch was estimated for interruptible gas, firm gas, and
ULSD in eight time periods reflecting seasonal fuel and energy price ranges. This
category is based on forward looking estimates of fuel and energy commodity costs,
and a simplified representation of their interaction in a dynamic market place. The
cost sub-categories making up Net Energy Margin include:
a. Energy Revenue – Based on a range of zonal energy prices for each of several
time periods, including off peak hours in winter, summer, and shoulder
months, “normal” on peak hours by season, and “super peak” hours for
summer and winter seasons.
b. Gas Commodity – Based on seasonal forwards and estimates of basis
differential by source points for each season/period, including winter “super
peak” days.
c. Variable Gas Transportation – Based on the relevant rates for each applicable
pipeline and, where appropriate, for NYFS. Any charges which would be
included in the NYFS MBO Charge category are excluded from this category.
d. ULSD Commodity and Delivery – Based on New York Harbor forward price
for ULSD and zonal estimates of normal delivery charges (not including the
fleet reservation charges discussed above.)
e. Variable O&M – The total variable O&M costs for each option, including,
where applicable, the incremental variable O&M costs in the tables above.
A comparison of differential levelized annual costs for the Capital District is shown in Figure
3. The first comparison in the chart is between dual fuel capability and gas-only operation
with non-firm transportation. The second comparison is between firm transportation (gas
only) and interruptible transportation. Dual fuel capability results in revenue requirements for
recovery of incremental capital costs, ULSD inventory carrying costs, incremental fixed
O&M, and ULSD delivery capacity reservation. Under the assumed energy and fuel price
structure, the incremental net energy margins earned during gas curtailment hours are enough
to offset the incremental cost elements. This results in a small positive total levelized cost for
the combined cycle technology. For the simple cycle technology, the incremental costs are
similar, but the net energy margin is also smaller, resulting in a more significant positive total
levelized cost.
15
The comparison of firm transportation to interruptible transportation (the second and fourth
columns of the chart) result in favorable total levelized cost for both technologies. Because
net benefits are illustrated below the x-axis, a favorable determination, that is, one that is “inthe-money,” is reported as a negative number. Pipeline reservation costs are more than offset
by the lower variable cost of natural gas in all hours and the additional energy margin
resulting from more dispatch hours. Note that these comparisons are based on recent
historical energy price, fuel price, and pipeline congestion levels. During congestion events,
non-firm shippers are exposed to scheduling discipline when critical notices are posted, high
imbalance resolution costs, and, penalties for unauthorized gas use. As discussed fully in the
Task 2 report, owners of combined cycle plants and/or peakers now face a more secure energy
future regarding gas supply deliverability throughout the year. Consequently, there is likely a
materially reduced risk of curtailment or interruption relative to recent history. .
Figure 3. Levelized Annual Cost Comparison – Capital District
Capital District - Incremental Cost v. Gas-Only IT
Levelized Annual Cost (2013 $/kW-yr)
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Dual-Fuel IT
Gas-Only FT
Dual-Fuel IT
Combined Cycle
Gas-Only FT
Simple Cycle
Net Energy Margin
($6.68)
($77.68)
($2.85)
($52.85)
ULSD Delivery Capacity Reservation
$1.20
$0.00
$1.44
$0.00
Incremental Fixed O&M
$0.92
$0.00
$1.25
$0.00
NYFS MBO Charges
$0.00
$0.00
$0.00
$0.00
Pipeline Reservation Charges
$0.00
$30.16
$0.00
$37.76
Inventory Carrying Cost
$2.83
$0.00
$3.40
$0.00
Recovery of Incremental Capital
$2.97
$0.00
$3.67
$0.00
Total Levelized Cost
$1.25
($47.52)
$6.91
($15.09)
Similar results are shown in Figure 4 for the LHV.
16
Figure 4. Levelized Annual Cost Comparison – LHV
Levelized Annual Cost (2013 $/kW-yr)
Lower Hudson Valley - Incremental Cost v. Gas-Only IT
$80
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Dual-Fuel IT
Gas-Only FT
Dual-Fuel IT
Combined Cycle
Gas-Only FT
Simple Cycle
Net Energy Margin
($5.03)
($82.99)
($2.27)
($56.89)
ULSD Delivery Capacity Reservation
$1.20
$0.00
$1.44
$0.00
Incremental Fixed O&M
$0.97
$0.00
$1.29
$0.00
NYFS MBO Charges
$0.00
$0.00
$0.00
$0.00
Pipeline Reservation Charges
$0.00
$55.29
$0.00
$69.23
Inventory Carrying Cost
$2.83
$0.00
$3.40
$0.00
Recovery of Incremental Capital
$3.18
$0.00
$3.84
$0.00
Total Levelized Cost
$3.15
($27.70)
$7.70
$12.34
Since generating units receiving non-firm transportation service at the local level through
NYFS are required by the tariff terms to have backup fuel capability, the interruptible gasonly case is not a realistic baseline for comparison of fuel assurance options. Furthermore,
true firm delivery is not available on NYFS. The best realistic delivery character of service is
represented as quasi-firm. In LAI’s view, quasi-firm service is equal to firm service almost
always, except during cold snaps when Con Edison and/or NGrid regasify LNG from their
respective satellite tanks in NYC or Long Island.3 Hence, we report the results for NYC and
Long Island using a comparison of a firm pipeline transportation case with quasi-firm NYFS
delivery and dual fuel capability (with less storage capacity and inventory) versus non-firm
pipeline transportation, standard interruptible NYFS delivery, and dual fuel capability. We
have defined duel fuel capability as 5 days of storage capacity and inventory.
The financial results for NYC are shown in Figure 5. For the combined cycle technology,
pipeline reservation charges are the major cost increase, while recovery of incremental capital
cost, inventory carrying charges, and incremental fixed O&M are slightly reduced (negative).
Net Energy Margin is a significant credit in favor of the firm transportation due to lower gas
variable commodity cost. The total levelized cost effect is a significant decrease. For the
simple cycle technology, the net energy margin credit is smaller, and cannot offset the fixed
3
Information regarding the frequency and duration of downstate regasification is not publicly available, but
these occurrences are believed to be infrequent.
17
reservation charges plus an increase in fixed MBO charges associated with the higher NYFS
rate for quasi-firm delivery.
Figure 5. Levelized Annual Cost Comparison – NYC
Levelized Annual Cost (2013 $/kW-yr)
New York City - Incremental Cost v. Dual-Fuel IT
$100
$80
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Net Energy Margin
Dual-Fuel FT
Dual-Fuel FT
Combined Cycle
Simple Cycle
($80.71)
($29.86)
ULSD Delivery Capacity Reservation
$0.00
$0.00
Incremental Fixed O&M
($0.11)
($0.09)
NYFS MBO Charges
$0.00
$8.60
Pipeline Reservation Charges
$56.94
$71.29
Inventory Carrying Cost
($1.82)
($2.18)
Recovery of Incremental Capital
($0.44)
($0.34)
Total Levelized Cost
($26.13)
$47.42
Similar results for Long Island are shown in Figure 6. For the combined cycle facility, the
increase in net energy margin is not enough, however to create a significant levelized cost
advantage for firm transportation in this instance.
18
Figure 6. Levelized Annual Cost Comparison – Long Island
Long Island - Incremental Cost v. Dual-Fuel IT
Levelized Annual Cost (2013 $/kW-yr)
$150
$100
$50
$0
($50)
($100)
Net Energy Margin
Dual-Fuel FT
Dual-Fuel FT
Combined Cycle
Simple Cycle
($81.85)
($27.97)
ULSD Delivery Capacity Reservation
$0.00
$0.00
Incremental Fixed O&M
($0.11)
($0.09)
NYFS MBO Charges
$0.00
$13.10
Pipeline Reservation Charges
$82.71
$103.55
Inventory Carrying Cost
($1.69)
($2.03)
Recovery of Incremental Capital
($0.42)
($0.33)
Total Levelized Cost
($1.36)
$86.23
The following general conclusions arise from the economic/financial analysis:

When compared to gas-only operation with non-firm transportation rather than firm
transportation, dual fuel capability is accretive, that is, in-the-money, for combined
cycle facilities in all four zones considered.

When compared to gas-only operation with non-firm transportation, dual fuel
capability is dilutive, that is, out-of-the-money, for simple cycle facilities in all four
zones considered. This determination is first-order in nature, that is, prior to
incorporating the potential reduction in capacity revenues attributable to a generator’s
inability to perform during the heating season, November through March, when
pipeline congestion events may limit or preclude a generator’s ability to arrange
natural gas supply to perform in the Day Ahead or Real Time Market.

When compared to gas-only operation using non-firm transportation, gas-only
operation with firm transportation is accretive for combined cycle facilities in the
Capital District and the LHV. This comparison is not relevant in NYC and Long
Island as the last leg in the supply path from the citygate to the meter station is by
definition quasi-firm or interruptible, thereby hindering the economic case for firm
transportation entitlements on the upstream segment from a liquid sourcing point to
the NYFS. Quantification of second-order effects attributable to redeployment of firm
capacity entitlements in the secondary market is outside the scope of this analysis, but
may have a bearing on the economic rationale for firm transportation.
19

When compared to gas-only operation with interruptible transportation, gas-only
operation with firm transportation is accretive for a simple cycle facility in the Capital
District, but about neutral for a peaker in the LHV. The high efficiency and dispatch
flexibility of the GE LMS100 technology promotes intermediate cycling of the unit,
thereby helping to defray the comparatively high, fixed monthly cost associated with
firm transportation to the LHV. The comparison is not relevant for NYC and Long
Island.

When compared to dual fuel operation with non-firm pipeline transportation and 30day interruptible transportation service on the NYFS, dual fuel operation with firm
pipeline transportation and quasi-firm delivery service at the local level is accretive for
a combined cycle facility in NYC. It is about neutral for a combined cycle facility on
Long Island.

When compared to dual fuel operation with non-firm pipeline transportation and 30day interruptible delivery service on the NYFS, dual fuel operation with firm pipeline
transportation and quasi-firm delivery service at the local level is dilutive for simple
cycle facilities in NYC and Long Island.
LAI notes that the engineering economic and financial results reported in this Task 1 Study
encompass a number of simplifying assumptions about the cost of facility upgrades on the
New York Facilities System, net margin achieved from energy and ancillary sales, EFORd
effects attributable to fuel constraints, and the applicability of Con Edison’s and NGrid’s
respective MBO. To more finely calibrate the economic rationale for firm pipeline
transportation to serve gas-fired generation in the Capital District, LHV, NYC and Long
Island, in lieu of, or in addition to, fuel storage capability on site, production simulation
modeling is required.
20
EXISTING DUAL-FUEL CAPACITY IN NYCA
This section summarizes the locations, oil storage capacity and gas interconnections of each
existing generator identified by NYISO as having dual-fuel capability and on-site oil storage
capacity. Information related to downstate reliability rule procedures is also presented.
Capital District
The existing dual-fuel generators located in Zone F are shown in Figure 7.
Figure 7. Zone F Generator Locations
Indeck-Corinth
Dominion
Tennessee
Rennsselaer
Selkirk
Empire
Fort Orange
Bethlehem
Iroquois
Athens
The oil storage capacity at each location is shown in Table 5.
21
Table 5. Zone F Oil Storage Capacity
Generator
Athens
Bethlehem Energy Center
Empire Generating
Fort Orange
Indeck-Corinth
Rennselaer Cogen
Selkirk
Oil Storage Capacity
(bbl)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Storage Capacity
(gal)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Product
FO2
FO2
FO2
FO2
FO2
FO2
FO2
The gas transportation arrangements of each generator are listed in Table 6. The MDQ is
calculated for purposes of the tables in this section as the amount of gas needed to run at full
load for 24 hours.
Table 6. Zone F Generators Gas Transportation (MDth)
Generator
Athens
Bethlehem Energy Center
Empire Generating
Fort Orange
Indeck-Corinth
Rennselaer Cogen
Selkirk
Gas Interconnection
Iroquois
Tennessee
Tennessee
Dominion (via LDC)4
Dominion (via LDC)4
Dominion
Tennessee
Transportation Rights
70 from Wright
None
None
None
26.2 from Lebanon
None
55 from Wright5
Lower Hudson Valley
The existing dual-fuel generators located in Zones G-H-I are shown in Figure 8.
4
5
Fort Orange and Indeck-Corinth are located in Niagara Mohawk’s service territory.
Selkirk also holds 55.6 MDth/d of capacity on Iroquois from Waddington to Wright.
22
MDQ
154
129
95
13
25
16
70
Figure 8. Zones GHI Generator Locations6
Iroquois
Millennium
Danskammer
Roseton
Shoemaker
Algonquin
Bowline
Tennessee
Hillburn
Por
Northport
The oil storage capacity at each location is shown in Table 7.
Astoria Energy 2
Table 7. Zones G-H-I Oil Storage East
Capacity
River
Generator
Bowline
Danskammer
Hillburn
Roseton
Shoemaker
Oil Storage Capacity
(bbl)
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Storage
Capacity
Gowanus
Narrows
(gal)
Redacted
Redacted
Redacted
Redacted
Redacted
Pinelawn
Oil Product
Freeport
FO6
FO6
FO2
FO6
FO2
The gas transportation arrangements of each generator are listed in Table 8
6
Danskammer is in the process of being retired following damage from Hurricane Sandy that resulted in an
extended forced outage and expensive repairs.
23
Table 8. Zones GHI Generators Gas Transportation (MDth)
Generator
Bowline
Danskammer
Hillburn
Roseton
Shoemaker
Gas Interconnection
Millennium
Iroquois (via LDC)7
LDC8
Iroquois (via LDC)7
LDC8
Transportation Rights
None
None
None
None
None
MDQ
191
41
12
292
11
New York City
The existing dual-fuel generators located in Zone J are shown in Figure 9.
Figure 9. Zone J Generator Locations
Iroquois
NRG Astoria GTsNYPA Astoria CC
Transco
Astoria Generating
59th Street
Ravenswood
Glenwood
Astoria East Energy
Astoria Energy 2
NYFS
Trigen-NDEC
East River
Brooklyn Navy Yard
Bayonne
Gowanus
Linden Cogen
KIAC
Barrett
Texas Eastern
7
8
Fr
Narrows
Danskammer and Roseton are located in Central Hudson Gas & Electric’s service territory.
Hillburn and Shoemaker are located in Orange & Rockland’s service territory.
24
The oil storage capacity at each location is shown in Table 9.
Table 9. Zone J Oil Storage Capacity
Generator
59th Street
Astoria East Energy
Astoria Energy 2
Astoria Generating
Bayonne Energy Center9
Brooklyn Navy Yard
East River
Gowanus
KIAC Cogen
Linden Cogen9
Narrows
NRG Astoria
NYPA Astoria
Ravenswood
Oil Storage Capacity
(bbl)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Storage Capacity
(gal)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Product
FO2
FO2
FO2
FO6
FO2
FO2
FO2
FO6
FO2
FO2
BUT
FO2
FO2
FO2
FO2
FO6
The gas transportation arrangements of each generator are listed in Table 10.
9
Bayonne Energy Center and Linden Cogen were not included in NYISO’s oil storage capacity survey, therefore
the data is not available.
25
Table 10. Zone J Generators Gas Transportation (MDth)
Generator
59th Street
Astoria East Energy
Astoria Energy 2
Astoria Generating
Bayonne Energy Center
Brooklyn Navy Yard
East River
Gowanus
KIAC Cogen
Linden Cogen
Narrows
NRG Astoria
NYPA Astoria
Ravenswood
Gas Interconnection
NYFS
NYFS
NYFS
NYFS
Transco
NYFS
NYFS
NYFS
NYFS
LDC12
NYFS
NYFS
NYFS
NYFS
10
Transportation Rights
None11
None
None
None
125 on delivery lateral
25 from Waddington
None11
None
None
None
None
None
None13
60 from Waddington
MDQ10
6
86
90
185
120
60
163
77
26
91
97
146
82
475
Includes only the units at each plant that are dual-fuel capable.
Con Edison holds 417 MDth/d of capacity on Transco from various receipt points to the Con Edison gate
station, 62 MDth/d of capacity on Tennessee from various receipt points to the White Plains gate station and 150
MDth/d of capacity on Iroquois from Waddington and Brookfield to the Hunts Point and South Commack gate
stations. These entitlements are assumed to serve core demand rather than generation.
12
Linden Cogen is connected to the PSE&G local distribution system.
13
NYPA holds 15 MDth/d of capacity on Transco from an interconnection with Dominion at Leidy to the Con
Edison gate station, which may be used to fuel the Astoria CC, but may also be used to fuel NYPA’s other inCity units.
11
26
Long Island
Figure 10. Zone K Generator Locations
Iroquois
ria GTs
Northport
NYFS
Glenwood
erating
ood
East River
Port Jefferson
Stony Brook
Flynn
Caithness
Trigen-NDEC
Pinelawn
Gowanus
nNarrows
Freeport
Barrett
Far
Rockaway
Transco
The oil storage capacity at each location is shown in Table 11.
Table 11. Zone K Oil Storage Capacity
Generator
Barrett
Caithness
Far Rockaway
Flynn
Freeport
Glenwood GTs
Glenwood LM6000s
Northport
Pinelawn
Port Jefferson
Stony Brook
Trigen-NDEC
Oil Storage Capacity
(bbl)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Oil Storage Capacity
(gal)
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
Redacted
The gas transportation arrangements of each generator are listed in Table 12.
27
Oil Product
FO2
FO6
FO2
FO2
FO2
FO2
FO2
FO2
FO2
FO6
FO2
FO2
FO6
FO2
FO2
Table 12. Zone K Generators Gas Transportation (MDth)
Generator
Barrett
Caithness
Far Rockaway
Flynn
Freeport
Glenwood GTs
Glenwood LM6000s
Northport
Pinelawn
Port Jefferson
Stony Brook
Trigen-NDEC
Gas Interconnection
NYFS
NYFS
NYFS
NYFS
NYFS
NYFS
NYFS
Iroquois
NYFS
NYFS
NYFS
NYFS
Transportation Rights
None
None
None
None15
None
None
None
None
None
None
None
None
MDQ14
48
52
14
26
12
28
19
390
16
101
4
12
Minimum Oil Burn Compensation Programs
New York State Reliability Council (NYSRC) reliability rules I-R3 and I-R5 set the
requirements for assurance of energy supply to the electric load in the NYC and Long Island
Zones, respectively, under a single gas facility contingency. In particular, rule I-R3 requires
that the power system be operated so that the loss of a single gas facility does not result in the
loss of electric load within NYC. Similarly, according to rule I-R5, the power system shall be
operated so that a loss of a single gas facility does not result in the uncontrolled loss of
electric load on Long Island.
Con Edison and the Long Island Power Authority (LIPA), working with NGrid, are
responsible for developing application of NYSRC rules I-R3 and I-R5, respectively. These
procedures, known as Minimum Oil Burn Compensation (MOBC) programs, outline the
actions required to meet the reliability rules across the NYFS. Con Edison’s reliability rule
procedures require that selected in-city generating units shall maintain either a minimum level
of oil use as part of the generator fuel mixture, or have the ability to automatically swap to a
liquid fuel source to guard against the sudden interruption of gas fuel supply to the generator.
According to LIPA’s reliability rule procedures, one or more Northport units may be required
to use oil as the primary fuel such that the unit(s) will not trip on a loss of gas transported by
Iroquois Gas Transmission System (Iroquois). The actual number of units burning oil is
dependent on the load level and voltage support devices in service. If only one Northport unit
is in service then there is no natural gas fuel restriction at all load levels. When a Northport
unit burns a minimum of 75% oil or a maximum of 25% gas, the unit will not trip on a loss of
gas pressure.
14
Includes only the units at each plant that are dual-fuel capable.
NYPA holds 15 MDth/d of capacity on Transco from an interconnection with Dominion at Leidy to the Long
Beach gate station, which may be used to fuel the Flynn plant, but may also be used to fuel Brentwood, a gasonly plant.
15
28
Generating units responding to the MOBC procedures under the I-R3 and I-R5 reliability
rules are allowed to recover the costs associated with either activation of their auto-swap
capability or the actual burning of an alternate fuel at designated minimum levels. The
eligibility period of time in which the units burn the alternate fuel only because the I-R3 or IR5 rules are activated includes time required to move into and out of the reliability rule
compliance. The allowed costs include variable operating costs consistent with the “but for”
test to the extent: (i) such costs are not reflected in the reference level for the hours included
in the eligibility period, and (ii) the hour is one for which the commodity cost of the alternate
fuel, including taxes and emission allowance costs, is greater than the commodity cost for
natural gas, including taxes and emission allowance costs, as determined by NYISO. In
addition to the costs discussed above, generating units responding to the I-R3 and I-R5
requirements under the MOBC program may recover other costs specifically addressed in the
Implementation Agreements negotiated with NYISO.16
Over the last three years, natural gas prices delivered to generation plants across NYCA have
almost always been lower than oil prices on a BTU-equivalent basis. The incremental costs
under the MOBC program are paid to the participating generating units as out-of-market
payments to make up the difference between the lower cost of natural gas and the higher cost
of fuel oil. The MOBC costs are categorized as uplift costs and are not reflected in the energy
market clearing prices. According to the NYISO State of the Market Reports of 2010 and
2011, the uplift from MOBC payments were approximately $10 million in 2009, $12 million
in 2010, and $7 million in 2011.
In LAI’s view, the MOBC program has been an integral part of NYISO’s ability to meet fuel
assurance objectives in NYC and on Long Island.
16
The Implementation Agreements indicate the rate to be charged during the period of the Implementation
Agreements to recover such additional costs. This period could be equal to one or more capability periods.
29
INCREMENTAL CAPITAL AND OPERATING COSTS FOR DUAL-FUEL CAPABILITY
This section of the Task 1 report focuses on the capital, fixed operation and maintenance
(O&M), and variable O&M cost impacts of including ULSD storage and firing capability in
the scope of a new combined cycle facility, based on the General Electric 7FA.05 gas turbine
in a 2x1 configuration, or a new simple cycle peaking facility, based on 2 General Electric
LMS100 units.
Key incremental cost results are summarized Table 13 below assuming each plant has ULSD
storage of five days of full load operation.17 The incremental variable O&M cost does not
include the commodity cost of delivered ULSD. The costs shown are applicable to the
Capital District. Adjustments for variables such as construction cost factors, land cost, and
property taxes, as applicable to the LHV, NYC and Long Island are also provided in this
report.
Table 13. Summary of 2013 Dual Fuel Capability Incremental Costs (Capital District)
Maximum ULSD Rate (gal/h)
ULSD Storage Capacity
Hours at maximum rate
Gallons
Capital Costs ($ millions)
Power Island Scope Modifications
Fuel Receiving and Storage Facilities
Balance of Plant
Contingency, Owner’s Costs, etc.
Incremental Capital Cost
Fixed O&M Costs ($ 1000/yr)
Staffing
Land Lease
Property Tax
Insurance
Incremental Fixed O&M Cost
Variable O&M Costs ($/MWh)
Demineralized Water Cost
Gas Turbine Overhaul Accrual
Incremental Variable O&M Cost
2x7FA.05
Combined Cycle
32,500
2 LMS100
Simple Cycle
12,800
120
3,900,000
120
1,530,000
$ 5.1
$ 2.8
$ 9.0
$ 2.1
$19.0
$
$
$
$
$
3.1
1.1
1.9
1.8
7.9
$ 116
$ 10
$ 380
$ 57
$ 563
$ 58
$ 10
$ 159
$ 24
$ 250
$ 1.18
$ 0.74
$ 1.92
($ 0.05)
$ 0.76
$ 0.71
Scope of Analysis
In order to develop this database, LAI has reviewed reports in the public domain and industry
literature, as well as reached out to suppliers and industry participants.18 We have also
17
18
This assumption will be reviewed with NYISO and may be modified.
Independent engineering and cost analysis is beyond the scope of work.
30
reviewed and relied on, where appropriate, prior engineering economic cost analyses
conducted by third parties for both NYISO and PJM in relation to the quantification of the
Cost of New Entry (CONE).
Generation Types
LAI selected two generation technologies as representative of new gas-fired capacity in New
York:

A combined cycle facility consisting of two General Electric Frame 7FA.05 gas
turbines, each with a HRSG, and a single steam turbine generator with a net summer
capacity of about 600 MW without duct-firing. This technology choice is consistent
with the combined cycle configuration selected for the PJM CONE Report19 and is
representative of combined cycle facilities under development in New York.

A simple cycle facility consisting of two General Electric LMS100PA aero-derivative
gas turbines with selective catalytic reduction and a net summer capacity of about 200
MW. This technology is consistent with the simple cycle configuration evaluated in
the NYISO Study for several zones and was selected to support the derivation of
CONE in NYC and Long Island.
Locations
LAI has estimated incremental costs for dual fuel capability of the two selected generation
technologies at sites representative for the Capital District, LHV, NYC and Long Island. We
have adopted the cost estimating assumptions used in the NYISO Study for each site,
including land lease costs, property tax rates, and labor cost multipliers. These assumptions
have been adapted as necessary to accommodate the combined cycle technology in each zone.
Dual Fuel Capability Scope
The addition of dual fuel capability requires that the following items be included in the
procurement and construction scope for typical combined cycle and simple cycle plants.
Combined cycle plants typically utilize demineralized water for HRSG make-up but would
require a ten-fold expansion to accommodate gas turbine water injection for NOx control
when operating on ULSD. An LMS100 simple cycle plant typically utilizes water injection
for NOx control on natural gas, so there would be no significant cost differential for a dualfueled simple cycle plant operating on ULSD
The additional equipment normally included in a dual-fueled combined cycle power island
supply scope is as follows:

Dual fuel manifold / burners
19
“Cost of New Entry Estimates for Combustion Turbine and Combined Cycle Plants in PJM (CONE Report)”,
Prepared for PJM Interconnection, LLC, by The Brattle Group with input from CH2MHill and Wood Group
Power Operations, August 24, 2011.
31

Atomizing air skid

Water injection skid

Purge system

Fuel conditioning/filtering skid

Related instrumentation and controls
The additional equipment normally included in a dual-fueled LMS100PA simple cycle plant
that utilizes water injection for gas-only NOx control is as follows:

Dual fuel burners

All internal fuel piping

Auxiliary skid with filtration and fuel transfer pumps

Related electrical equipment, controls, and instrumentation
There would be additional fuel oil storage and handling equipment that is normally outside of
the power island supply scope:

Distillate oil storage tank sized for five days of full-load operation

Concrete pad and containment berm

Fuel oil forwarding pumps

Fuel oil receiving bays for truck delivery

Interconnecting power and instrumentation cables, piping, valves, filters

Fire protection system to cover distillate fuel unloading area and storage tanks
There would also be an expansion of the demineralized water system for the combined cycle
plant that is also normally outside of the power island supply scope20:

Demineralized water storage tank sized for three days of full-load operation of water
injection, in addition to HRSG makeup requirements

Pumps and piping to supply demineralized water to the water injection connection on
gas turbines
20
The combined cycle plant would not require combustion turbine water injection to meet NO x emission limits
firing natural gas, but would require such water injection firing ULSD. The simple cycle plant using LMS100
combustion turbines would typically use water injection firing either fuel.
32

Concrete pad and interconnecting piping to accommodate a trailer-mounted
demineralizer system to provide additional capacity during extended operation on
distillate oil
ULSD operation increases fixed O&M costs, mostly for additional fuel and water quality staff
and for land lease, property taxes, and insurance. ULSD operation increase variable O&M
costs for higher gas turbine overhaul accrual rates. For combined cycle plants, water injection
for NOx control results in higher water supply and treatment costs as well. For simple cycle
plants, lower injection rates result in slightly lower water supply and treatment costs.
Distillate Oil Delivery and Storage
Air permitting issues and cost considerations make ULSD the most likely backup fuel for a
new combined cycle or simple cycle facility in New York. The fuel is generally delivered to
terminals by barge or pipeline and then delivered to users by truck. Pricing of delivered fuel
is generally based on a New York Harbor (NYH) price, plus adders for handling and delivery.
Terminal operators may provide storage services, as well. The NYH price for the last 3 years
is shown in Figure 11, along with a forward price curve based on trading as of January 29,
2013.21
Figure 11. ULSD Prices
30
25
$/MMBtu
20
15
NYH ULSD Spot Price
NYMEX ULSD NY Argus
10
5
21
Oct-13
Jul-13
Apr-13
Jan-13
Oct-12
Jul-12
Apr-12
Jan-12
Oct-11
Jul-11
Apr-11
Jan-11
Oct-10
Jul-10
Apr-10
Jan-10
0
The price in cents per gallon was converted to $/MMBtu using a higher heating value of 138,490 Btu/gallon.
33
To provide fuel assurance, a generator will need to demonstrate that sufficient backup fuel is
available on-site or deliverable on a firm, timely basis, to cover a postulated curtailment in
natural gas fuel delivery. Since natural gas curtailments are most likely to occur during cold
snaps when fuel oil terminal operators and delivery fleets typically experience peak demand
for ULSD as well as No. 2 fuel oil, the ability to secure delivery of large amounts of ULSD on
short notice would involve an additional, significant financial premium for the restocking of
oil inventory when regional demand is high. By short notice, we mean one or at most two
days when conventional oil customers simultaneously scramble for refill on the second, third,
or fourth day of a prolonged cold snap. In this study, we have assumed that a generator would
provide for 3-days of full operation on ULSD stored on-site, and would then exercise
reasonable efforts to replenish ULSD inventory as quickly as possible.
For the selected combined cycle plant, with an hourly full load requirement of 32,500 gallons,
full replenishment would require 19 - 5,200 gallon delivery trucks. Larger tractor-trailers
with a hauling capacity of 10,500 gallons should also be available, but were not assumed for
purposes of this analysis. Even with a day or two of notice prior to delivery, the scheduling of
about ten 5,200 gallon delivery truckloads per hour would require a major commitment on the
part of the delivery fleet operator for extended periods of ULSD operation. LAI has estimated
the cost of meeting this fuel assurance objective based on acquiring 19 new delivery trucks
making 8 two-hour trips per day during a 16-hour delivery window that would provide
deliveries of 49,000 gallons per hour for each gas curtailment. The estimated annual cost for
this service is approximately $732,000.22
For the selected simple cycle plant, the hourly full load requirement is 12,800 gallons per
hour. When pipelines serving gas-fired generation across NYCA post Critical Notices, it is
reasonable to assume that NYISO would not require a dual-fuel unit to operate on ULSD at
full power output for 24 consecutive hours. The fuel assurance premium cost for the simple
cycle plant is based on eight trucks capable of delivering 20,800 gallons per hour during 16
hours of daily operation per curtailment. The estimated annual cost for this service is
$288,000.
ICF performed a study of New York State’s petroleum infrastructure in 2006.23 This study
considered the network of pipelines, distributors, and truck fleets that provide petroleum
products to residential, industrial, commercial, and generators in New York State.
The ICF study provides a basis for estimating the cost of fuel oil storage tanks of different
capacities. These costs are shown in 2012 dollars in Figure 12. The cost estimates include
“labor and materials for the tank and auxiliary equipment and services such as piping, and
environmental compliance requirements.” They do not include land acquisition or permitting
and legal costs. Cost on a unit basis ($ per gallon) drops as tank capacity increases, but levels
out when tank size is about 5 million gallons. At this tankage level, unit costs are
22
The estimated premium for fuel assurance is based on a cost of $195,000 for each 5,200 gal delivery truck
amortized over 5 years. Sources for delivery truck cost information include: Oilmen’s Truck Tanks, Inc. at
www.trucktanks.com, Truck Papers at www.truckpaper.com, and Polar Tank Trucks at www.polartank.com.
23
Petroleum Infrastructure Study Final Report, prepared for New York State Energy and Research and
Development Authority by ICF Consulting LLC and Applied Statistical Associates, September 2006.
34
approximately $0.36/gal in the NYC metropolitan area, and about $0.33/gal in the both the
Capital District and LHV. Over the range of tank capacities examined herein – about 900,000
gallons to 2.35 million gallons – unit costs for the NYC metropolitan area decrease from
about $0.71/gallon to about $0.52/gallon, respectively. Importantly, LAI has identified
certain cost components that support significantly higher unit costs than those estimated by
ICF in its 2006 study. We have used a unit cost of $0.83/gallon of ULSD storage (2012$).
Figure 12. ICF Study Oil Storage Tank Costs
$3,500,000
Construction Cost (2012 $)
$3,000,000
$2,500,000
$2,000,000
$1,500,000
ICF - Albany/Hudson
$1,000,000
ICF - NYC Area
Confidential Examples
$500,000
$0
0
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
Tank Capacity, gal
Combined Cycle Analysis
LAI’s primary source of information regarding incremental capital and operating
requirements associated with dual fuel capability for a combined cycle facility is the 2011
PJM CONE Report prepared by the Brattle Group. 24 Brattle assembled cost data for similar
2x1 7FA.05 combined cycle plants located in Middlesex, New Jersey (Eastern MAAC);
Charles County, Maryland (Southwest MAAC); Will, Illinois (Rest of RTO); Northampton,
Pennsylvania (Western MAAC), and Fauquier, Virginia (Dominion). Dual fuel capability
was assumed for all sites, and gas-only was evaluated separately for the Illinois site.
Capital cost estimates for the Illinois site were presented in enough detail so that the key
differentiators between the dual fuel and gas-only cases could be identified. The PJM CONE
Report identified differences in “owner furnished equipment” (gas turbines, HRSGs, and
24
Brattle obtained engineering support from CH2MHill, and operating cost support from Wood Group Power
Operations.
35
steam turbine) of $3.0 million, in additional “EPC Contract” costs of $13.5 million, and in
sales taxes of $0.5 million, for a total difference of $18.0 million in 2015 dollars.
In order to apply this PJM differential (dual fuel versus gas-only) to the relevant zones in the
NYCA, LAI applied individual cost factors from Illinois to New Jersey, a location outside the
NYC metropolitan area. In LAI’s experience, a New Jersey site is roughly comparable costwise to the LHV. Next, we adjusted the differential costs for each of the New York zones
using the cost factors developed for the NYISO Demand Curve Study. We further adjusted
the differentials to reflect specific estimates for power island scope costs and storage tank
costs developed by LAI. Table 14 shows 2013 dollar costs for gas turbine scope, field erected
tanks (distillate oil and demineralized water), and balance of plant for each zone. Financing
costs were increased pro rata with the subtotal capital costs. The total capital cost increments
amount to approximately 3.4% of the gas-only capital cost in all zones, and range from about
$29/kW (Capital District) to $37/kW (NYC).
Table 14. Differential Capital Costs for Dual Fuel Combined Cycle
(2013 $ millions)
Zone
Gas Turbine Scope
Field Erected Tanks
Balance of Plant
Subtotal
Financing Costs
Total
Incremental Cost
Capital District
$ 5.1
$ 2.8
$ 9.8
$17.7
$ 1.3
$19.0
$29/kW
LHV
$ 5.1
$ 2.8
$11.0
$18.9
$ 1.4
$20.3
$31/kW
NYC
$ 5.1
$ 2.8
$14.4
$22.3
$ 1.7
$24.0
$37/kW
Long Island
$ 5.1
$ 2.8
$13.7
$21.6
$ 1.6
$23.3
$36/kW
The PJM CONE Report did not estimate differential fixed O&M expenses for dual fuel versus
gas-only at the Illinois site. LAI was able to estimate the incremental staff requirement based
on both the PJM CONE Report and the NYISO Demand Curve Study. We found that one
additional full-time equivalent (FTE) employee would be required to cover maintenance and
operation of the fuel oil system and the expanded demineralized water system. We also
estimate that the additional tankage would increase land requirements by about one-half acre.
Using the labor rate, land lease rate, property tax rate, and insurance rate assumptions of the
NYISO Demand Curve Study, we estimated incremental annual fixed O&M costs for each
Zone, as shown in Table 15. The incremental fixed O&M costs amount to approximately
2.8% of the gas-only fixed O&M cost in all zones and range from $0.86/kW-year (Capital
District) to $2.30/kW-yr (NYC).
36
Table 15. Differential Fixed O&M Costs for Dual Fuel Combined Cycle
(2013 $ 1000 per year)
Zone
Operating Staff
Land Lease
Property Taxes
Insurance
Total Fixed O&M
Incremental Cost
Capital District
$ 116
$ 10
$ 380
$ 57
$ 563
$0.86/kW-yr
LHV
$ 116
$ 10
$ 406
$ 61
$ 593
$0.90/kW-yr
NYC
$ 144
$ 129
$1,161
$ 74
$1,508
$2.30/kW-yr
Long Island
$ 144
$ 12
$ 466
$ 70
$ 691
$1.05/kW-yr
Having dual fuel capability does not change the variable O&M cost or the heat rate of a
combined cycle plant when it is fired with natural gas. When firing ULSD fuel, however, the
plant heat rate and variable O&M costs would be higher compared to firing on natural gas.
First, water injection to control NOx to the typical permit level of 42 ppm results in substantial
demineralized water costs, estimated at $19 per 1,000 gallons, or about $1.18/MWh. Second,
operation on ULSD results in a higher accrual rate for gas turbine overhaul costs, the GE
formula for “factored fired hours” applied a factor of 2.5 for fired hours on distillate oil, while
the factor is 1.0 for natural gas. Applying those higher accrual rates to the overhaul costs
estimated in the PJM CONE study, adjusted for year and labor rates, increases the accrual rate
from $0.49/MWh to $1.23/MWh in the Capital District, a differential of $0.74/MWh, with
higher differentials in other zones as shown in Table 16. Since the expected annual hours of
operation on ULSD for a dual-fueled combined cycle facility would be approximately 200
hours/year, the accrual of additional factored fired hours due to ULSD operation would be
unlikely to accelerate the timing of a major overhaul by a significant amount.25
Table 16. Differential Variable O&M Costs for Dual Fuel Combined Cycle
(2013 $/MWh)
Zone
Differential Variable O&M
Major Overhaul Accrual
Demineralized Water
Differential Cost
Capital District
LHV
NYC
Long Island
$ 0.74
$ 1.18
$ 1.92
$ 0.85
$ 1.18
$ 2.03
$ 1.16
$ 1.18
$ 2.34
$ 1.10
$ 1.18
$ 2.28
Simple Cycle Analysis
LAI’s primary source of information regarding incremental capital and operating
requirements associated with dual fuel capability for a simple cycle facility is the NYISO
Study that provided cost data for similar 2 x LMS100PA plants located in the four NYCA
zones of relevance. Dual fuel capability was assumed in the base case for the NYC site and
gas-only was assumed for the other sites.
25
Information on factored fired hours accrual provided by GE Power and Water. We assume that the additional
gas turbine starts associated with distillate operation would not trigger overhaul requirements based on number
of factored starts.
37
The NYISO Demand Curve Study provided EPC cost estimates for the Long Island and NYC
sites in enough detail so that the key differentiators between the dual fuel and gas-only cases
could be identified. The NYISO Study identified differences in “Combustion Turbines
w/Accessories” and “Field Erected Tanks” which could reasonably be inferred as the costs for
the power island scope ($1,500,000) and distillate fuel storage and handling ($1,120,000) in
2010 dollars. By backing out differences attributable solely to location-related cost
multipliers, LAI identified $2,480,000 in construction labor and material cost associated with
the dual fuel capability of the NYC estimate. The NYISO Study also provided factors for
adjusting the dual fuel costs for the other locations, which allowed LAI to calculate the total
capital investment for both a gas-only and a dual fuel configuration. LAI’s costs are
consistent in format and reference date to the costs presented in the NYISO Study.
LAI adjusted the NYISO Study costs to 2013 using an inflation rate of 2.4%. We further
adjusted the differentials to reflect specific estimates for power island scope costs and storage
tank costs developed by LAI based on discussions with vendors and a review of other reports.
Table 17 shows 2013 dollar costs for power island scope, field erected ULSD tanks, and
balance of plant for each New York zone. The total capital cost increments amount to
approximately 2.6% of the gas-only capital cost in all zones and range from about $44/kW
(Capital District) to $52/kW (NYC).
Table 17. Differential Capital Costs for Dual Fuel Simple Cycle
(2013 $ millions)
Zone
Gas Turbine Scope
Field Erected Tanks
Balance of Plant
Subtotal
Financing Costs
Total
Incremental Cost
Capital District
$ 3.1
$ 1.1
$ 3.2
$ 7.4
$ 0.5
$ 7.9
$44/kW
LHV
$ 3.1
$ 1.1
$ 3.6
$ 7.8
$ 0.5
$ 8.3
$45/kW
NYC
$ 3.1
$ 1.1
$ 4.5
$ 8.7
$ 0.6
$ 9.3
$52/kW
Long Island
$ 3.1
$ 1.1
$ 4.4
$ 8.6
$ 0.6
$ 9.2
$50/kW
The NYISO Study estimated a staff increase of 1.0 FTE employee as part of the differential
fixed O&M expenses for dual fuel versus gas-only at the NYC site. Based on the discussions
of staffing in both the PJM CONE study and the NYISO Study and the limited time the
simple cycle plants would have to operate on ULSD, LAI assumes that only an additional 0.5
FTE employee would be required. We estimate that the additional tankage would increase
land requirements by about one-half acre. Using the labor rate, land lease rate, property tax
rate, and insurance rate assumptions of the NYISO Study, we estimate incremental annual
fixed O&M costs for each New York zone, as shown in Table 18. The incremental fixed
O&M costs amount to approximately 2.9% to 3.1% of the gas-only fixed O&M cost in all
zones and range from $1.38/kW-year (Capital District) to $3.68/kW-yr (NYC).
38
Table 18. Differential Fixed O&M Costs for Dual Fuel Simple Cycle
(2012 $ 1000 per year)
Zone
Operating Staff
Land Lease
Property Taxes
Insurance
Total Fixed O&M
Incremental Cost
Capital District
$ 58
$ 10
$ 158
$ 24
$ 250
$1.38/kW-yr
LHV
$ 58
$ 10
$ 166
$ 25
$ 259
$1.41/kW-yr
NYC
$ 72
$ 129
$ 436
$ 28
$ 665
$3.68/kW-yr
Long Island
$ 72
$ 12
$ 183
$ 28
$ 295
$1.61/kW-yr
As with combined cycle plants, dual fuel capability does not change the variable O&M cost or
the heat rate of a simple cycle plant when it is fired with natural gas. However, when firing
ULSD, the variable cost would be higher due to the unit price of the fuel and a higher heat
rate. In addition, certain variable O&M cost elements can be significantly higher.26
Operation on distillate results in a higher accrual rate for gas turbine overhaul costs, since the
General Electric formula for “factored fired hours” applied a factor of 1.5 for fired hours on
distillate oil, while the factor is 1.0 for natural gas firing. We have therefore multiplied the
gas-only accrual rates identified in the NYISO Study by 1.5 and adjusted for year and labor
rates by zone. The accrual rate (expressed on a $/MWh basis) increases from $1.53 to $2.30
in the Capital District, a differential of $0.77/MWh, with higher or lower differentials in other
zones as shown in Table 19. However, given the limited number of hours of operation on
ULSD, the accrual of additional factored fired hours may not accelerate the timing of a major
overhaul by a significant amount.27
Table 19. Differential Variable O&M Costs for Dual Fuel Simple Cycle
(2013 $/MWh)
Zone
Differential Variable O&M
Major Overhaul Accrual
Demineralized Water
Differential Cost
Capital District
LHV
NYC
Long
Island
$ 0.77
($ 0.05)
$ 0.71
$ 0.76
($ 0.05)
$ 0.71
$ 0.78
($ 0.05)
$ 0.73
$ 0.77
($ 0.05)
$ 0.72
26
The amount of demineralized water required for gas turbine injection to control NO x to the typical permit level
of 42 ppm on distillate is approximately the same as that required to control to the 25 ppm standard on natural
gas. Based on discussions with vendors, we have assumed that water injection would be used for NOx control on
gas-only plants, rather than a Dry Low NOx (DLN) burner system, since the water injection enhances output.
27
Information on factored fired hours accrual provided by GE Power and Water.
39
INCREMENTAL COSTS OF FIRM NATURAL GAS TRANSPORTATION
Contracting for firm natural gas transportation entitlements from a liquid sourcing point to a
generator’s delivery meter is another alternative to meet fuel assurance objectives. Most of
the pipelines serving New York State are fully subscribed, but not fully utilized. Therefore
there is often slack deliverability usable by generators through secondary firm transactions
with pipeline entitlement holders, in particular, LDCs, or directly with the pipeline through
interruptible transportation arrangements. Due to high pipeline and storage subscription rates,
a generator’s ability to acquire a firm transportation entitlement would require a long term
transportation commitment, coupled with the facility enhancements needed to support
increased throughput on a primary firm basis.
In this analysis, we have evaluated the cost of obtaining firm transportation to serve
generators located in the Capital District, LHV, NYC and Long Island. In Zones F and G-HI, generators are assumed to be directly connected to an interstate pipeline rather than served
by an LDC. In Zones J and K, we assume that the generator will be served by Con Edison or
NGrid via the NYFS. For generators connected to the NYFS, we have made the simplifying
assumption that the highest character of service is quasi-firm transportation rather than FT.
Quasi-firm transportation still requires significant capital outlays to bolster local
deliverability, but does not assure gas transportation on very cold days when Con Edison
and/or NGrid experiences congestion events at the local level, thereby requiring use of
peaking gas facilities behind the citygate.
The minimum cost of firm transportation is generally based on the current effective rate
structure of the pipeline providing service. As new infrastructure is added, the cost of
incremental transportation is the greater of the existing rate or the unitized expansion cost.
Therefore the existing rate provides a lower bound or baseline for the cost to a generator of
procuring firm transportation along a given path. In order to estimate the incremental cost of
the facility improvements needed to accommodate a generator’s firm transportation
requirements, LAI has reviewed the costs associated with recent pipeline system expansions
along paths of relevance to each zone.28 In constructing “supply curves” by zone, we have
assumed that pipelines construct the least expensive improvements first. Thus, the next
increment of loopline and/or compression to bolster deliverability will be equal to or greater
than the cost of the most recent capacity addition on a unitized basis. In most cases, there are
not multiple relevant capacity additions; hence, we have escalated past expansion costs at an
escalation rate of 2.5% to estimate the cost of constructing in 2013. 29 Resultant unitized rates
represent a baseline estimate of the cost of incremental pipeline capacity to serve the firm
transportation needs of new or existing generation.
The consolidated network of pipelines serving core and non-core loads across New York State
has a multitude of pipeline interconnects, which requires pipelines and shippers to coordinate
28
No independent hydraulic modeling has been performed by LAI to evaluate how delivery conditions change in
response to increased FT requirements to serve new generation by zone.
29
Depending on the nature of proposed improvements, the timeline from a pipeline open season to determine
interest in a capacity expansion through the planning process, FERC approval and construction can take
significantly more than a year, a 2013 in-service date is used here as a proxy.
40
daily scheduling from designated receipt points to delivery points in response to dynamic
market conditions. However, the large number of pipeline interconnection points complicates
the definition of the gas transportation path available to a new combined cycle plant or peaker
in each zone. We have determined the most likely paths to each zone from relevant regional
supply points and developed expansion cost estimates based on the rates associated with
recently completed infrastructure projects along these paths. Although it may be possible to
access lower cost supply points by optimizing route segments along different pipelines that
form an interconnected supply path from a liquid sourcing point to the delivery point, we have
made the simplifying assumption that the most economic pipeline pathway minimizes the
stacking or “pancaking” of transportation rates.
We have consolidated the unitized cost for both fixed annual charges ($/year) and variable
operating charges ($/MWh). There are three rate components for each transportation path
segment that are relevant to this analysis:
 first, the reservation rate, which is a monthly fixed charge per unit of contracted
capacity;
 second, the commodity or variable rate, which is charged per unit of flowing
volume; and,
 third, the fuel retention percentage, which is applied to flowing volumes to account
for compressor station fuel.
For the levelized cost analysis described in the final section of this report, a single path has
been selected for each zone. The MDQ for the combined cycle technology is 110 MDth,
supporting approximately 600 MW of generating capacity.30 The MDQ for the simple cycle
technology is 45 MDth.31 It is possible that a lower quantum of firm transportation could be
appropriate for the peaking unit, depending on the expected operating regime. However, for
this analysis we have assumed firm transportation for the full plant output.32
Capital District
Three pipelines operate in Zone F: Dominion, Iroquois and Tennessee (Figure 13).
30
Incremental gas to fuel duct burners is not included in the firm transportation MDQ because the duct burners
are assumed to be used primarily during the summer when gas systems are less constrained and interruptible
transportation or released firm capacity is typically available.
31
The MDQ for a plant is determined by multiplying the heat rate by the plant capacity for 24 hours of
operation.
32
In many cases, the size of the recent expansion is smaller, or much smaller, than the MDQ of the postulated
new generation facility. The infrastructure improvements to provide firm transportation to a new combined cycle
plant could therefore be more extensive than the incremental improvements to accommodate LDC load growth.
Cost estimates included in this study are stated on a conservative basis.
41
Figure 13. Zone F Pipelines
Dominion
Dominion connects Zone F shippers directly to multiple liquid supply points – North Point
and South, each of which represents a geographical segment of the system. Although trading
volumes are much lower at North Point, the cost of an infrastructure expansion from South
Point to North Point may be prohibitively expensive. Therefore we have examined the cost of
transportation from both sources. Representative receipt points in North Point and South
Point are the Leidy and Oakford storage facilities, respectively.
42
Figure 14. Dominion Supply Points to Zone F
Dominion’s Northeast Expansion project, placed in service in 2012, provides 200 MDth/day
of incremental capacity from various Marcellus shale receipt points (primarily in
Westmoreland County) in western Pennsylvania to Leidy, representative of a South Point to
North Point path. The incremental facilities required for this service included total
incremental compression of 32,440 HP at the existing Punxsutawney, Ardell, and Finnefrock
compressor stations in Pennsylvania. The project was projected to cost $97.3, million, to be
recovered through a reservation charge of $8.36/Dth-month. Escalating the rate from 2012 to
2013 yields a reservation rate of $8.57/Dth-month. Applying the system usage charge of
$0.0234/Dth yields a 100% load factor rate of $0.3053/Dth, with a fuel retention percentage
of 2.85%.
In November 2010 Dominion extended the transportation path further downstream into Zone
F, when a 20,000-Dth expansion to serve NGrid (Niagara Mohawk) in West Schenectady, NY
(in Zone F) from North Point (Leidy) as part of the Dominion Hub II project (CP09-83) was
completed. This project involved the replacement of a compressor at the Borger Compressor
Station to reduce system emissions, and a larger-than-required unit was installed to create
incremental capacity. The total construction cost for the project was $22.5 million, of which
the capacity expansion component accounted for $4.8 million, and the reservation charge for
the incremental capacity is $4.25/Dth-month; the cost of the incremental capacity was reduced
43
by being part of a larger project.33 Roughly 20% of the project cost is allocated to the
expansion although 44% of the replacement compression is incremental. Extrapolating the
rate if it had been applied to recovery of 44% of the costs results in a rate of $8.77/Dth-month.
Adjusting for inflation from 2010 to 2013, results in a calculated rate of $9.44/Dth-month.
Applying the system usage charge of $0.0234/Dth yields a 100% load factor rate of
$0.3393/Dth, with a 2.85% fuel retention. Combining this rate with the North Point rate to
complete the transport path from South Point to Zone F results in a 100% load factor rate of
$0.6392/Dth.
Tennessee
Previously, Niagara would have been a viable liquid receipt point on Tennessee’s 200 Line,
but with the reversal of flow into Canada, this has become a delivery point rather than a
receipt point, and is therefore no longer applicable for deliveries in Zone F. Tennessee has a
relatively new interconnection with Empire on the Empire Connector at Hopewell that would
provide access to new production in Tioga County, PA, on Empire and from Laser on
Millennium (via an interconnection at Corning), priced at Millennium – East receipts.34
33
The smallest available replacement compressor was larger than the unit being replaced. Therefore the amount
of incremental compression was smaller than it would have been if a smaller replacement unit had been
available.
34
The Millennium – East receipts pricing point represents receipts into Millennium between Corning and the
Ramapo interconnect on Algonquin.
44
Figure 15. Tennessee Supply Points / Interconnections to Zone F
Tennessee also has interconnections with Dominion and Iroquois that are upstream or in Zone
F. However, if a point on either of these pipelines is used as a source, it would make more
sense for a generator to establish a direct connection on only one pipeline.
Sourcing gas from the Laser gathering system on Millennium would extend the transportation
path to Zone F by an additional pipeline, further pancaking the total service rate.35
Millennium has begun to undertake expansions to facilitate the reversal-of-flow on key
segments. Because the path from Laser to Corning uses existing capacity either as a backhaul
or a flow reversal, we believe that existing rates for firm transportation would apply. Hence,
no facility expansion is contemplated. The existing rate for transportation (forward haul or
back haul) on Millennium is $19.77/Dth-month, or $0.6542/Dth at a 100% load factor,
including the usage rate of $0.0038/Dth.
Alternatively, a Zone F transportation path could be sourced from new production in Tioga
County, PA. Empire placed the Tioga County Extension Project (CP10-493) into service in
November 2011. This project was designed to allow two producers in Tioga County, PA to
35
The Laser system consists of ten miles of pipeline and gathering facilities in New York and 33 miles in
Pennsylvania. Williams acquired the Laser assets in Q1-2012. Along with the proposed Constitution Pipeline
project, Laser will form the basis of Williams’s Susquehanna Supply Hub.
45
deliver gas north along the Empire Connector to an interconnection with TransCanada at
Chippawa, near Niagara. Secondary points in the path include the new Hopewell
interconnection with Tennessee. The cost of service for this expansion is low enough that the
new contracts qualified for rolled-in rate treatment. Therefore, the rates for this path are the
existing Empire Connector rates, including a $9.9664/Dth-month reservation charge,
commodity charges of $0.0018 for the FERC ACA surcharge, and variable monthly fuel
retention. Combining the rate components yields a $0.3296/Dth 100% load factor rate. As
shown in Figure 15, the Corning to Hopewell segment that would bring gas from Laser into
Tennessee via Empire, is a section of the Tioga County to Hopewell path, and is therefore
subject to the same rate considerations.
Tennessee has very few contracts for intra-zone 5 capacity on Line 200. No incremental
capacity has been built to move gas from the new Hopewell interconnection with Empire. In
the absence of expansion cost data to use as a basis for estimating a reservation charge for
future incremental capacity, the current reservation rate for Zone 5 to Zone 5 transportation of
$5.7043/Dth-month has been used as a placeholder to complete this path. This is a
conservative estimate representing a lower bound for this leg of the path. The current usage
charge of $0.0671 and fuel retention of 0.740% would also apply to this segment, resulting in
a 100% load factor rate of $0.2547/Dth.
Iroquois
For service on Iroquois, the only physical receipt point on Iroquois upstream of Zone F is at
Waddington, where gas flows south from at the Waddington import point via TransCanada.
Iroquois has not recently proposed any expansions in the northern part of its system, due to
decreasing utilization of the existing capacity, adverse market developments upstream on
TransCanada’s mainline, and Iroquois’s proposed facility improvements across Zone 2 to
accommodate increased shipper interest from Marcellus.
Iroquois has interconnections with both Dominion (at Canajoharie) and Tennessee (at
Wright).
Because Iroquois is a higher pressure line, the physical flow at both
interconnections is from Iroquois. Offset receipts at interconnections with Dominion (at
Canajoharie) or Tennessee (at Wright) are possible, but due to the proximity of the three
pipelines in this Zone, it is more likely that a generator would interconnect directly to
Dominion or Tennessee in order to avoid pancaking transportation rates.
Iroquois has recently announced the Wright Interconnect Project, which will create a new
physical receipt point at Wright to transport Marcellus shale supplies from the proposed
Constitution Pipeline to New York and New England delivery points. This expansion project
could materially alter flow patterns on Iroquois. Under certain circumstances, gas may enter
Iroquois at Wright and move both south to the market center, and north to Ontario, rendering
the existing Waddington receipt point a delivery point following commercialization of the
Wright Interconnect Project. Cost data for this project has not been filed. Absent indicative
data from Iroquois, we have not included this path in our analysis.
46
Figure 16. Iroquois Supply Point to Zone F
47
Lower Hudson Valley
Four pipelines operate in Zones G-H-I: Algonquin, Iroquois, Millennium and Tennessee
(Figure 17).
Figure 17. Zones G-H-I Pipelines
Millennium
Previously, a generator connected to Millennium would have received Canadian gas from
Niagara via Empire; with the flow reversal on this path. However, gas produced along
Millennium and Empire is now flowing both west into Canada and east into downstate New
York. For a generator in the LHV, the supply path would be from the Laser gathering system,
Tennessee via Stagecoach, or the new Bluestone gathering system (subject to the Millennium
– East receipts pricing point).
48
Figure 18. Millennium Supply Path to Zones G-H-I
Millennium has two projects currently underway to expand capacity to deliver at Ramapo.
The Minisink Compressor Project (CP11-515), which will add a new 12,000 HP compressor
station at Minisink, is currently under construction. The expected cost of this project is $43.6
million. Volumes and rates for this project have been marked confidential at FERC, and will
not be in the public domain until the project is near commercial operation. However, based
on the existing deliverability at Ramapo and the filed annual operating revenues for the
expansion, we have calculated the incremental capacity to be 225,000 Dth/d and the
negotiated reservation rate to be approximately $8.90/Dth-month, or $0.2928/Dth.36 This
project is projected to be commercialized later this year. Therefore, no adjustment for
inflation has been included.
The Hancock Compressor Project (CP13-14), which will add a new 16,000 HP compressor
station at Hancock to increase deliverability at Ramapo by 107,500 Dth/d, is currently seeking
certification from FERC. The expected cost of this project is $45.8 million. The negotiated
rates for this expansion have not been made public, but based on the filed annual operating
revenues we have calculated the rate to be approximately $14.03/Dth-month, or
$0.4615/Dth.37 This project is also expected to enter service in 2013. No inflation adjustment
has been incorporated.
36
This project is described as increasing deliverability at Ramapo to 675,000 Dth/d, from the initial certificated
transportation capacity of 450,000 Dth/d. The FERC application states that the annual operating revenues will
be approximately $24 million.
37
The FERC application states that the expected annual operating revenues will be $18 million.
49
The rate differential between these two projects is based primarily on the lower incremental
capacity of the Hancock project. The cost of each compressor station is roughly the same,
although the Hancock station will have more installed HP. This differential indicates that the
incremental cost of expanding Millennium’s deliverability is increasing significantly with
each project. A project to increase Millennium’s forward-haul capacity by a sufficient
increment to serve new generation would therefore be subject to the supply curve trend,
resulting in a rate similar to the existing transportation rate of $19.77/Dth-month. A usage
charge of $0.0038/Dth and a fuel retention factor of 0.291% have been applied to this
segment, for a 100% load factor rate of $0.6542/Dth. Because Ramapo is in Zones G-H-I, for
purposes of this analysis the same rate is assumed for transportation from Laser.
The CPV Valley Energy Center intends to directly connect to Millennium. Millennium
reports that they have signed an agreement with CPV to provide up to approximately 113
MDth/d of gas transportation to the plant via a dedicated 7-mile lateral.38
Algonquin
For a generator served by Algonquin, multiple pipelines will be required for the transport
path. Algonquin does not receive gas directly at any liquid pricing points, but interconnects
with its sister company, Texas Eastern in northern New Jersey. Algonquin has multiple
receipt points upstream of or in NYCA, including interconnections with Columbia,
Millennium, Tennessee, Texas Eastern and Tennessee. The shortest path is from new
production points on Millennium via the Ramapo interconnection.
38
http://www.nyenergyhighway.com/Content/documents/29.pdf
50
Figure 19. Path to Algonquin in Zones G-H-I
In November 2008, Algonquin completed the Ramapo Expansion Project (CP06-76), adding
125,000 Dth/d of incremental capacity from the interconnection with Millennium at Ramapo
to the interconnection with Iroquois at Brookfield, CT. The capital cost of this project was
$270 million, and the negotiated reservation rate for the incremental service is $11.38/Dthmonth; adjusting for inflation results in a $12.88/Dth-month reservation rate. The commodity
usage rate charged under the negotiated rate agreement is $0.00, plus the FERC ACA
surcharge of $0.0018/Dth, for a 100% load factor rate of $0.4253/Dth. The fuel retention
percentage for Ramapo expansion capacity is 1.90% during the winter months, and 1.87%
during the rest of the year. Because Zones G-H-I are in close proximity to Brookfield, for
purposes of this analysis the same rate is assumed for transportation from Ramapo.
The cost of transportation on the upstream segment from a Laser receipt point on Millennium
to the Ramapo interconnection would be as discussed in the previous section for service on
Millennium.
Iroquois
Service from Iroquois in Zones G-H-I would be subject to the same physical path restrictions
as in Zone F, with Waddington the only available physical receipt point. Therefore the
Waddington pricing point and transportation path would again be applicable (Figure 16). Due
to the decreasing utilization of the Waddington receipt point and the lack of recent expansions
on this segment, we do not believe this is a likely path for transportation expansion.
51
Although Cricket Valley’s developers have indicated that if built the plant will be directly
connected to Iroquois, reports are conflicted whether the plant will have firm upstream
transportation to support all, some, or none of its capacity, and no open seasons have been
held regarding a capacity expansion. It is possible that they could contract for existing
capacity, but with Iroquois running full during winter peak days, it is uncertain whether yearround firm capacity would be available.
Tennessee
A generator served by Tennessee in Zones G-H-I would connect to Line 300 rather than Line
200, which serves Zone F. In this case, the closest upstream pricing point reported by Platts is
Tennessee Zone 4-300 Leg, which represents Marcellus shale deliveries into Tennessee at
points between Stations 315 and 321, near the Stagecoach storage field lateral tie-in point.
Figure 20. Tennessee Supply Path to Zones G-H-I
Tennessee’s 300 Line Project (CP09-444) was placed into service in November 2011. The
project brings 350,000 Dth/d into several New Jersey delivery points and the White Plains,
New York meter, with 50,000 Dth/d specifically designated for White Plains. The receipt
points for this incremental capacity are largely in Zones 0 and 0L, with 50,000 Dth/d from the
high deliverability Stagecoach storage facility in Zone 4. Facility upgrades included the
installation of seven looping segments in Pennsylvania and New Jersey totaling
approximately 127 miles of 30-inch pipeline, and the addition of approximately 55,000
horsepower following the installation of two new compressor stations and upgrades at seven
existing compressor stations. The cost of the project was approximately $752 million. The
52
reservation charge for the incremental capacity is $26.94/Dth-month; adjusting for inflation
results in a reservation rate of $28.30/Dth-month. The commodity charge for the incremental
capacity is $.0018/Dth and the fuel retention factor is 0.750%, for a 100% load factor rate of
$0.9328/Dth.
New York City
Generators located in Zone J receive local transportation from the NYFS operated by Con
Edison. Interstate pipelines supplying gas to the NYFS include Transco, Texas Eastern,
Tennessee, and Iroquois Eastchester (Figure 21).
Figure 21. Zone J Pipelines
53
Iroquois
For deliveries to the NYFS in Zone J, Iroquois can receive gas at both Waddington and
Brookfield. Brookfield receipts allow a shipper to access preferable supply points via
Algonquin, similarly to an Algonquin-connected generator in Zones G-H-I.
Figure 22. Supply Path to Iroquois in Zone J
Iroquois has completed two recent expansion projects to provide service from the new
Brookfield interconnection with Algonquin to downstate delivery meters. The Market Access
Project (CP02-31-002) created 100,000 Dth/d of capacity from Brookfield to the Hunts Point
delivery meter in Zone J. The Brookfield Compressor Station was constructed as part of this
project in order to enable interconnection flows from the lower-pressure Algonquin pipeline
into Iroquois. The construction cost for this project was estimated to be $41.6 million, and the
rate for the capacity is $13.69/Dth-month. Adjusting for inflation from 2008 to 2013 results
in a calculated rate of $15.49/Dth-month. A commodity charge equivalent to the ACA
surcharge of $0.0018/Dth and the Brookfield shipper fuel retention factor of 1.200% have
been applied to this segment, resulting in a 100% load factor rate of $0.5112/Dth.
The upstream segments on Millennium from Laser to Ramapo, and Algonquin from Ramapo
to Brookfield would apply to this path as described above.
54
Tennessee
The NYFS receives gas from Tennessee at an interconnection in Zones G-H-I. Hence, the
same paths and rates would apply as presented for a direct-connected generator in the LHV
(Figure 20).
Texas Eastern
Texas Eastern currently delivers gas into the NYFS on Staten Island. An expansion is also
currently under construction that will deliver gas to a new NYFS receipt point in Manhattan.
The new project into Manhattan will be supplied from a Tennessee expansion project, as
illustrated in Figure 23.
Figure 23. Texas Eastern Supply Path to Zone J
Tennessee’s Northeast Upgrade Project (CP11-161), which received FERC approval in
August 2012, will bring 636,000 Dth/d of Marcellus gas into eastern markets at the Mahwah,
N.J. interconnect with Algonquin. Facility upgrades will include construction and installation
of five separate segments of 30-inch pipeline loop, totaling approximately 39.5 miles,
including 21.9 miles in Pennsylvania and 17.6 miles in New Jersey and the addition of
approximately 22,310 horsepower of compression at Stations 321 and 323. The expected cost
of the project is expected to be about $376 million. The filed tariff rates for incremental
capacity include a reservation rate of $14.91/Dth-month, a commodity charge of $0.0018/Dthmonth, and a commodity charge of 0.750%, for a 100% load factor rate of $0.4922/Dth.
Texas Eastern is currently constructing an expansion into Manhattan, known as the New
Jersey – New York Expansion Project (CP11-56), which will bring 800,000 new Dth/d into a
55
new delivery point from (1) new interconnections with Algonquin at Mahwah and Ramapo
via capacity lease and (2) the existing Texas Eastern receipt point at Lambertville, with
service scheduled to begin in late 2013. Facility upgrades include replacing 4.84 miles of 12”
and 20” pipe with 42” pipe along a segment from New Jersey into Staten Island; (2)
constructing 15.5 miles of new 30” pipe through Staten Island and Bayonne, Jersey City and
Hoboken, New Jersey into Manhattan; (3) modifying the Hanover compressor station in New
Jersey to accommodate bi-directional flow; and (4) constructing new meter stations for
service to PSE&G in Bayonne and Jersey City and a new meter station for service to Con
Edison in Manhattan. Algonquin will also modify selected system facilities to accommodate
bi-directional flow. The total project cost is expected to be about $857 million. The project
has a projected reservation rate of $18.67/Dth-month with a usage rate of $0.0018/Dth and
fuel retention of 0.58%, for a 100% load factor rate of $0.6158/Dth.
Transco
Transco has multiple meter deliveries into the NYFS in Zone J, at its Manhattan and Central
Manhattan gate stations. These points are located in the Transco Zone 6-New York pricing
zone, but because there are no receipt points in this zone, the transportation path for this case
flows from Transco Zone 6-non-NY, where Leidy is a representative receipt point.
Figure 24. Transco Supply Path to Zone J
Transco is currently in the construction phase for the Northeast Supply Link Project (CP1230), which will create 250,000 Dth/d of incremental capacity from new sources of gas supply
via supply interconnections on the Leidy Line to market delivery points including NYC.
56
Project facilities include loop line, pipeline uprates, incremental compression at an existing
station, and a new compressor station. The expected cost of the new facilities is $341 million,
with a resultant reservation rate of $24.04/Dth-month. Because the project is expected to
enter service in 2013, we have not applied an inflation adjustment. A commodity charge of
$0.0101/Dth and a fuel retention factor of 0.650% have been included for this segment, for a
100% load factor rate of $0.8008/Dth.
57
Long Island
Generators located in Zone K receive local transportation from the NYFS operated by NGrid.
Two interstate pipelines serve Long Island – Transco at the Long Beach terminus and,
Iroquois at the South Commack terminus (Figure 25). It is possible that a generator could
establish a direct connection into the Iroquois mainline along the on-Island segment between
Northport and South Commack to avoid LDC charges, but recent experience shows that new
pipe in this area can be difficult to permit.39 We have focused on NGrid as the final leg of the
Zone K supply path.
Figure 25. Zone K Pipelines
Iroquois
Iroquois delivers gas into Zone K at Northport and South Commack, which can be received at
both Waddington and Brookfield. Brookfield receipts allow a shipper to access preferable
39
Spectra and NGrid’s Islander East project was cancelled due to environmental opposition in Connecticut.
Iroquois previously had proposed a marine segment from Connecticut waters to eastern Long Island, but
cancelled the project in response to environmental opposition and Islander East’s initial success in the market.
Iroquois had previously proposed the Brookhaven Lateral from South Commack to Yaphank, but the project was
cancelled in response to local opposition. Potential alternative transportation options on Long Island have not
been examined in this study.
58
supply points via Algonquin; this upstream supply path is the same as for Zone J, as shown in
Figure 22.
The second of Iroquois’s expansion projects to serve downstate meters is the 08/09 Expansion
Project (CP07-457), which added 200,000 Dth of capacity from Brookfield to Long Island.
The project was constructed in phases, and included multiple loopline segments, a new
compressor station in Milford, CT, and incremental compression at the Brookfield compressor
station – the first phase was placed into service in November 2008 and the final phase was
placed into service in November 2009. The total construction cost for all phases was
estimated at $163 million, and the effective rate for this capacity is $13.69/Dth-month, which
is the same rate charged for the Brookfield to Zone J capacity described above. A calculated
rate of $15.49/Dth-month reflects an adjustment for inflation. A commodity charge equivalent
to the ACA surcharge of $0.0018/Dth and the Brookfield shipper fuel retention factor of 1.2%
have been applied to this segment, the same factors used for the Brookfield to Zone J
segment, resulting in the same 100% load factor rate of $0.512/Dth.
Transco
Transco’s delivery point on Long Island is Long Beach. This point is located in the Transco
Zone 6-New York pricing zone. Because there are no receipt points in this zone, the
transportation path for this case flows from Leidy, in Transco Zone 6-non-NY, (Figure 23).
Transco completed the Leidy to Long Island Expansion Project (CP06-34) in December 2007.
This project created 50,000 Dth/d of new capacity from Leidy to Station 210 to and 100,000
Dth/d from Station 210 to Long Beach. Infrastructure improvements included loop line,
updates, pipe replacement, and construction of a new compressor station. The total
construction cost of these facilities was $171 million. The rate for the 50,000 Dth/d of new
capacity from Leidy to Long Beach is $29.17/Dth-month. Adjusting for escalation from 2007
to 2013 results in a calculated reservation rate of $33.83/Dth-month. The commodity rate for
this capacity is $0.2735/Dth, and the fuel retention is 0.65%, resulting in a 100% load factor
rate of $1.3863/Dth.
New York Facilities System Service in Zone J and Zone K
Unlike FERC regulated pipelines, the cost of adding new capacity along the NYFS is difficult
to pin down. In LAI’s opinion, the regulations and tariff requirements of the New York
Department of Public Service (NYDPS) are not as transparent as FERC requirements for
pipelines filing for regulatory approval under the Natural Gas Act. Generators on the NYFS
typically pay for facility expansions through Contribution-In-Aid-of-Construction (CIAC). 40
Con Edison is required to address project expenditures that are above a capital threshold, but
the current proposed modifications are to accommodate oil-to-gas conversions throughout
NYC. Such expenditures are in the heart of the core market center, in particular, in
Manhattan, and therefore do not necessarily reflect a reasonable benchmark for new
generation located in Queens, Brooklyn or Staten Island. Moreover, the character and scale of
40
Although the NYDPS requires Con Edison and NGrid to identify capital expenditures, exactly how capital
outlays for infrastructure projects formulated under a CIAC are accounted for beyond the scope of this study.
59
the projects oriented around oil-to-gas conversion are not comparable to the lower character
of service considered applicable for a new combined cycle plant or peaker.
In regard to facility upgrade costs on Long Island, the best project example is NGrid’s
expansion in 2007-08 to serve the 330 MW Caithness combined cycle plant. In March and
April 2008 filings, overall costs for facility improvements and a lateral to the station were
provided. Increasing deliverability on Long Island by 200,000 Dth/d, to serve both Caithness
and incremental core customer demand were $53 million. In addition, the cost for the lateral
from NGrid’s system to the plant fieldgate at Caithness was $7.5 million to accommodate
60,000/Dth/d. Escalating the total construction costs of $60.5 million from 2008 to 2013
yields a project cost of $68.5 million. Exercising our professional judgment to account for
other system use and cost increase factors, we have adjusted this cost by an additional 50% to
$103 million. Consistent with NYDPS ratemaking criteria, under the CIAC formula, the allin project cost must then be grossed up for state and federal taxes.
The cost for a simple cycle unit was determined by scaling the MDQ ratio, resulting in a
construction cost estimate of $42 million, before tax gross-up. These costs have been applied
to Zone J improvements as well, as a baseline expansion estimate. The same facility
improvement costs apply for both 30-day interruptible and quasi-firm service. Capital cost
improvements consistent with a fully interruptible service would likely be significantly less,
but have not been addressed in this study.
In addition to the CIAC costs to reimburse Con Edison or NGrid for the cost of facility
improvements, there are other local tariff charges that need to be included. A generator
connected to the NYFS is subject to usage charges. Such charges differ in Zone J and Zone
K. In Zone J, the relevant rate is Con Edison’s SC-9 Transportation Service Rate for Power
Generation Transportation Customers of $0.192/Dth. In Zone K, the relevant rate is the SC14 Non-Core Transportation Service for Electric Generation, Rate Schedule 1 rate of
$0.24/Dth. Both rates are subject to the Value-Added Charge (VAC), estimated for purposes
of this analysis at $0.12/Dth. These rates offer access to a 335-day (30-day interruptible)
service. Both Con Edison and NGrid require that customers utilizing these services have 5
days of backup fuel available. Several additional terms apply to services, including MBOs of
50% and 60% of the annual transportation quantity for Con Edison and NGrid, respectively,
as well as certain restrictive balancing provisions. 41
Both Con Edison and NGrid can negotiate a rate schedule that is subject to different terms, for
example, curtailment limits. Incremental negotiated rates are not public. In our experience,
the cost of obtaining firm transportation rights on the NYFS is high. Exercising our
professional judgment, we have assumed that quasi-firm service would be negotiable at a
reasonable cost. Quasi-firm service would be equal to firm service, except on those days
when either Con Edison or NGrid is straining to keep up with conventional send-out
41
The applicability of the Minimum Bill Obligation has not been quantified in this study, but should be
recognized as a potentially includible incremental cost for units that do not meet the dispatch threshold
governing Con Edison’s or NGrid’s recoupment of various costs for peaking or low intermediate operation.
Imbalance resolution charges can also represent a significant additional economic burden, and have not been
quantified in this study.
60
requirements. On these days, Con Edison and/or NGrid would typically regasify LNG at one
or more satellite storage facilities in NYC and Long Island. We have made the assumption
that quasi-firm service can be available for approximately two-and-a-half times the respective
335-day service rate, plus VAC equal to $0.12/Dth.
Summary of Rate Estimates
The consolidated firm transportation charges for service along the selected path to each zone,
not including NYFS service charges, are summarized in Table 20 for both the combined cycle
and simple cycle technologies.
Table 20. Firm Interstate Pipeline Transportation Estimates by Zone
Zone
F
G-HI
J
K
Selected Path
Dominion
(from South Point)
Millennium 
Algonquin
Tennessee 
Texas Eastern
( NYFS)
Millennium 
Algonquin 
Iroquois
( NYFS)
100%
Load
Factor
Rate
($/Dth)
Combined Cycle (612 MW)
Annual
Unitized
Fixed
Variable
Charges
Charge
($ millions/year) ($/MWh)
Simple Cycle (200 MW)
Annual
Unitized
Fixed
Variable
Charges
Charge
($ millions/year) ($/MWh)
$0.6159
$23.8
$0.16
$9.7
$0.22
$1.0920
$43.6
$0.04
$17.8
$0.05
$1.1255
$45.0
$0.03
$18.4
$0.03
$1.6325
$65.2
$0.05
$26.7
$0.07
61
LEVELIZED ANNUAL COST COMPARISON
Modeling Approach
The levelized cost comparison utilizes the cost estimates presented above (Task 1A and Task
1B) in our financial model that calculates the impact on new generation revenue requirements
of a NYISO fuel assurance requirement. These results assume that the fuel assurance
requirement is met by either providing dual fuel capability or contracting for firm natural gas
delivery. The financial model can be applied to either intermediate load (combined cycle) or
peaking (simple cycle) capacity in each of the four selected New York zones – Capital
District, LHV, NYC, and Long Island.
The baseline for each generation type and each zone is a power plant without firm natural gas
transportation from a liquid trading point to the plant site (Capital District and LHV) or into
the NYFS with limited deliverability (e.g., 335 days) in Zones J and K. The costs of
obtaining either firm deliverability or adequate dual fuel capability are measured relative to
this baseline or reference case.
The incremental cost of securing that fuel assurance is measured in levelized dollars per kWyear of capacity using the same formulation as is used in developing CONE. Importantly,
LAI notes that the use of this convention should not be misconstrued as the provision of an
incentive for fuel assurance through the capacity market.
The cost elements in the model include the following:
1. Baseline Case – Interruptible natural gas transportation and/or delivery service, no
backup fuel.
a. Effective annual fixed charges for interruptible service on the NYFS that
would arise due to MBO provisions of the relevant tariffs under dispatch
regimes representative of peaking technology.
b. Credit for Net Energy Margin
i. Energy revenues from dispatch based on relevant variable costs, and
excluding assumed natural gas curtailment hours. Curtailment hours
are based on recent historical levels of pipeline congestion along key
route segments.
ii. Less natural gas commodity cost based on prices at sourcing point for
interruptible transportation/delivery. These natural gas prices reflect
volatility in basis relative to upstream supply points associated with
congestion during extreme peak periods.
iii. Less variable natural gas transportation costs not included in MBO
iv. Less other relevant variable O&M costs
2. Dual Fuel Case – Interruptible natural gas transportation and/or delivery service and
provisions for dual fuel capability using ULSD. (Note: The Dual Fuel Case
effectively replaces the Baseline Case for NYC and Long Island, since duel fuel
capability is an effective requirement to receive interruptible service on the NYFS.)
62
a. Recovery of incremental plant capital cost for dual fuel capability, including
power island scope additions, fuel oil system with appropriate storage tankage,
and balance of plant costs.
b. Annual costs to reserve dedicated ULSD delivery capacity via truck or barge
c. Carrying charges on the cost of backup fuel inventory based on 5 days of full
load operation.
d. Incremental fixed O&M associated with dual fuel capability (including
staffing, property tax and insurance).
e. Effective annual fixed charges for interruptible service on the NYFS arising
from the MBO provisions of the relevant tariffs under dispatch regimes
representative of peaking technology.
f. Credit for Net Energy Margin
i. Energy revenues from dispatch based on relevant variable costs for
operation on natural gas during non-curtailment hours, and for ULSD
during natural gas curtailment hours. Curtailment hours are the same
as those used in the Baseline Case.
ii. Less natural gas commodity cost based on prices at sourcing point for
interruptible transportation/delivery. Natural gas commodity prices are
the same as those used in the Baseline Case.
iii. Less variable natural gas transportation costs not captured in MBO
iv. Less ULSD inventory
transportation)
replenishment
costs
(commodity
and
v. Less other relevant variable O&M costs applicable to generation using
each fuel
3. Firm Transportation Case – Natural gas sourced at a liquid trading point with firm
transportation on the interstate pipeline system and, if applicable, quasi-firm delivery
service on NYFS. Dual fuel capability is provided in NYC and Long Island to cover
interruptions under quasi-firm delivery terms.
a. Recovery of incremental plant capital cost for dual fuel capability, including
gas turbine scope additions, fuel oil system with appropriate storage tankage,
and balance of plant cost for NYC and Long Island only.
b. Annual reservation charges on interstate pipeline system(s) to secure firm
transportation service.
c. Annual costs to reserve dedicated ULSD delivery capacity via truck or barge
for NYC and Long Island only.
d. Carrying charges on the cost of backup fuel inventory.
e. Incremental fixed O&M associated with dual fuel capability (including
staffing, property tax and insurance).
63
f. Effective annual fixed charges, for quasi-firm service on the NYFS arising
from the MBO provisions of the relevant tariffs under dispatch regimes
representative of peaking technology.
g. Credit for Net Energy Margin
i. Energy revenues from dispatch based on relevant variable costs,
including natural gas curtailment hours assumed to be avoided.
ii. Less natural gas commodity cost based on prices at sourcing point for
firm transportation/delivery (generally upstream of the sourcing point
for interruptible transportation and therefore, less volatile during
extreme peak load conditions).
iii. Less variable natural gas transportation costs not included in MBO
iv. Less ULSD inventory replenishment costs
transportation) for NYC and Long Island only
(commodity
and
v. Less other relevant variable O&M costs
LAI has not estimated the value to a generator holding firm transportation rights that may be
derived from the release of such capacity rights when delivered gas is trading at a large
premium relative to the cost of gas into-the-pipe. Likewise, the chance of increasing net
margin by operating on ULSD when profits from releasing primary transportation are
available has not been tested. We have made the simplifying assumption that NYISO
incentives for firm transportation entitlements is tantamount to increased gas use for power
generation when pipeline conditions are constrained during the peak heating season.
Economic and Financial Assumptions
We have calculated levelized costs in a manner consistent with that used in the NYISO Study.
The inflation rate is assumed to be 2.4% per year. The underlying assumptions for cost of
capital, capital structure, and depreciation period are identical to those used in the NYISO
Study.42 LAI independently calculated the WACC and capital charge rates that are
necessarily lower in Zone J than for the other zones. The capital charge rates, expressed in
constant dollars per dollar of base year investment, are summarized in Table 21 for each
technology and zone, reflecting different MACRS tax depreciation lives by technology and
Zone J’s higher composite income tax rate.
42
We noticed that the 2010 NYISO Study may have an inconsistency, namely, the after-tax returns on equity
(ROE) are identical for all zones, as are the weighted average cost of capital (WACC) values, in spite of the
combined effective income tax rate being higher in Zone J.
64
Table 21. Carrying Charge Rates
Technology
Zones
Amortization Life
Debt Fraction
Debt Interest
After Tax Equity IRR
MACRS Tax Life
Composite Tax Rate
After Tax WACC /
Discount Rate
Real Levelized
Carrying Charge on
Plant Capital Cost
Real Levelized
Carrying Charge on
Inventory
Combined Cycle
NYC
Rest of State
Simple Cycle
NYC
Rest of State
30
50%
7.25%
12.48%
20
15
45.37%
39.62%
45.37%
39.62%
8.22%
8.43%
8.22%
8.43%
9.95%
9.57%
9.52%
9.23%
14.69%
13.63%
14.69%
13.63%
Furthermore, we have assumed a set of prices in 2013 dollars for natural gas commodity,
ULSD commodity, and zonal electric energy to allow estimation of net energy margin effects.
The fuel commodity prices are shown in Table 22. NYH and Henry Hub prices are based on
recent forward quotes for each month of the year. Basis differentials for natural gas are based
on an analysis of three years of market data. The “winter peak” pricing reflects the highest 7day rolling average basis differential relative to Henry Hub observed over 3 years of data.
65
Table 22. Assumed 2013 Fuel Commodity Prices
Season
ULSD ($/gallon)
NYH Commodity
Delivery Premium
Capital District
LHV
NYC
Long Island
Natural Gas ($/MMBtu)
Henry Hub
Transco Z6 non-NY
Transco Z6 NY
DTI South Point
DTI North Point
Millennium – East Receipts
Tennessee Zone 4-300 Leg
Tennessee Zone 6-200 Leg
Iroquois Zone 2
Iroquois Zone 1
Algonquin City Gates
Apr-Nov
Winter
$3.100
$3.200
$0.058
$0.058
$0.032
$0.032
$0.058
$0.058
$0.032
$0.032
$3.403
$3.660
$3.720
$3.498
$3.230
$3.269
$3.034
$4.003
$4.002
$4.516
$4.012
$3.403
$4.715
$5.684
$3.538
$3.573
$3.460
$3.307
$5.627
$5.628
$5.490
$5.733
Winter Peak
$3.657
$12.417
$22.357
$4.231
$4.453
$3.937
$3.937
$20.034
$20.644
$18.204
$20.467
The principal driver for the economic advantage of FT over IT (with or without ULSD
backup) is the net energy margin derived from operation on natural gas with a relatively low
variable cost. This margin was found to offset FT reservation charges for the combined-cycle
plant in both the Capital District and the LHV. Notably, when we postulate utilization of FT
we assume that the generator bids cost into the Day Ahead Market (DAM), not value. This
means that the relevant cost bid into the DAM is the commodity cost of gas at the liquid
sourcing point plus the sum of pipeline variable transport cost, shrinkage, and non-fuel plant
variable O&M cost. As shown in Table 22, the typical gas commodity cost at upstream
receipt points such as Dominion South Point (DTI-SP), Tennessee Zone 4 Leg 300, and
Millennium East Receipts are lower than the gas commodity cost at pricing points deep in the
market, i.e., Transco Zone 6 New York (TZ6NY), Algonquin City Gates (AGT Citygates),
Iroquois Zone 2 (IGTSZ2), and Tennessee Zone 6 Leg 200 (TNZ6).
The price differential is magnified throughout the heating season, November through March,
in particular, the coldest days that occur in late December, January and February. After
adding the relatively low usage and shrinkage rates to the commodity cost of gas, the
delivered variable cost of firm natural gas is significantly lower than the delivered cost of
natural gas under the IT option. Hence, dispatch on FT is higher than dispatch on IT, and net
margin derived from energy sales is higher on FT than dispatch on IT.
Electric energy prices for each zone were estimated to produce reasonable ranges for each
“season” and to allow for estimation of dispatch hours as a function of variable cost. Price
ranges for the Capital District zone are shown in Figure 26. The price distributions are similar
for the other zones. The dispatch algorithm used in this study uses a simplified representation
66
of fuel and energy prices over a single sample year. A more detailed simulation of daily gas
and hourly energy price dynamics over a study period with changing market conditions might
result in different relative positions for FT and IT.
Figure 26. Assumed Energy Price Ranges for Capital District
$350
Capital District
Energy Price Range ($/MWh)
$300
$250
$200
$150
$100
$50
$0
1,530 h/yr
1,390 h/yr
1,530 h/yr
1,070 h/yr
320 h/yr
1,530 h/yr
1,070 h/yr
320 h/yr
Off Peak
Normal
Peak
Off Peak
Normal
Peak
Super Peak
Off Peak
Normal
Peak
Super Peak
Spr-Fall
Summer
Winter
The unit variable operating cost for each technology, region, fuel option, and time period was
calculated as the product of the applicable variable fuel cost and the applicable heat rate, plus
appropriate variable O&M costs.
(Fuel options are natural gas with interruptible
transportation, natural gas with firm transportation, and ULSD.)
For each technology, region, fuel option, and time period, a dispatch factor was calculated
using the appropriate unit variable operating cost and energy price range. If the unit variable
cost was greater than the minimum energy price, dispatch factor was set at zero. If the unit
variable operating cost was less than the maximum energy price, dispatch factor was set at
100%. Where unit variable operating cost fell within the price range, dispatch factor was
calculated by linear interpolation:
DF = (EPmax – UVOC) / (EPmax – EPmin).
For each technology, region, fuel option, and time period, average dispatched energy price is
determined from dispatch factor as follows:
ADEP = EPmax – 0.5 * DF * (EPmax – EPmin)
67
For each technology, region, fuel option, and time period, period net energy margin is
calculated as period energy revenue less period variable operating cost Period energy revenue
is the product of period hours (reflecting any gas curtailment), output capacity, dispatch
factor, and average dispatched energy price. Period variable operating cost is the product of
the same period hours, output capacity, dispatch factor, and unit variable operating cost.
Annual net energy margin for each technology in each region is calculated as the sum of the
eight period net energy margin amounts for the appropriate fuel options. For example, for the
Dual Fuel strategy in LHV, the annual net energy margin would be the sum of the eight
period net energy margin amounts for interruptible natural gas plus the corresponding eight
period net energy margin amounts for ULSD. For the Firm Natural Gas strategy in LHV, the
annual net energy margin would be the sum of the eight period net energy margin amounts for
firm natural gas. The firm natural gas strategy in NYC or Long Island would include a ULSD
case, since gas delivery would remain non-firm.
Results
Results are summarized for the four zones of interest in Table 23, Table 24, Table 25, and
Table 26 below.
Table 23. Levelized Revenue Requirement Results – Capital District
(2013 $)
Technology Type
Baseline Case
Natural Gas Source
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Levelized Costs ($/kW-yr)
Dual Fuel Case
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Firm Transportation Case
Natural Gas Source
Natural Gas Path
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Differential v. Dual Fuel Case
68
Combined Cycle
Simple Cycle
TGPZ6 200
500
4,324
($ 73.87)
TGPZ6 200
500
1,497
($ 32.51)
112
($ 72.62)
($ 1.25)
67
( $ 25.60)
$ 6.91
DTI South Point
Dominion
0
7,547
0
($121.39)
($ 47.52)
($ 48.76)
DTI South Point
Dominion
0
3,110
0
($ 47.60)
($ 15.09)
($ 22.00)
Table 24. Levelized Revenue Requirement Results – LHV
(2013 $)
Technology Type
Baseline Case
Natural Gas Source
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Levelized Costs ($/kW-yr)
Dual Fuel Case
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Firm Transportation Case
Natural Gas Source
Natural Gas Path
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Differential v. Dual Fuel Case
Combined Cycle
Simple Cycle
Iroquois Zone 2
300
4,963
($ 83.54)
Iroquois Zone 2
300
1,725
($ 38.91)
77
($ 80.39)
($ 3.15)
51
( $ 31.20)
$ 7.70
Millennium East Receipts Millennium East Receipts
Millennium  Algonquin Millennium  Algonquin
0
0
7.964
3,952
0
0
($111.24)
($ 26.56)
($ 27.70)
$ 12.34
($ 30.85)
$ 4.64
Table 25. Levelized Revenue Requirement Results – NYC
(2013 $)
Technology Type
Baseline Case
Natural Gas Source
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Levelized Costs ($/kW-yr)
Dual Fuel Case
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Firm Transportation Case
Natural Gas Source
Natural Gas Path
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Differential v. Dual Fuel Case
Combined Cycle
Simple Cycle
Transco Zone 6 NY
720
4,999
($ 66.05)
Transco Zone 6 NY
720
1,900
($ 9.20)
170
($ 68.33)
($ 2.28)
121
($ 3.09)
$ 6.12
Tennessee Zone 4
300 Leg
Tennessee  Texas
Eastern  NYFS
336
7,369
89
($ 94.47)
($ 28.41)
($ 26.13)
Tennessee Zone 4
300 Leg
Tennessee  Texas
Eastern  NYFS
336
3,328
64
$ 44.33
$ 53.53
$ 47.42
69
Table 26. Levelized Revenue Requirement Results – Long Island
(2013 $)
Technology Type
Baseline Case
Natural Gas Source
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Levelized Costs ($/kW-yr)
Dual Fuel Case
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Firm Transportation Case
Natural Gas Source
Natural Gas Path
Natural Gas Curtailment (h/yr)
Dispatch on Gas (h/yr)
Dispatch on ULSD (h/yr)
Levelized Costs ($/kW-yr)
Differential v. Baseline Case
Differential v. Dual Fuel Case
Combined Cycle
Simple Cycle
Iroquois Zone 2
720
5,279
($ 75.54)
Iroquois Zone 2
720
1,957
($ 11.00)
184
($ 82.83)
($ 7.30)
138
($ 9.74)
$ 1.26
Millennium East
Receipts
Millennium 
Algonquin 
Iroquois  NYFS
336
7,189
96
($ 84.19)
($ 8.65)
($ 1.36)
Millennium East
Receipts
Millennium 
Algonquin 
Iroquois  NYFS
336
3,094
73
$ 76.49
$ 87.49
$ 86.23
Differential levelized annual revenue requirements between the Dual Fuel Case and the
Baseline Case are shown in Figure 27. Note that dual fuel capability provides an economic
benefit for combined cycle plants in NYC and Long Island and a positive cost for combined
cycles in the Capital District and LHV. The Dual Fuel Case has a positive cost for the simple
cycle plants in each zone. While the bold colored bars above the x-axis represent reasonable
estimates of hard capital and operating costs, the striped bar for net energy margin is based on
more volatile and uncertain estimates of fuel prices and zonal energy prices.
70
Figure 27. Differential Revenue Requirements for Dual Fuel Capability
Dual Fuel Capability v. Interruptible Gas-Only
$15
Net Energy
Margin
Levelized Annual Cost (2013 $/kW-yr)
$10
ULSD Delivery
Capacity
Reservation
$8
$7
$6
$5
Incremental
Fixed O&M
$3
$1
$1
$0
NYFS MBO
Charges
($2)
($5)
Pipeline
Reservation
Charges
($7)
($10)
Inventory
Carrying Cost
($15)
Recovery of
Incremental
Capital
($20)
CC
SC
Capital District
CC
SC
Lower Hudson Valley
CC
SC
New York City
CC
SC
Total Levelized
Cost
Long Island
The differential levelized annual revenue requirements for the Firm Transportation Case,
relative to the Baseline Case, are shown in Figure 28. In this chart, firm transportation
provides savings for both technologies in the Capital District and LHV, based on the higher
availability and lower unit variable cost of gas, relative to the pipeline reservation charges.
For the NYC and Long Island Zones, the Firm Transportation Case includes the only quasifirm delivery at the local level and the cost of dual fuel capability. Fuel assurance relative to
interruptible gas-only is a break-even proposition for a combined cycle plant and a losing
option for a simple cycle plant.
71
Figure 28. Differential Revenue Requirements for Firm Transportation
Firm Transportation v. Interruptible Transportation
$150
Net Energy
Margin
Gas-Only FT v. Gas-Only IT
Dual-Fuel FT v. Gas-Only IT
$100
Levelized Annual Cost (2013 $/kW-yr)
$87
Incremental
Fixed O&M
$54
$50
ULSD Delivery
Capacity
Reservation
NYFS MBO
Charges
$12
$0
($9)
($15)
($28)
Pipeline
Reservation
Charges
($28)
($48)
($50)
Inventory
Carrying Cost
($100)
Recovery of
Incremental
Capital
($150)
CC
SC
Capital District
CC
SC
Lower Hudson Valley
CC
SC
New York City
CC
SC
Total Levelized
Cost
Long Island
Figure 29 compares a more practical set of fuel assurance options against “status quo”
conditions. For the Capital District and LHV, the “status quo” cases represent gas-only with
interruptible transportation, as in Figure 28. For NYC and Long Island, the “status quo” cases
represent the Dual Fuel Capability Case. Hence, the differentials reflect the addition of firm
pipeline transportation and quasi-firm delivery over the NYFS, with credits for reduced tank
volume and inventory costs for ULSD. Firm transportation is clearly advantageous for
combined cycles in the upstate zones and NYC, but is generally less attractive or “out-of-themoney” for simple cycle applications. Firm transportation is essentially neutral for a
combined cycle on Long Island.
72
Figure 29. Differential Revenue Requirements for Firm Transportation v. Status Quo
Firm Transportation v. "Status Quo"
$150
Net Energy
Margin
Levelized Annual Cost (2013 $/kW-yr)
Gas-Only FT v. Gas-Only IT
Dual-Fuel FT v. Dual-Fuel IT
$100
$86
ULSD Delivery
Capacity
Reservation
Incremental
Fixed O&M
$50
$47
NYFS MBO
Charges
$12
$0
Pipeline
Reservation
Charges
($1)
($15)
($26)
($28)
Inventory
Carrying Cost
($48)
($50)
Recovery of
Incremental
Capital
($100)
CC
SC
Capital District
CC
SC
Lower Hudson Valley
CC
SC
New York City
CC
SC
Total Levelized
Cost
Long Island
Differentials for the components of levelized annual revenue requirements are shown for the
Dual Fuel Case and the Firm Transportation Case for the Capital District in Figure 30. For
the combined cycle technology, dual fuel capability offers small savings, while firm gas
transportation offers a much larger net benefit, despite the high pipeline reservation costs.
The benefits in either case arise from estimates of future gas, ULSD, and electric energy
prices. Due to the comparatively high assumed dispatch of the peaking generation plant in the
Capital District, the simple cycle technology with dual fuel capability does not provide a net
benefit, but firm transportation does provide a net benefit. Of the $77.68/kW-yr Net Energy
Margin benefit indicated for the firm transmission with the combined cycle technology,
$61.96/kW-yr is attributable to lower gas commodity unit costs and $15.72 to avoided
curtailment hours. For the simple cycle technology, $43.65/kW-yr of the Net Energy Margin
benefit is attributable to lower gas commodity unit costs and $9.20/kW-yr to avoided
curtailment hours.
A factor influencing the relative economics of firm transportation versus interruptible
transportation is the selection of the GE LMS100 technology as the representative peaker.
This combustion turbine model has a significantly lower heat rate than the industrial frame
machines that have been used for CONE in the upstate zones, or, for that matter, the
aeroderivative LM6000 units used in early downstate CONE studies. Based on information
from GE, we have used a heat rate of 9,134 Btu/kWh (HHV) on natural gas and 8,892
Btu/kWh (HHV) on ULSD. While much higher than the heat rates assumed for the combined
cycle plant, the simple cycle heat rates are still low enough to dispatch at much higher levels
than would older technology combustion turbines. The comparatively low heat rate and
73
cycling efficiency of the LMS100 technology helps to explain the magnitude of the net
margin derived from energy sales under firm transportation for a peaker in the Capital
District.
Figure 30. Capital District Incremental Revenue Requirement Components
Capital District - Incremental Cost v. Gas-Only IT
Levelized Annual Cost (2013 $/kW-yr)
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Dual-Fuel IT
Gas-Only FT
Dual-Fuel IT
Combined Cycle
Gas-Only FT
Simple Cycle
Net Energy Margin
($6.68)
($77.68)
($2.85)
($52.85)
ULSD Delivery Capacity Reservation
$1.20
$0.00
$1.44
$0.00
Incremental Fixed O&M
$0.92
$0.00
$1.25
$0.00
NYFS MBO Charges
$0.00
$0.00
$0.00
$0.00
Pipeline Reservation Charges
$0.00
$30.16
$0.00
$37.76
Inventory Carrying Cost
$2.83
$0.00
$3.40
$0.00
Recovery of Incremental Capital
$2.97
$0.00
$3.67
$0.00
Total Levelized Cost
$1.25
($47.52)
$6.91
($15.09)
Figure 31 shows the same information for the LHV zone, which exhibits the same relative
costs and benefits among the cases. As is the case with the Capital District, the vast majority
of the Net Energy Margin benefit from firm gas transportation is derived from lower
commodity costs rather than avoided curtailment hours.
74
Figure 31. LHV Incremental Revenue Requirement Components
Levelized Annual Cost (2013 $/kW-yr)
Lower Hudson Valley - Incremental Cost v. Gas-Only IT
$80
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Dual-Fuel IT
Gas-Only FT
Dual-Fuel IT
Combined Cycle
Gas-Only FT
Simple Cycle
Net Energy Margin
($5.03)
($82.99)
($2.27)
($56.89)
ULSD Delivery Capacity Reservation
$1.20
$0.00
$1.44
$0.00
Incremental Fixed O&M
$0.97
$0.00
$1.29
$0.00
NYFS MBO Charges
$0.00
$0.00
$0.00
$0.00
Pipeline Reservation Charges
$0.00
$55.29
$0.00
$69.23
Inventory Carrying Cost
$2.83
$0.00
$3.40
$0.00
Recovery of Incremental Capital
$3.18
$0.00
$3.84
$0.00
Total Levelized Cost
$3.15
($27.70)
$7.70
$12.34
Figure 32 shows the differential revenue requirement components between the Firm
Transportation Case and the Dual Fuel Case for Zone J. This chart is dominated by the
pipeline reservation charges and the corresponding net energy margin benefits of firm
transportation. Avoided costs related to reduced ULSD tankage capacity and reduced
inventory carrying cost are relatively minor.
75
Figure 32. NYC Incremental Revenue Requirement Components
Levelized Annual Cost (2013 $/kW-yr)
New York City - Incremental Cost v. Dual-Fuel IT
$100
$80
$60
$40
$20
$0
($20)
($40)
($60)
($80)
($100)
Net Energy Margin
Dual-Fuel FT
Dual-Fuel FT
Combined Cycle
Simple Cycle
($80.71)
($29.86)
ULSD Delivery Capacity Reservation
$0.00
$0.00
Incremental Fixed O&M
($0.11)
($0.09)
NYFS MBO Charges
$0.00
$8.60
Pipeline Reservation Charges
$56.94
$71.29
Inventory Carrying Cost
($1.82)
($2.18)
Recovery of Incremental Capital
($0.44)
($0.34)
Total Levelized Cost
($26.13)
$47.42
Figure 33 shows similar information for the Long Island zone.
76
Figure 33. Long Island Incremental Revenue Requirement Components
Long Island - Incremental Cost v. Dual-Fuel IT
Levelized Annual Cost (2013 $/kW-yr)
$150
$100
$50
$0
($50)
($100)
Net Energy Margin
Dual-Fuel FT
Dual-Fuel FT
Combined Cycle
Simple Cycle
($81.85)
($27.97)
ULSD Delivery Capacity Reservation
$0.00
$0.00
Incremental Fixed O&M
($0.11)
($0.09)
NYFS MBO Charges
$0.00
$13.10
Pipeline Reservation Charges
$82.71
$103.55
Inventory Carrying Cost
($1.69)
($2.03)
Recovery of Incremental Capital
($0.42)
($0.33)
Total Levelized Cost
($1.36)
$86.23
Conclusions
The following general conclusions arise from the economic/financial analysis:

When compared to gas-only operation with interruptible transportation, dual fuel
capability is accretive for combined cycle facilities in the NYC and Long Island zones
and dilutive in the Capital District and LHV zones.

When compared to gas-only operation with interruptible transportation, dual fuel
capability is dilutive for simple cycle facilities in all four zones considered.

When compared to gas-only operation with interruptible transportation, gas-only
operation with firm transportation is accretive for combined cycle facilities in the
Capital District and LHV zones. The comparison is not relevant for the NYC and
Long Island zones.

When compared to gas-only operation with interruptible transportation, gas-only
operation with firm transportation is accretive for a simple cycle facility in the Capital
District zone, but dilutive for a simple cycle facility in the LHV zone. The
comparison is not relevant for the NYC and Long Island zones.

When compared to dual fuel operation with interruptible pipeline transportation and
30-day interruptible delivery service over NYFS, dual fuel operation with firm
pipeline transportation and quasi-firm delivery service over NYFS is accretive for a
77
combined cycle facilities in the NYC zone and neutral for a combined cycle facility in
the Long Island zone.

When compared to dual fuel operation with interruptible pipeline transportation and
30-day interruptible delivery service over NYFS, dual fuel operation with firm
pipeline transportation and quasi-firm delivery service over NYFS is dilutive for
simple cycle facilities in the NYC and Long Island zones.

In the final analysis, generators’ risk tolerance may support a non-firm transportation
strategy based on perceived improvements in deliverability conditions across NYCA,
producers’ willingness to arrange supplies in the market area, and relatively light
penalties for non-performance due to fuel delivery constraints. Notwithstanding the
economic rationale for firm transportation from a liquid sourcing point to the relevant
zone in New York State, current market signals are likely to support gas-fired
generators’ contract preference for non-firm transportation arrangements in the Capital
District, LHV, and across the New York Facilities System.
78