PUBLIC VERSION

NAVIGANT

FINAL REPORT: ECONOMIC ANALYSIS
AND FINDINGS RELATED TO
PROPOSALS FOR LIOUFIED NATURAL
GAS STORAGE CAPACITY

  

Prepared for:

 

State of Maine, Public Utilities Commission
Division of Purchases

Burton M. Cross Building

111 Sewell Street, 4th Floor

Augusta, ME 04330

Submitted by.
Gordon Pickering, Director

Navigant Consulting, Inc.

35 Iron Point Circle, Suite 225
Folsom, CA 95630
916.631.3249 (direct)
916.201.7475 (mobile)
navigant.com

State of Maine 201609179
December 28, 2016

Final Report: Economic Analysis and Recommendations

AVIGANT Related to Proposals for LNG Storage Capacity

 

DISCLAIMER i
1. Executive Summary 1
2. Introduction 3
3. Overview of Maine Natural Gas Market 4
3.1. Total Gas Demand 4
3.2. Market Access and Infrastructure 7
3.3. Maine Local Distribution Companies 11
3.4. Regional Market Overview 15
3.5. Maine Sources of Supply 16
3.6. Natural Gas Prices 18
4. Overview of Maine Wholesale Electric Power Market 22
4.1. Total Electric Demand 22
4.2. Supply Sources and Trends 24
4.3. Reserve Margin 25
4.4. Maine Forecast Results 26
4.4.1. Load and Generation Balance 26
4.4.2. LMP Summary 27
4.4.3. Consumer Wholesale Payments 28
4.4.4. Fuel Requirements 29
4.4.5. Comparison Between Access Northeast Scenarios 30
5. General Overview of PESC Bids 31
6. Detailed Methodology 32
6.1. Model Description 32
6.2. Model Assumptions 33
6.3. Benefit Analysis 35
7. Analysis of PESC Bids 37
7.1. Cavus 37
7.1.1. With Access Northeast 38

7.1.2. Without Access Northeast 39

PUBLIC VERSION



7.2. Eagle Partners 40
7.2.1. With Access Northeast 40
7.2.2. Without Access Northeast 41
7.3. Engie 42
7.3.1. With Access Northeast 42
7.3.2. Without Access Northeast 43
7.4. Maine Energy Storage (Northern) 44
7.4.1. With Access Northeast 45
7.4.2. Without Access Northeast 45
7.5. 46
7.5.1. With Access Northeast 46
7.5.2. Without Access Northeast 47
7.6. Reliable 48
7.6.1. With Access Northeast 48
7.6.2. Without Access Northeast 49
7.7. Summary of PESC Bid Total Net Bene?ts 5O
8. Other Factors 51
8.1. Without Access Northeast Scenario 51
8.2. Use of Average Prices 52
8.2.1. With Access Northeast 52
8.2.2. Without Access Northeast 53
8.3. Historical Snapshot Review 53
8.4. Power Market Impacts 54
9. Findings 54
APPENDIX A 56
APPENDIX 57
APPENDIX 58
APPENDIX 59

APPENDIX 60

Final Report: Economic Analysis and Findings Related to

AVIGANT Proposals for LNG Storage Capacity

 

This report was prepared by Navigant Consulting, Inc. (Navigant) for the State of Maine, Public Utilities
Commission. The work presented in this report represents Navigant?s professional judgment based on the
information available at the time this report was prepared. Navigant is not responsible for the reader?s use
of, or reliance upon, the report, nor any decisions based on the report. NAVIGANT MAKES NO
REPRESENTATIONS OR WARRANTIES, EXPRESSED OR IMPLIED. Readers of the report are advised
that they assume all liabilities incurred by them, or third parties, as a result of their reliance on the report,
or the data, information, ?ndings and opinions contained in the report.

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1. Executive Summary

In accordance with certain legislation, the State of Maine has sought proposals for Physical Energy
Storage Contracts (PESC), speci?cally in the form of lique?ed natural gas (LNG). The legislation, 2016
Legislative Session Public Law, Chapter 445, LD 881, provides that the Public Utilities Commission may
execute or direct one or more transmission and distribution utilities, gas utilities, or natural gas pipeline
utilities to execute a PESC subject to certain showings being made. Navigant has been retained by the
State to assist in estimating and evaluating the relative costs and bene?ts of the proposed PESCs.
According to the legislation, for a contract to meet program requirements the overall costs of the contract
need to be outweighed by its bene?ts to electricity consumers, gas consumers, or both in the State.

Navigant has structured the cost-bene?t analyses so as to capture the overall impact on estimated gas
supply costs to a party or parties contracting for LNG storage through a PESC pursuant to the program.
At a high level, the analysis starts with the avoided cost of winter-time peak) gas purchases due to
the stored LNG, less the summer-time non-peak) gas cost to ?ll the storage facility, less the contract
costs to provide the storage service. The net of these ?gures represents the net bene?t of the PESC.
Navigant utilized four annual ?snapshot" years around which the analysis is built, and then estimated
annual ?gures for the intervening years in order to produce an NPV result of the net benefit estimated for
each of the 11 contract options bid in total by six bidders.

The parameters of PESC bids covered a range of key aspects of proposed facilities from facility size and
operating characteristics, to various components of contract costs. The main physical parameters
included the capacity of the proposed LNG storage tanks, the vaporization rate and/or number of storage
withdrawal days, and the ?ll rate for the storage tanks. Cost-related parameters included ?xed and
variable costs and the rates of vaporization and/or liquefaction fuel loss/use. The LNG tank sizes were
generally spread between one and two Bcf, with varying vaporization rates contributing to various total
days of LNG use out of storage. Fill time for liquefaction-based projects varied from 100 days to about
240 days, as a function of tank size and ?ll rate. The estimation of contract costs for the PESC options
followed from the bids as proposed. Fixed costs, variable costs, fuel use and vaporization losses were
factored in as proposed. One cost factor estimated by Navigant as discussed is an LNG premium to
represent extra fill costs associated with trucked-in LNG options.

For purposes of estimating the peak value of the LNG, Navigant utilized its Daily Gas Model. The price in
each snapshot applicable to the avoided peak price of LNG-based supply is derived as the average of the
top 15 days falling in the two-month winter period (assumed as January and February) in each snapshot
year. This methodology yields a more conservative analysis higher PESC valuation). To provide a
less conservative outlook on which to analyse the PESCs, we have also presented results using average
wintertime prices. In addition, Navigant has included scenarios both with the Access Northeast pipeline
project and without the project, to further bookend the analyses with less conservative and more
conservative price forecasts, respectively. The choice of Access Northeast, a proposed pipeline
expansion in New England with potential impact on the Maine market, is discussed in more detail in
Section 6.2. The pricing point used in the analysis is Tennessee Gas Pipeline Zone 6-delivered, a liquid
point with applicability for northern New England and for Maine given the lack of liquid gas trading points
in the Maine market itself.

Since our assumptions show that the contracting party, eg. an LDC, may not have suf?cient load by itself
to use the full vaporization rate under a PESC, we assume that as ?holder? or ?owner" of the PESC, the

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LDC would be in a position to maximize value of the PESC (say by selling excess gas at peak), in order
to bene?cially offset contract costs that it would be subject to paying. Thus, the operative metric for
comparison is assumed to be the net bene?t of a bid option incorporating the total bid volume, regardless
of the ultimate disposition of the stored LNG. This assumption is consistent with the assumption that
direct contract costs and bene?ts realized as a result of a PESC will ?ow to the ratepayers of the
contracting entity. Nevertheless, Navigant?s analysis provides breakouts of contract volume across
different allocation categories LDC, Maine, out-of-state) of the stored LNG to provide tracking for
informational purposes.

After accounting for tank ?ll costs, annual contract costs are netted out from the commodity bene?t in
order to arrive at an annual cost-bene?t result in each snapshot year. It should be noted that Navigant?s
analysis indicates minimal impact of the LNG storage projects on the actual levels of natural gas market
prices applicable to Maine, as well as to the electric market prices (locational marginal prices, or LMPs)
for Maine. This means that the net bene?ts calculated in the analyses all relate only to contract volumes,
and not to any other natural gas transacted in the markets.

As can be seen in Table 1, representing the PESC option net present value (NPV, calculated at a 4% real
discount rate) and return on investment (ROI) under the ?with Access Northeast? scenario analysis (using
peak prices), of the 11 PESC options analysed in this report perhaps unexpectedly only one provided a
positive NPV, and that project only yielded a 3.2% return on investment, a low result for typical
investment criteria. Thus, Navigant?s ?ndings in this instance are that if the PUC decides to go forward
with any one of the PESCs as proposed, it would be for objectives other than pure economic return.

Table 1: PESC Option NPV and ROI, With Access Northeast

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 5.8 3.2%

Engie 2 (8.2) 
Reliable 2 (11.7) 
Engie 1 (41.8) -15.0%
2 (33.2) -15.3%
Reliable 1 (43.7) -22.2%
Cavus 2 (65.8) -35.1%
Northern 1 (98.4) -40.1%
Cavus 1 (97.7) -44.4%
Eagle Partners 2 (22.0) -69.2%
Eagle Partners 1 (28.0) -85.1%

 

 

We note, however, the sensitivity of the results to the exclusion of the Access Northeast pipeline project,
for which we have included another scenario in the report that indicates favorable results for some PESC
options. If there were indications that the project would not go forward, then there could be an impact on
the ?ndings, as shown in Table 2, below, where seven PESC options have a positive NPV.

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Table 2: PESC Option NPV and ROI, Without Access Northeast

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 109.1 60.7%
?yie 2 136.8 55.7%
Reliable 2 126.8 49.1%
?yie 1 103.2 37.0%
2 70.1 32.0%
Reliable 1 42.8 21.6%
Cavus 2 3.1 1.6%

Northern 1 (15.7) 
Cavus 1 (28.8) -13.0%
gale Partners 2 (16.4) -51.6%
gale Partners 1 (25.2) -76.6%

 

 

 

 

 

2. Introduction

In accordance with certain legislation, the State of Maine has sought proposals for Physical Energy
Storage Contracts, speci?cally in the form of lique?ed natural gas (LNG). The legislation, 2016
Legislative Session Public Law, Chapter 445, LD 881, provides that the Public Utilities Commission may
execute or direct one or more transmission and distribution utilities, gas utilities, or natural gas pipeline
utilities to execute a PESC subject to certain showings being made. As a result of the State?s RFP for
PESCs, issued on September 14, 2016 with an ultimate due date of November 4, 2016, a number of
contract proposals have been submitted to the state for evaluation. As we understand, the State has
issued its Storage Contract RFP in the interest of mitigating high natural gas prices during the wintertime
peak periods or in the event of upstream natural gas infrastructure disruptions. LNG storage can be
located close to load centers, thereby making peak volumes of gas directly available to the system in
order to reduce costs and increase reliability. Navigant has been retained by the State to assist with this
evaluation.

The evaluation is speci?cally informed by the legislation?s stated requirements for PESCs. Most notably,
an important factor in the proposal evaluation concerns a cost-bene?t analysis of the proposals, in
addition to other stated criteria. According to the legislation, the PESC should be economically bene?cial
to electricity consumers, gas consumers, or both in the State, and the overall costs of the contract are to
be outweighed by its bene?ts to electricity consumers, gas consumers, or both in the State. Navigant has
structured the cost-bene?t analyses so as to capture the overall impact on estimated gas supply costs to
a party or parties contracting for LNG storage through a PESC pursuant to the program. At a high level,
the analysis starts with the avoided cost of winter-time peak) gas purchases due to the stored LNG,
less the summer-time non-peak) gas cost to ?ll the storage facility, less the contract costs to provide
the storage service. The net of these ?gures represents the net bene?t of the PESC.

In order to estimate peak period natural gas prices on a forecast basis, Navigant made use of its natural
gas Daily Model, a specialized version of Navigant?s fundamental GPCM long-term model. The use of a
daily model in this analysis is noteworthy both because of the limited availability of daily natural gas
modelling for the North American gas market, as well as the fact that daily analysis is key to the

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assessment of the LNG proposals as part of this RFP. Because we believe the key analysis to perform a
cost-bene?t analysis for the RFP is to focus upon peak period pricing, as opposed to say 
average pricing, the use of a daily model is very helpful. In order to proceed with this somewhat unique
Daily Market analysis, Navigant generated four peak day ?snapshots" across the relevant time period of
the contracts 2022, 2032, 2042 and 2052), and then, using Navigant?s market model,
estimated peak day figures for intervening years in order to produce a Net Present Value and Return on
Investment (ROI) result for each contract. To have modeled each year during the contract period could
have been done but due to the modelling time involved to do each year could not have been done within
the Procedural Order timeline schedule.

It should be noted that Navigant?s analysis indicates minimal impact of the LNG storage projects on the
actual levels of natural gas market prices applicable to Maine, as well as on the electric market prices
(locational marginal prices, or LMPs) for Maine.

Other criteria for consideration in meeting the requirements of the PESC is that they must be reasonably
likely to materially enhance LNG storage capacity in the State or ISO-NE region, provide the opportunity
for access to lower cost natural gas at times of regional peak demand for natural gas supplies or in the
event of upstream natural gas infrastructure disruption, enhance electrical and natural gas reliability in the
State, as well as being commercially reasonable and in the public interest. These factors will also be
discussed in the report. It should be noted that the legislation put an annual cap of $25 million on the
program cost of 

3. Overview of Maine Natural Gas Market

3.1. Total Gas Demand

Maine natural gas demand, at 140 in 2015, represents a small fraction of regional gas
demand, at about 6% percent of New England annual gas demand, which was 2.5.Bcfd in 2015.

As shown in Figure 1 below, the principal consumption sectors of natural gas in Maine include electric
power generation, industrial consumption and the residential, commercial and natural gas vehicle fuel
sectors.

 

1 Some proposals may exceed the $25 million cost cap depending on interpretation. Navigant has not
included such factor in its analysis, and defers to the judgment of the Commission on this matter.

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Figure 1: Maine Natural Gas Consumption (2011 20152011 2012 2013 2014 2015

IIND IELC IRESICOMNEH



o88888

 

 

 

Source: Navigant Consulting Inc. EIA

Over the 2011 to 2015 time period, total annual average daily natural gas consumption by sector has
decreased from 190 in 2011 to 140 in 2015, with the largest decrease coming from the
electric generation sector.

Demand in the industrial sector also decreased, with most of the decline related to the loss of
manufacturing activity, particularly from the closure of the East Millinocket, Old Town and Bucksport
pulp and paper mills in 2014.2. Although the residential/commercial/vehicle fuel sectors represented
only about 25% of total gas consumption in Maine in 2015, this sector has experienced signi?cant
growth with a 12% compound average growth rate from 2011 to 2015 (driven in large part by cold
weather) as shown in Table 3, below.

Table 3: Maine Historical Natural Gas Consumption (2011 2015)

2012 2013 2014 2015 CAGR
Electric
Industrial

 

 

Res/Comm/Veh

Total
Source: Navigant Consulting Inc. EIA

 

 

 

 

 

 

 

 

 

Gas demand in Maine is cyclical due to variations in consumption driven by seasonal requirements.
As shown in Figure 2, below, consumption of natural gas in Maine ?uctuates based upon increases in
cold-weather-driven demand. In 2015, demand peaked at 187 in February, which represents

 

2 Bangor Daily News, October 2014.

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Final Report: Economic Analysis and Findings Related to

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an increase of 47 over the yearly average demand of 140 or an increase of
approximately 33%.

Figure 2: Maine Natural Gas Consumption (Jan 2011 Dec 2015)

 

 




IIND IELC 

 

 

 

Source: Navigant Consulting Inc. EIA

Navigant's forecast for natural gas consumption in Maine calls for a signi?cant growth in overall
demand, driven primarily by growth in residential, commercial and natural gas vehicle sectors.
Overall demand is projected to increase from 140 in 2015 to 160 by 2020 and
approximately 200 by 2030.

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Final Report: Economic Analysis and Findings Related to

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Figure 3: Maine Natural Gas Consumption Yearly (2011 205300?00 OD 


IIND IELC 

 

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC
3.2. Market Access and Infrastructure
Deliveries of natural gas to Maine are enabled by several major pipelines as shown in Figure 6 below.

The Portland Natural Gas Transmission System is a 295-mile interstate pipeline that
originates at the terminus of the TransCanada Corp. Trans-Quebec and Maritimes Pipeline at the
border between Canada and New Hampshire and ends in Dracut, MA where it ultimately connects
with the Tennessee Gas Pipeline System (TGP). The system shares facilities with the
Maritimes and Northeast Pipeline from Westbrook, ME to Dracut MA. has a design capacity
of 168 at the Canadian border which increases to 210 from Westbrook, ME to Dracut,
MA. provides access to natural gas from several regions including Western Canada, the US
Rockies and the Marcellus and Utica shale plays in the US.

The Maritimes Northeast Pipeline brings offshore, onshore and LNG-sourced natural gas
from Atlantic Canada to North American markets. The pipeline has a design capacity of 830
on the US. side and 550 of natural gas capacity on the Canadian side. The pipeline
extends from Nova Scotia into New Brunswick, Maine, New Hampshire and Massachusetts where it
connects with the Algonquin Gas Transmission pipeline near Bever1y, Massachusetts. pipeline
provides access to offshore Canadian production from the Sable Island and Deep Panuke natural gas
?elds in addition to deliveries of lique?ed natural gas (LNG) from the Canaport facility in New
Brunswick, Canada.

The Granite State Gas Transmission (GSGT) pipeline runs from Haverhill, MA, up to Portland, ME.
This pipeline is owned by Unitil Corporation, an interstate electricity and natural gas utility company
that serves the areas in New Hampshire, Massachusetts and Maine. The GSGT, for most of its

length, runs in parallel with the and shared pipeline. GSGT receives gas from either

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the or the TGP pipelines near Haverhill, MA and delivers along the Maine seacoast
into Portland, where it supplies the Unitil distribution network.

In addition to these pipelines that directly serve Maine, two additional pipelines, the Tennessee Gas
Pipeline (TGP) and the Algonquin Gas Transmission pipeline (AGT) deliver natural gas to the New
England area.

The TGP system is an approximately 11,800-mile pipeline system that transports natural gas from
Louisiana, the Gulf of Mexico and south Texas to the northeast section of the United States, including
New York City and Boston. The TGP system has two legs in New England. One leg extends from
New York to Connecticut with a capacity of approximately 150 while another leg extends from
New York to Massachusetts with a capacity of approximately 1.17 Bcfd.

The AGT system is a 2.98 pipeline that extends from the Texas Eastern Pipeline, which
connects Texas and the Gulf Coast with the US Northeast, to the pipeline. The AGT system
capacity is approximately 1.36 from New York to Massachusetts via Connecticut.

A proposed expansion of the AGT and pipelines will add approximately 133 per day of
additional capacity. Known as the Atlantic Bridge Project, it is expected to enter service in November
2017. The Atlantic Bridge project is designed to increase capacity along the AGT and systems
allowing increased deliverability to New England and to Atlantic Canada.

Another important project to the New England region is the proposed Access NE pipeline expansion
project. This project is expected to increase capacity on the AGT system by 925 Also
proposed as part of this project is an LNG peak shaving facility with a potential daily send-out of 400
This project is designed to increases supplies of natural gas, particularly on peak days, to
power plants off the AGT and systems The additional capacity brought on by Access NE will
also provide access to less expensive shale gas in the Appalachian basin. Shale gas from the
Appalachian basin can reach the AGT system via its interconnects with the Texas Eastern pipeline at
Hanover, New Jersey and TGP at Mahwah, New Jersey. From the AGT system, the Appalachian
shale gas can make its way into Maine and Atlantic Canada via the pipeline system which
interconnects with AGT in northern Massachusetts.

 

3 FERC Docket No. PF16-1-000

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Final Report: Economic Analysis and Findings Related to

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Figure 4: Proposed Access Northeast Project

 

 

    

Texas Eastern

 

 

 

Source: Spectra Energy

Outside the Algonquin system and closer to the source of Appalachian supply, multiple pipeline
projects are being proposed as a response to the recent growth in Appalachian shale production. As
shown in Figure 5, Appalachian gas production has grown by 37.3% annually from 2008 to 2015. As
a result, the share of Appalachian gas production out of total USA production has increased from 4%
to 28% between 2008 and 2015?a transformative growth in production from a region that produced
almost no gas relatively before 2008.

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Figure 5: Appalachian gas production VS the rest of the USA (2006-20152006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Rest of the USA lAppalachia

 

 

 

Source: Navigant Consulting Inc. PointLogic Energy

In order to get the Appalachian production to surrounding markets, several projects have been
proposed to increase take-away capacity from the Appalachian basin. Currently there are almost 30
projects representing over 21 of takeaway capacity that are proposed and seem to be moving
forward. The table below shows the projects most likely to have a signi?cant potential impact on the
Maine market, with projected volumes.

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Final Report: Economic Analysis and Findings Related to

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Table 4: Major New England Pipeline Expansions

 

 

 

 

 

 

 

 

. . . . Incremental
Pipeline Proiect In?Serwce Date Capacity 
Algonquin Access Northeast November 925
20194
Algonquin Algonquin
Incremental Market November 2016 342
(AIM)
Algonquin Atlantic Bridge November 2017 133
Constitution Constitution November 2019 650
Tennessee Gas Connecticut . November 2017 72
Pipeline Expan3ion 
Nexus Nexus November 2017 1500
ET Rover ET Rover November 2018 3250
Portland Natural Continent to Coast November 2017 132
Gas Transmissmn ExpanSIon Proiect

 

 

 

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; PointLogic Energy

3.3. Maine Local Distribution Companies

There are four local gas distribution companies (LDCs) in Maine that serve the industrial residential
and commercial sectors. These LDCs receive natural gas from the interstate pipelines and deliver to
end users via their distribution networks. The four LDCs in Maine are Bangor Natural Gas Company,
Maine Natural Gas Corporation, Northern Utilities Inc. d/b/a Unitil, and Summit Natural Gas of Maine.
The service territories of these LDCs are shown below in Figure 6. In addition, some electric and
industrial consumers receive natural gas directly from the interstate pipelines.

 

4 In its December 16, 2016 Progress Report to FERC, Spectra noted it will delay its FERC
application for Access Northeast until late 2017.

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Final Report: Economic Analysis and Findings Related to

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Figure 6: Maine Natural Gas Pipeline Infrastructure


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krr?,? 2% 
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NFW Legend
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Trans Queber Pt?he
Ngonqun Ca; iraismlascr?
Ivonne?s 
Grams Rare Gas transmission
Portland Manual Gas System
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ERMONT

 

 

Neptune anwnor Port
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A 3? ?mans-um

6? 
Hamlin: Prpalno
Mame LDC Servos Tammy
RH - Bayarrmt?clic
[x - Mama Mama Gas
0 I Nonherriulkeslnc
-


 

Summit Natural Gas of Marc tn<
TGP Zone 6 Market Port

 

 



 



 

Source: Navigant Consulting Inc. Ventyx

Figure 7 below shows the Maine LDC load relative to the total load of Maine. As can be seen in the chart,
the Maine LDC load represents a small but growing portion of Maine?s total load. The average winter load
for Maine has stayed around 190 between 2013 and 2015. During this same time, the Maine LDC
load has grown from 47 to 62 As a percent of total demand, the LDC load has increased
from 24% of market share in 2013 to 34% of market share in 2015.

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Final Report: Economic Analysis and Findings Related to

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Figure 7: Maine gas consumption by LDC and non-LDC (May 2012- Dec 2015a?35$53335$8a335$83335
2 (02

Maine LDCs Maine non-LDCs

 

 

 

Source: Navigant Consulting Inc. Maine PUC

The four in Maine serve residential, commercial and industial customers throughout the state. Of
the 3 sectors, the residential and commercial sectors have shown signs of growth over the last 4 years
while the industrial sector has been in decline. The residential sector has increased its share of the winter
peak market from 16% to 22%. The commercial sector has shown even stronger signs of growth,
increasing from 30% of the winter peak share of the market to 44%. During this same time, the industrial
sector share of the winter peak market declined from 55% to 35%.

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Final Report: Economic Analysis and Findings Related to
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Figure 8: Maine?s LDC gas consumption sector (May 2012- Mar 2016)

 

80
7O

 

0

88?8?888?8?888?8?888?8
E3 8 563 8 Eli?s? 8 5&3 8
?5$23?23$2g22582g2?532

IResidential lCommercial llndustrial

 

 

 

Source: Navigant Consulting Inc. I Maine PUC

As was previously noted, the Maine natural gas market is highly seasonal, with winter peak loads growing
to over 33% of annual demand. In order to reduce their exposure to high prices from swings in demand,
the Maine have hedged a portion of their winter load with capacity-backed contracts. As can be

seen in the chart below, over the last 4 winters, Maine?s have generally secured around 62% of
their load with contracts.

Figure 9: Maine LDC Contracted and Uncontracted Load

 

May-12
Jul-12
Nov?12
Jan I 3
Mar-13
May-13
Jul?1 3
Sep13
Nov-13
Jan 14
Mar-14
Jul-14
Sep14
Nov-14
Jan15
Mar-15
May-15
Jul-15
Nov-lb
Jam 6
Mar-16

I LDC Cont'acted load LDC Uncontracted loac

 

 

 

Source: Navigant Consulting Inc./ Maine PUC Staff

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3.4. Regional Market Overview

As mentioned above, total natural gas consumption in Maine in 2015 was approximately 140 
and represented approximately 6% of total demand in New England. In addition, total demand in
New England in 2015 was 2.5 Bcfd, which represents approximately 22% of total demand in the
Northeast, comprised of New England and the Mid-Atlantic regions, or 11.5 in 2015 as shown
below in Figure 10 below. The Mid-Atlantic region, which consumed 8.7 of natural gas in 2015
is the largest regional market in the Northeast region. Total natural gas consumption in Maine
represents 1% of total gas consumption in the Northeast. Maine?s LDC gas consumption represents
only 0.2% of total gas consumption in the Northeast.

Figure 10: Comparison of Annual Demand Mid-Atlantic and New England (2011 2015)

 

1 2,000
10,000
8,000

2 6.000
2
4,000
2,000
2011 2012 2013 2014 2015
I Mid-Alantic New England

 

 

 

Source: Navigant Consulting Inc. EIA

The size of the Mid-Atlantic region relative to the Northeast is underscored by a comparison of
demand which highlights the seasonality of natural gas consumption due to winter space
heating requirements, as shown in Figure 11, below. In 2015, peak load in the Mid-Atlantic
was 14.8 in the month of February while average 2015 demand is 8.6 Bcfd. This represents an
increase of more than 6 Bcfd, or 1.7 times the yearly average.

In New England, the peak demand in 2015 was 3.9 while the 2015 yearly average demand was
2.5 Bcfd, a difference of 1.3 Bcfd.

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Final Report: Economic Analysis and Findings Related to

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Figure 11: Comparison of Demand Mid-Atlantic and New England (Jan 2011 Mar 2016)

 

20,000
10,000
10,000
14,000
33 12,000
5 10,000
5 8.000
5,000
4,000
2,000

8 3

"a 

a 3

3 

 

Oct-2011
Jan-2012



0


5


I
5
D.

 





=0 Q30 Q50 Q30
?og<aog<aog<aog
-A antic New England

 

 

Source: Navigant Consulting Inc. EIA

3.5. Maine Sources of Supply

Gas supply in Maine is primarily served by natural gas deliveries from Appalachia (Marcellus and
Utica Shale plays), the Western Canadian Sedimentary Basin (WCSB), Eastern Canada and LNG
imports from import terminals along the eastern seaboard in Canada and Massachusetts as shown in

Figure 12, below.

Figure 12: Maine Natural Gas Sources of Supply

 

250

200

2011
2013
2015
2017
2019

I Appalachia

 

2021



2027
2029
2031



 

2033
2035
2037

Eastern Canada



00000000

I LNG Atlantic

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC

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Final Report: Economic Analysis and Findings Related to

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The sources of gas supply in Maine vary from the sources of natural gas that serve the overall New
England and Mid-Atlantic markets as shown in Figure 13 and Figure 14 below. The rapid increase in
natural gas production from the Marcellus and Utica shale plays in the Appalachian region is forecast
to provide the majority of natural gas in the Mid-Atlantic and New England markets and displace more
traditional sources of supply such as WCSB and Eastern Canada.

While supply from the Appalachian region is projected to become a growing source of supply for
Maine, it is also projected to continue to be served by gas supply from the WCSB, LNG imports and
Eastern Canada. This is due to the ability of the pipeline to deliver natural gas from the
WCSB and the pipeline to provide deliveries from Eastern Canada in addition to LNG imports
from the Canaport LNG import facility in Saint John, New Brunswick. The Everett LNG import facility
in Everett, Massachusetts will also continue to serve load on the AGT system. Although both of the
previously mentioned LNG import facilitates continue to actively serve load, the region's dependence
on them has diminished over time. In fact, Repsol, the owner of the Canaport LNG facility, has
reviewed the conversion of its Canaport import facility into an export facility.

Figure 13: New England Natural Gas Sources of Supply

 

4,000
3,500
3,000

:2 2,500

2, 000

2 1,500
1,000

500

 

2033
G) 2035

NO)
Wt?)
00
NN

2043

In
Vt
c3
cu

2031
2041
2047
2049
2051
2053

03??
FN
0000
NW



IAppaIachia Eastern Canada I Atlantic WCSB

 

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC

As shown in Figure 13, the Appalachian region is expected to become the primary supplier of gas to
New England. Figure 14 demonstrates how the Appalachian region is expected to almost completely
displace sources of natural gas from the Rockies, Midcontinent, Permian and Gulf Coast regions by
2020 into the Mid-Atlantic Region.

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Final Report: Economic Analysis and Findings Related to

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Figure 14: Mid-Atlantic Sources of Supply

 

 

12,000
10,000
8,000

26,000
2
4,000
2,000
0

0000 OO OO

IAppaIachia IArkla-East Texas lGulf Midcontinent IRockies WCSB

 

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC

3.6. Natural Gas Prices

The primary price hubs that in?uence delivered natural gas prices in Maine are Tennessee Gas Zone
6, Algonquin City Gates and Dracut.

Algonquin, city-gates represents deliveries from Algonquin Gas Transmission to all distributors and
end-use facilities in Connecticut, Massachusetts and Rhode Island. The Dracut, MA market price
represents deliveries into Tennessee Gas Pipeline at the Dracut interconnect with Maritimes 
Northeast Pipeline near Middlesex, MA and gas is generally traded during winter peak months only.
The Dracut point also includes gas entering from Portland Natural Gas Transmission System.

Tennessee, zone 6 delivered represents deliveries from Tennessee Gas Pipeline on the 200 leg in
Connecticut, Massachusetts, Rhode Island and New Hampshire.

A review of the relationship between natural gas prices in the Northeast and natural gas demand in
the Mid-Atlantic and New England regions yields insights into natural gas market dynamics in the
region.

As shown in Figure 11 above, during the winter period, de?ned as November through March, demand
for natural gas increases signi?cantly in both the Mid-Atlantic and New England. One result of the
sharp increases in demand is a pronounced increase in spot prices for natural gas at key
market hubs in New England. Figure 15 below shows spot natural gas prices for Dracut, Algonquin
and Tennessee Gas Pipeline Zone 6 in addition to the Henry Hub. These exhibits demonstrate that
during periods of peak demand, driven by signi?cant increases in seasonal demand during the winter,
spot prices have increased sharply in response to the increase in demand.

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Final Report: Economic Analysis and Findings Related to

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Figure 15: Daily Spot Natural Gas Prices (Jan 2012 - Dec 2015)
Henry Hub, Dracut, TGP 26 and Algonquin

 

 

$90

$70

 

 

 

 

 

f?f?fyf56? 33?
?Henry Hub ?Dracut
$90 $90
$80 $80
$70 $70
$60 $60
350 tan 550
$40 $540
$(?90 ?90 ?9&5 (19? wok" W68, .190 (?90 (1945 ?9'9 we? Wok? ?9'33 
3"5?39, 33 35? 53? 5'5" 33
200L Algonquin

 

 

 

 

 

 

Source: Navigant Consulting Inc. ICE Ventyx
Note: Gaps in the historical prices at Dracut re?ect lack of reported data on trades.

A key insight from this analysis is that the signi?cant increases in natural gas prices in New England
that occurred in the winter months in 2012 through winter of 2015 were driven primarily by the
seasonal increases in demand in the Mid-Atlantic. The reason for this relationship is that New
England is at the end of the major interstate pipelines that serve the Northeast region, including
Maine. As these pipelines move natural gas from supply sources to demand centers throughout the
Mid-Atlantic towards New England, seasonally-driven increases in demand in the Mid-Atlantic push
up prices at demand centers further upstream.

This is evidenced by the sharp increases in prices at Algonquin, Tennessee Zone 6 and Dracut. The
size of the Mid-Atlantic market relative to the size of the New England market and its position in front

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Final Report: Economic Analysis and Findings Related to

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of New England on the path of the major pipelines that serve both markets means that New England
must compete for supply with the Mid-Atlantic.

Similar dynamics in?uence natural gas prices for the Maine market. At 2.5 of demand in 2015,
the New England regional natural gas market is significantly larger than the 2015 average of 140
of demand in Maine. In addition, the geographic position of Connecticut and Massachusetts
on the route of two of the major pipelines, Algonquin and TGP, that provide natural gas supply to
Maine mean that prices in Maine are largely in?uenced by regional market dynamics in the Mid-
Atlantic and Southern New England.

Another key takeaway from the price comparisons is the relative scarcity of reported prices for Dracut
compared to Tennessee Zone 6 and Algonquin City Gate. This is due to the lack of trades at Dracut,
which generally only trades on the most extreme winter days and rare occasions in the summer
months. Between 2012 and 2016, the Dracut price was only reported for 22% of the total trade days
over the year. In the winter the Dracut price was reported 44% of the time and in summer it was only
reported 7% of the time. In contrast, the AGT price was reported for 100% of the of the trade days
while the price was reported for 99.6% of the trade days.

As shown in Figure 16 below, Navigant projects that natural gas prices will rebound in 2017 and
2018, then remain moderately ?at until 2025 when an increase in demand from electric generation
begins to put some upward pressure on prices. After 2035 price growth moderates as growth in both
supply and demand begin to slow down. Dracut prices were left out of the forecast comparison due to
the previously described lack of trade days and transparency.

Figure 16: Navigant Regional Natural Gas Price Forecast

 

$7.00
$6.00
$5.00 
$4.00

$3.00

2015 

$2.00
$1.00
5.


556?)

Tennessee, zone 6 delivered Algonquin. city-gates Henry Hub

 

 

 

Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC

Natural gas prices at Tennessee Zone 6 (TGP Z6) and Algonquin are expected to trade in a close
range with each other in addition to trading more closely to the Henry Hub. Prices in the Gulf are

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Final Report: Economic Analysis and Findings Related to

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expected to rise on higher demand from the electric generation and industrial sectors as well as
increased exports of LNG. Northeast prices are expected to remain low due to the abundance of
supply in the Appalachian basin. Between the increasing demand in the Gulf and the additional
supply in the Northeast, the basis between the two regions is expected to shrink signi?cantly over the
next few years

Table 5: Regional Natural Gas Price Forecast

2.62 2.70 2.49
3.62 3.65 3.36
3.88 3.90 3.77
4.60 4.61 4.66
$5.18 $5.19 $5.20
5.50 5.52 5.36
5.63 5.64 5.46
Source: Navigant?s North American Natural Gas Market Outlook, Fall 2016; RBAC

 

For the purposes of conducting the analysis of the proposed Physical Energy Storage Contracts,
Navigant has based its analysis on the Tennessee Gas Pipeline Zone 6 (TGP Z6) as the pricing hub
against which to measure the market impact of the proposed projects. As shown above in Figure 6,
TGP Zone 6 is located closer to Maine than Algonquin. In addition, Dracut was not selected due to its
historical lack of trading activity and therefore transparency, especially over the summer period, in
comparison to TGP 26 and Algonquin as explained above and shown in Figure 17 below.

Figure 17: Comparison of Daily Trading Activity at New England Natural Gas Hubs

 

No. of days with trade 2012-2016

1200

1000
800
600
400
I


Winter Summer

 

lAlgonquin ZOOL lDracut

 

 

 

Source: Navigant Consulting Inc. ICE Ventyx

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Final Report: Economic Analysis and Findings Related to

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4. Overview of Maine Wholesale Electric Power Market

Independent System Operator New England (ISO-NE) is the regional transmission organization for
Maine, Massachusetts, Connecticut, New Hampshire, Rhode Island, and Vermont, serving 6.5 million
electricity customers and 14 million people. The regional generation market is largely unregulated,
with the smallest proportion of generation owned by vertically integrated utilities of any market in the
United States. ISO-NE administers two energy markets (day-ahead, real-time), a capacity market,
three ancillary services markets, and a transmission market. Energy markets are nodal and prices
peak in summer months. The sub-market areas of the ISO generally do not demonstrate strong
separation of prices, indicating that intra-regional congestion is not a large issue and that prices are
driven by regional factors rather than local factors. Historical annual prices for separate areas of the
ISO-NE are shown in Figure 18. This is an important observation because it underscores a further
conclusion that modest changes in gas supply in Maine are in turn a relatively small addition to supply
to the entire ISO and will have little-to-no impact on Maine LMP.

Figure 18: ISO-NE Annual LMP

 

 

 

$Hub On-Peak - Historical - Maine Central On-Peak - Historical
Northeast Massachusetts On-Peak - Historical Southwest Connecticut On-Peak - Historical
ISO-NE Hub Off-Peak - Historical Maine Central Off-Peak - Historical
- - Northeast Massachusetts Off-Peak - Historical - - Southwest Connecticut Off-Peak - Historical

 

 

 

Source: Navigant Consulting Inc. EnergyVelocity

4.1. Total Electric Demand

highest single peak occurred on August 2, 2006 at 28,130 MW and in recent years reached
peak levels of 24,437 MW in 2015 and 25,521 MW in 2016.

As shown below in Figure 19, over 75 percent of demand and consumption occur in the southern
New England states of Massachusetts, Connecticut, and Rhode Island while Maine?s electric peak

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Final Report: Economic Analysis and Findings Related to

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demand and annual energy requirements account for about 9% of total power consumption and 8%
of peak demand in the ISO.

Figure 19: Maine Electric Energy and Demand Share of ISO-NE (2015)

 

Annual Energy Peak Demand

RI: 5.496
8.796 0'
24.3%
H,
8.096
Vans,
9.1%

MA, MA,
44.5% 44.9%

VT

    

 

 

 

 

Source: Navigant Consulting Inc. EnergyVelocity

Over the 2011 to 2015 time period, total electric consumption in New England decreased moderately
from 127 in 2011 to 125 in 2015, although these numbers are not weather-normalized and
there is no clear trend. Beginning in 2006, prior to the so-called Great Recession of December 2007
to June 2009, electric energy consumption decreased from 130 Again, these data are not
adjusted to normal weather and do not indicate a clear upward or downward trend in the region.
Consumption in Maine remained ?at during the period with 11.44 in 2006 and 11.35 in
2015 and a ten-year mean value of 11.30 

Figure 20: Total Electric Energy Consumption

 

Annual Energy Consumption

150
125
100
75
SO
25
0



 

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
IME IRestoflSO

 

 

 

Source: Navigant Consulting Inc. EnergyVelocity

Electric demand in Maine and the rest of New England is cyclical due to variations in consumption
driven by seasonal requirements for heating and cooling. As shown in Figure 21 below, electricity
consumption in Maine ?uctuates with a bi-modal distribution around the January and July peak
months while consumption in the rest of New England has a more pronounced Summer peak.

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Figure 21: Electric Energy Consumption

 

Energy Consumption, of Annual
12Q36 Q36 Q36 Q36 Q36

-Restof SO 

 

 

 

Source: Navigant Consulting Inc. EnergyVelocity

Navigant?s forecast for electric consumption in Maine has a long term growth rate of 0.7% per year,
which is slower than the long-tenn growth rate of 0.9% per year in the rest of New England.

Figure 22: Annual Electric Energy Growth

 

Annual Energy Consumption

 

175 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039

- Rest of ISO 

 

 

 

Source: Navigant Consulting Inc. (2016 CELT report with extrapolation)

4.2. Supply Sources and Trends

Most installed capacity in the New England market is thermal plant fueled by natural gas oil
and coal with nuclear and combined renewables adding 12% and 18%, respectively. In
total, installed capacity accounts for about 87.5% of total resources with the remaining 12.5% coming
from incremental energy ef?ciency programs, active demand response programs, and imports.
Current installed capacity in Maine is weighted more heavily to hydro, wind and other renewables
than the rest of the region as shown in Figure 23.

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Final Report: Economic Analysis and Findings Related to

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Navigant expects that natural gas additions will be about 55% of new installed capacity over the next
decade with mixed renewables accounting for the remainder. This, with expected retirements of oil,
coal, and nuclear facilities increase gas? capacity share from 45% to 52% and hydro and other
renewables? share from 18% to 26%. However, as shown in Figure 24 new gas plants are not
projected to be sited in Maine and renewables are expected to increase to nearly 50% of installed
capacity. Gas and renewable shares by 2035 are little changed from 2025.

Figure 23: Installed Capacity Allocations (2015)

 

Maine (2015) Rest of ISO (2015)

Gas
lOiI
lCoal

Nuclear
Hydro

42% 46%

Pumped Storage


Other Renewable

   

 

 

 

 

Source: Navigant Consulting Inc.

Figure 24: Installed Capacity Allocations (2025)

 

Maine (2025) Rest of ISO (2025)

3%
15% Gas
IOil
ICoal
5596

Nuclear

I Hydro

 

I Pu 'n pod Storage

 

IWind

Other Renewable

 

 

 

 

Source: Navigant Consulting Inc.
4.3. Reserve Margin

ISO-NE de?nes its reserve margin as total capacity minus peak demand net of rooftop solar and
passive demand response. The reserve margin target will change based on year-to-year reliability

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Final Report: Economic Analysis and Findings Related to

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calculations but is generally set at or around 14 percent. ISO-NE includes both demand response and
?rm purchases/sales in this calculation. The reserve margin has been above 20% in recent years and
Navigant expects it remain at or above 20% for the forecast horizon due in large to expected ?rm
purchases of a large block of hydro under the Massachusetts 2016 Act to Promote Energy Diversity.

Figure 25: Supply, Demand, and Planning Reserve

 

40.000 252..
35.000 .
A
20?.
- 30000 .
a I
. 
.
8 25.030 15? a
as 
20.000 
05 ..
3 
8 15.000 a:
3
5 10000
a 

5.000
Source: Navigant Consulting Inc.

4.4. Maine Forecast Results

The ISO-NE market, including the three Maine zones of Bangor Hydro, Central and Southwest, were
forecasted for the period 2017-2040 in Navigant?s nodal PROMOD model. Two scenarios were run 
one with the Access Northeast pipeline and the other without Access Northeast. Summary results of
these two cases are presented for Maine in this section. We note that Navigant?s analysis indicates
minimal impact of the LNG storage projects on the actual levels of LMPs for Maine.

4.4.1. Load and Generation Balance

On an all-hours basis, Maine is a net-positive producer through the early years of the forecast period
but that condition fades by the mid-20205 as existing combined cycle plant output lag in the face of
competition from new more ef?cient combined cycle plants in the southern New England states and
(ii) new generation plant construction in Maine does not keep pace with demand growth. In that
transition, an increasing amount of imports from New Brunswick are ?retained? within Maine. Figure
26 and Figure 27 show these results for the two scenarios. The general market impacts on Maine of
removing Access Northeast are to shift production of power from themial generation plant into Maine,
with broad scale increases in LMP, fuel consumption, and emissions.

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Final Report: Economic Analysis and Findings Related to

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Figure 26: Maine Load and Generation Balance (with Access)

 

Annual 

 

 

 

?3

-In-stateGeneration -Imports ?Tota  Load

 

Source: Navigant Consulting Inc.

Figure 27: Maine Load and Generation Balance (w/o Access)

 

20,000
18,000
16,000
14,000



AnnualGWh
9? :5 .H


 

6,000
4,000
2,000


$4 '04} we? 9?6 ~69 .90" x69 yd} my ?93? .93? 19"" 15? 159 a we? 19"? ~59 wd?g

 

 

-In-stateGeneration -Imports ?Tota  Load

 

Source: Navigant Consulting Inc.

4.4.2. LMP Summary
Projected changes in LMP in the Maine zones track closely with changes at the ISO Hub. Market
heat rates decline steadily across all three time blocks (on-peak, off-peak, all hours) due to the
penetration of more efficient gas combined cycle plants at the margin and broader penetration of
renewable plant. Also, Maine heat rates fall faster than the ISO heat rates. Figure 28 and
Figure 29 show these results for the two scenarios. With the Access Northeast project removed,
Navigant?s long-term all-hours LMP forecasts are about $2 higher in the 20205 and $7 higher in the
20305, with the gap increasing to $9 by 2040. Market heat rates are correspondingly higher.

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Final Report: Economic Analysis and Findings Related to

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Figure 28: Maine and ISO All-Hours LMP and Heat Rate (with AccessMaine All Hours ISO Hub All Hours Maine All Hours HR ISO All Hours HR

 

 

 

 

Source: Navigant Consulting Inc.

Figure 29: Maine and ISO All-Hours LMP and Heat Rate (w/o AccessMaine All Hours ISO Hub All Hours Maine All Hours HR ISO All Hours HR

 

 

 

Source: Navigant Consulting Inc.

4.4.3. Consumer Wholesale Payments
Wholesale market payments underlie the eventual retail costs to consumers as the cost of purchased
power. Total LMP payments increase over the forecast period with increases in LMP and increases
in demand. Figure 30 and Figure 31 show these results for the two scenarios. With the Access
Northeast project removed, Navigant?s long-term power payment forecasts for consumers in Maine
are higher than the ?with-Access scenario? by about $35 million per year in the mid-20205, about
$100 million in the mid-20305, and $150 million by 2040.

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Final Report: Economic Analysis and Findings Related to

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Figure 30: Wholesale Power Payments (with Access)

 

$500
$450
$400 

a $350 

3 $300
2 $250 

?3200 

 

 

 

23150
5100 1
$50
$0
hmeHvamwhmeHvamwhme
1-4 
000000000 00000000000003

?Maine - BHE ?Maine - Central ?Maine - Southwest

 

 

 

Source: Navigant Consulting Inc.

Figure 31: Wholesale Power Payments (w/o Access)

 

$500
S450 
$400

$350 
Ln

5? $300

2' $250

?5200 

 

 

25150
$50
$0


000 0000000000 000 00003

?Malne - BHE ?Ma ne - Central ?Ma ne - Southwest

 

 

 

Source: Navigant Consulting Inc.

4.4.4. Fuel Requirements

Over the long run, biomass consumption in Maine is expected to remain stable, natural gas consumption
is expected to decline steadily until the mid-20305 before leveling off, and oil consumption is expected to
slowly decline. Figure 32 and Figure 33 show these results for the two scenarios. In both scenarios,
declines in natural gas consumption are driven by increasing competition from newer combined cycle
plants outside of Maine but the declines are partially offset by increases in biomass capacity factors and
feedstock consumption. With removal of the Access Northeast project, fuel consumption by plants in
Maine increases by about 3.7 TBtu per year, on average, in the 20205 and by about 5.3 TBtu per year in
the 20305. In parallel to this increase in fuel consumption, C02 emissions increase by about 255
thousand short tons per year in the 20205 and 340 thousand short tons in the 20305 in the scenario
without Access Northeast.

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Final Report: Economic Analysis and Findings Related to

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Figure 32: Fuel Consumption and C02 Emissions (with Access)

  

 

100 5,000
90 4,500
80 4,000
70 3,500 
60 3,000 
3 
a 50 2,500 
.- 
40 2,000 3
30 1.500
20 1,000
10 500
0 0



- Biomas Consumption -Gas Consumption -Oil Consumption emissions
Source: Navigant Consulting Inc.
Figure 33: Fuel Consumption and 002 Emissions (w/o Access)
100 5,000
90 4,500
80 4.000
70 3.500 
3 60 3,000 

50 2,500 8
2 40 2.000 3
30 1,500
20 1.000
10 500
0 0


0 3

-Biomas Consumption -Gas Consumption -Oi  Consumption emissions

Source: Navigant Consulting Inc.

4.4.5. Comparison Between Access Northeast Scenarios
The general market impacts on Maine of removing Access Northeast are to shift production of power

from thermal generation plant into Maine, with broad scale increases in LMP, consumer load
payments, production costs, fuel consumption, and emissions. Table 6 shows these results.

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Final Report: Economic Analysis and Findings Related to
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5. General Overview of PESC Bids

The parameters of PESC bids covered a range of key aspects of proposed facilities from facility size and
operating characteristics, to various components of contract costs. The main physical parameters
included the capacity of the proposed LNG storage tanks, the vaporization rate and/or number of storage
withdrawal days, and the ?ll rate for the storage tanks. Cost-related parameters included ?xed and
variable costs and the rates of vaporization and/or liquefaction fuel loss/use.

There were originally seven bidders providing more than twenty bid options. After both a procedural
order requiring a reduction to two options per bidder, as well as Prometheus Energy withdrawing, there
were six bidders that ultimately presented bids for analysis in this report, for a total of 11 bid options. The
LNG tank sizes were generally spread between one and two Bcf, with varying vaporization rates
contributing to various total days of LNG use out of storage. One bidder had a significantly smaller tank,
thereby creating smaller value. Days of use were generally estimated by dividing the tank size by the
vaporization rate.

The time to ?ll a tank was either provided in the bid or estimated from the tank size and the ?ll rate
speci?ed in the PESC bid. In general, an average price over the off-peak season was used to generate
?ll costs; in one instance, a longer time to ?ll led to a longer period than the generalized the off-peak
period during which prices to ?ll would be based. Fill time for liquefaction-based projects varied from 100
days to about 240 days, as a function of tank size and ?ll rate.

With regard to contract costs, charges generally consisted of ?xed costs, variable costs, and fuel loss/use
costs. As noted previously, some contract total costs appear to exceed the $25 million annual ?gure
appearing in the legislation. Some contracts included supply provided via on-site liquefaction, while other
options were based on trucked-in LNG supply. For trucked-in LNG supply, Navigant included a cost
adjustment to account for the extra costs to procure gas as LNG rather than as ordinary natural gas. A
general summary of bid terms by bidder and for the limit of two bids per bidder that were requested by the
Maine PUC follows.

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Final Report: Economic Analysis and Findings Related to

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Table 7: Overview of PESC Option Bids

 

     

 

 

Company Option Catrri?ty VapoRrai::tion Use Days Fill Method Fill Rate Fill Days Contract Charges
Days Days
fixed
. . $50k variable
Cavus Energy Base 1 200 5 Liquefaction 5.4 185 electric
2% vap loss
fixed
. . $50k variable
Cavus Energy Alternate 1 100 10 Liquefaction 4.1 244 electric
2% vap loss
Eagle Partners A - I I Truck I
Eagle Partners - I - Truck
mine Industries Industries Tolling 2 I I I - I
Reliable Energy
1-1 I I I I I
Reliable Energy
Storage 21 I - I - -
Prometheus
- I I - -

 

 

6. Detailed Methodology
6.1. Model Description

Navigant?s modeling uses a proprietary, in-house version of RBAC lnc.?s GPCM, a competitive,
partial-equilibrium model that balances supply and demand while accounting for the costs and
capacity of transport and storage. The model will balance or clear supply and demand for North
America based on meeting all regional demands from the mix of available supplies, accounting for
physical interconnections as well as costs associated with production, transport, and storage.
Navigant?s gas supply assumptions are based on currently producing gas basins, incorporating
potential trends in production levels to generate ranges of likely future production. Additional
producing basins or modi?cations to general production trends requires speci?c scenario modeling.

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Final Report: Economic Analysis and Findings Related to

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Navigant?s gas infrastructure assumptions are based on existing pipelines, augmented to relieve
future bottlenecks where appropriate5, plus those announced projects deemed likely to be built.
Additional pipelines require speci?c scenario modeling.

Navigant?s forecasting methodology is conservative in that, as noted, supply and infrastructure
assumptions are generally based on existing production basins or speci?c infrastructure that exists or
appears likely to be built. With regard to supply, the forecasts assume no new gas supply basins
beyond those already identi?ed as of mid-2016. This is conservative given the steady rate at which
new shale resources have been identi?ed over the past few years and the history of increasing
estimates of the North American natural gas resource base. For example, the United States
Geological Survey has recently issued a new resource assessment for the Mancos Shale play in the
Piceance Basin centered in Colorado, with a projected recoverable resource level of 66 ch. 5
Similarly, production in the Permian Basin has increased dramatically from 3.5 to 6.0 over the
last ?ve years, according to Navigant data review.

With regard to infrastructure, Navigant?s modeling is based upon existing North American pipeline
and LNG import terminals, augmented by planned expansions that have been publicly announced
and that appear likely to be built, including consideration of LNG export terminals. Pipelines are
modeled to have suf?cient capacity to move gas from supply sources to demand centers. Some local
expansions have been assumed and built into the model in future years to relieve expected
bottlenecks. In general, no publicly unannounced infrastructure projects have been introduced into
the model. This means that no new infrastructure has been incorporated into the model post-2016,
except as has been announced at the time of our forecasting in mid-2016. In the absence of speci?c
information, Navigant limits its infrastructure expansion to those instances where an existing pipeline
has become constrained as determined by the model. The remedy consists of adding suf?cient
capacity to relieve the constraint only.

daily gas market model is based on the GPCM model, but with additional capabilities
necessary to address daily demands and flows (such as peak day) rather than average data.
Speci?c market attributes that may be assessed on a daily basis include very hot or very cold
weather, and scheduled events such as LNG tanker arrivals or departures. Consequently, more
granular daily, rather than average) review of natural gas demand, storage capabilities
and operations, as well as pipeline system bottlenecks, allows for more focused peak day analysis of
the impacts of new gas infrastructure.

6.2. Model Assumptions

Navigant performed detailed analysis of natural gas demand for Maine both by sector and by
components of supply, i.e. LDC and balance of Maine, as well as contracted and uncontracted
portions of supply. These breakouts were important in order to allow for assessing how the different
PESC volumes would end up being deployed across different markets, as discussed in more detail in
the next section.

 

5 This expansion feature was not used in New England, in order to maintain existing infrastructure to
represent a ?status quo?.

6 United States Geologic Survey, Assessment of Continuous (Unconventional) Oil and Gas Resources in
the Late Cretaceous Mancos Shale of the Piceance Basin, Uinta-Piceance Province, Colorado and Utah,
2016.

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Starting with state-level natural gas demand, Navigant applied a forecasted growth rate to historical
sectoral demand for residential, commercial and industrial classes as reported by the US. Energy
Information Administration (EIA) for 2015. Growth rates from 2016 to 2020 are based on the annual
sectoral growth rates reflected in Northern Utilities? Inc. 2015 Integrated Resource Plan7 converted
from gas year to calendar year. The growth rates from 2019 to 2020 were extrapolated for purposes
of estimating demand growth through 2052. Electric generation sector natural gas demand was
provided through an integrated solution of GPCM and Navigant?s proprietary Portfolio Optimization
Model (POM).

For Maine LDC-level natural gas demand, Navigant used data for LDC sectoral demand for
residential, commercial and industrial classes provided by the Maine PUC for 2015, and applied the
forecasted growth rates used for sectoral Maine demand to these demand levels through 2020.
Beyond 2020, Navigant assumed that the LDC portion of Maine total demand, for each sector,
remained at the same percentage as 2020.

With respect to assumptions for contracted versus uncontracted sources of supply, Navigant
incorporated historical data for 2015 provided by the Maine PUC staff for contracted natural gas
supplies by sector for LDCs. Navigant then applied the forecasted growth rates used for sectoral
Maine demand to these demand levels through 2052 for the residential sector, and through 2020 for
the industrial and commercial sectors. For those two sectors beyond 2020, Navigant assumed that
the LDC contracted portion of Maine total demand, for each sector, remained at the same percentage
as 2020. LDC uncontracted sources of supply equal the difference between total LDC demand and
contracted sources of LDC supply. For the balance of Maine, contracted sources of supply are
represented using the ratio of LDC contracted sources to total LDC demand. Balance of Maine
uncontracted sources of supply equal the difference between total balance of Maine demand and
contracted sources of balance of Maine supply.

In summary, Navigant estimates for 2022 a Maine peak demand of 220 with 101 
representing LDC demand and 119 representing balance of Maine demand. Of the LDC
demand, 58 is estimated to have contracted supply, leaving 43 uncontracted. Of the
balance of Maine demand, 69 is estimated to have contracted supply, leaving 50 
uncontracted. For the state, 127 is estimated as having contracted supply, leaving 93 
as statewide demand with uncontracted sources of supply.

With regard to pricing, Navigant used the Daily Model to generate an estimate of peak period pricing
based on a ratio of 15-day average peak demand to average winter-time demand for Maine and other
regions. Speci?cally, Navigant calculated the average winter-time demand for each census region
and for Maine using daily consumption data available from Energy Velocity for the period January and
February from 2012 to 2016. For the 15-day average peak demand, Navigant utilized daily data from
January and February during the ?ve-year period from 2012 through 2016 to obtain the highest 15
demand dates per year for the Mid-Atlantic region. As outlined earlier in the report, the Mid-Atlantic
regional demand is the key driver for prices that are relevant to Maine. Using these 15 speci?c dates
for each of the ?ve noted years, Navigant estimated a 15-day average peak demand for each census
region, and for Maine. Demand levels were then factored up by the ratio of 15-day average peak
demand to wintertime average demand, and the Daily Model was employed on the revised data set to

 

7 Filed with Maine and New Hampshire Public Utilities Commissions, January 16, 2015.

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yield a price associated with an assumed 15-day average peak demand. As previously stated, we
also present summary results using a less conservative assumption of average wintertime prices.

We note Navigant?s analysis indicates minimal impact of the LNG storage projects on the actual
levels of natural gas market prices applicable to Maine less than one percent), as well as on the
electric market LMPs for Maine. With regard to natural gas prices, Navigant, using its daily model,
modeled the largest LNG facility with a max send out of 200 and found that the additional
supply had minimal impact on prices. As noted earlier in the report, Maine?s total demand represents
about 1% of the total demand in the Northeast making Maine a price taker in the area. More
importantly, large demand areas in the Mid-Atlantic and New England census regions drive prices
during winter peak days so even the largest LNG storage facility represents only a small fraction of
the regional supply that is used to meet Northeast demand on winter peak days

Finally, Navigant ran two scenarios, based on Navigant?s Fall 2016 Reference Case, to account for
either the inclusion or the exclusion of the Access Northeast pipeline project due to some uncertainty
with respect to ultimate construction of the project. It may be noted, however, that there is likelihood
that even if the Access Northeast pipeline project is not built, some other pipeline project will be built
sometime in the future to better serve the Northeast and Maine markets. The choice of Access
Northeast as the pipeline to exclude for the second scenario was based on its relative proximity to
and potential in?uence on the Maine market as well as its current status as a proposed project.
According to Spectra, one of the stated goals of the Access Northeast project is to increase
deliverability to electric generating units on the pipeline system in Maine. Spectra intends to
increase deliverability by expanding the AGT system as well as adding in an LNG storage facility with
the potential daily send-out of 400 The total Access Northeast project is anticipated to
increase deliveries in the area by 925 on winter peak days, which is much larger than even
the largest bid at 200 

6.3. Benefit Analysis

As noted above at the most general level the analysis starts with the avoided cost of winter-time 
peak) gas purchases due to the stored LNG, less the summer-time non-peak) gas cost to ?ll the
storage facility, less the contract costs to obtain the storage service. The net of these ?gures
represents the net bene?t of the PESC. The analysis of peak-day prices and off-peak prices, together
with the operational parameters, yields the gross commodity bene?t. From this commodity bene?t,
the annual contract costs must be deducted in order to arrive at a net bene?t ?gure for a PESC.
Navigant developed a comprehensive spreadsheet model tool to ?nancially analyse each PESC
option using a consistent framework, assumptions and methodology.

Depending on the quantity of daily gas sendout re?ected in a bid, contract volumes could exceed the
need for LNG peaking supplies by the LDC, or perhaps even for the State of Maine. Thus, because
of the interplay of contract volume with potential LDC demand volume, or potential State of Maine
demand volume, Navigant?s analysis includes breakouts of contract volume across different allocation
categories LDC, Maine, out-of-state) of the stored LNG to provide tracking for informational
purposes. At the snapshot level, net bene?ts are shown for each contract for each estimated demand
segment by allocation category. For consistency in analysis, as well as due to some uncertainties in
estimated start dates, we have assumed a uniform initial start date of 2022 for all bid options. All
?gures have been re?ected in 2015 (real) dollars in order to be consistent with Navigant?s market

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forecast of prices, as well as the forecast results of the Daily Model. Since our assumptions show
that the contracting party, e.g. an LDC, may not have suf?cient load by itself to use the full
vaporization rate under a PESC, we assume that as ?holder? or ?owner? of the PESC, the LDC would
be in a position to maximize value of the PESC (say by selling excess gas at peak), in order to
bene?cially offset contract costs that it would be subject to paying. Thus, the operative metric for
comparison is assumed to be the net bene?t of a bid option incorporating the total bid volume,
regardless of the ultimate disposition of the stored LNG. This assumption is consistent with the
assumption that direct contract costs and bene?ts realized as a result of a PESC will ?ow to the
ratepayers of the contracting entity.

Navigant?s analytical tool compares each contract?s parameters, including speci?cally vaporization
days and volumes, to an estimated demand for peak supplies by Maine LDCs, and then the balance
of Maine to give a view of Maine gas demand in total, with any remaining positive balance going to
serve out-of-state peak sales. In order to arrive at an estimated demand for LDC peak LNG supplies,
Navigant deducts from overall LDC demand estimates an estimate of LDC-contracted supplies,
leaving an estimate of uncontracted LDC supply requirement. The source of the estimated LDC
contracted supplies, as noted earlier, is the Maine PUC staff for this project. Similarly, for the balance
of Maine, Navigant deducts from the balance of Maine demand estimates of Maine-contracted
supplies, leaving an estimate of uncontracted balance-of-Maine supply requirement. Any remaining
contract volumes are assumed to be used for out-of-state sales. The tool then estimates the market
value of the peak LNG supplies by market, based on volume and number of vaporization days subject
to the demand requirements just discussed.

For purposes of estimating the peak value of the LNG, Navigant utilized its Daily Model. The price in
each snapshot applicable to the avoided peak price of LNG-based supply is derived as the average of
the top 15 days falling in the two-month winter period (assumed as January and February) in each
snapshot year. As discussed earlier, the pricing point used in the analysis is Tennessee Gas Pipeline
Zone 6-delivered, a liquid point with applicability for northern New England and for Maine given the
lack of liquid gas trading points in the Maine market itself.

Finally, annual contract costs are netted out from the commodity bene?t in order to arrive at an
annual cost-bene?t result in each snapshot year. For purposes of the volume breakouts, we have
netted the contract costs out of the LDC peak value bene?t, since the LDC will be responsible for
meeting the contract costs. This generally results in negative net bene?ts showing at the LDC level,
before allowing for peak value bene?t from beyond the LDC to be incorporated into the result. There
are also results with negative net bene?ts showing at the State of Maine level, before allowing for
peak value bene?t from out of state sales to be incorporated into the result. Finally, we have
generated a net bene?t calculation reflecting the subtraction of the contract costs from the net margin
on commodity for the entire contract volume, including any residual out-of-state sales. The results
coming from the calculation based on total contract volumes, which may incorporate some out-of-
state sales, is the appropriate measuring point for the net cost-bene?t analysis as it re?ects the total
position of the LDC contracting party from the PESC. To clarify, such out-of-state bene?ts would not
be accruing to out-of-state consumers, but would represent contract value from out-of-state sales,
presumably realized by the LDC on account of its ratepayers.

With regard to speci?c categories of contract costs, most bid options contained an annual ?xed

charge, generally levelized over the contract term, although one bidder included a partial escalation of
a portion of the ?xed charge. In addition to annual ?xed charges, elements of variable costs were

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also presented. In some instances, the variable costs were already re?ected on an annual basis, in
essence as an additional category of ?xed costs. These were added in to the cost calculation as
presented. In some instances, variable costs were noted, but had already been included in the ?xed
charge and therefore need not have been included as a separate item. Other bidders presented
volumetric variable costs, which were incorporated based on project volume. One bidder included an
electric charge based on estimated energy consumption, and this cost item was accounted for using
the 2015 average Maine retail power price.

Several other parameters contributing to contract costs were liquefaction fuel requirements as well as
vaporization losses. For liquefaction fuel, an adder was calculated with respect to the summer-time
?ll costs to re?ect the additional percentage of fuel requirement. For vaporization losses, an
adjustment was made to the avoided volumes of peak-period natural gas to re?ect the amount of
losses occurring at the vaporization stage.

Finally, for bid options relying on trucking in of pre-lique?ed LNG supplies, a ?ll cost premium for LNG
supplies versus pipeline natural gas was included. The premium is a percentage adder on top of the
standard ?ll cost (which is based on Navigant?s non-peak price forecast). The percentage is
derived from the historical relationship over summer periods during 2013-2016 between landed LNG
costs at the Everett import facility in Massachusetts and the price at Tennessee Zone 6-delivered and
was 74 percent, as shown for various trucking-related options in Table 7.

With respect to gas transport, since either summer-time ?ll gas or winter-time peak supplies would
require pipeline transport, it was assumed to be an equivalent cost that was not included in the
analysis. Similarly, due to the lack of public data on LNG transport costs, an equivalent cost was
assumed for pipeline and trucking costs in the analysis and was not specifically included.

In order to estimate an NPV value for the net bene?t over a proposed entire contract term,
the net benefits in intervening years between the snapshot years have been estimated using a
process based on the price levels contained in Navigant?s market assessment. Speci?cally,
annual interpolated values between snapshot values of the ratio between the peak and its 
average price was applied to the average prices in the intervening years in Navigant?s forecast. A
real discount rate of 4 percent has been utilized, accounting for the fact that the net bene?t flows are
already reflected in real 2015 dollars. In addition, a Return on Investment (ROI) has also been
estimated to accompany each NPV result to complete the analytical results.

7. Analysis of PESC Bids

Following is a set of analyses for each PESC bidder, summarizing each bid option, and presenting gross
margin, contract cost, and net bene?t results across the snapshot years. More detailed results appear in
Appendix A for the ?with Access Northeast? scenario and in Appendix for the ?without Access
Northeast? scenario.

7.1. Cavus

Cavus has proposed two options, both with liquefaction facilities. The tank size is the same at one
Bcf. The vaporization rate is 200 for the base offer (Cavus 1), yielding ?ve effective use days,
and 100 for the alternative offer (Cavus 2), yielding 10 effective use days. The ?ll rate for the
base offer is also faster, at 5.4 versus 4.1 for the alternative offer; these ?ll rates yield

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?ll times of 185 days and 244 days, respectively. The ?xed costs for the higher vaporization option
are higher at $25 million per year (nominal), as opposed to $21 million per year for the 100 
option. Cavus has also added a variable cost of $.05 per (for a total of $50,000 per one 
tankful), plus power costs of 13.2 per ?ll. At the 2015 Maine average retail power price of
$1297 per kWh, the power charge comes to about $1.7 million. Cavus has stated a vaporization loss
factor of two percent, which has been applied as a deduction from the calculated value of gross sales,
and thus gross margin.

7. 1.1. With Access Northeast
Modeled as outlined above, Cavus 1 net bene?ts are negative for the LDC, for the State of Maine,
and in total across each of the applicable three snapshot years. The NPV of the total annual net
bene?ts over the term comes to negative $98 million, with an ROI of negative 44%, as shown in
Section 7.7. Thus, Cavus 1 is not considered a viable option for the program, under the ?With Access
Northeast? scenario.

Modeled as outlined above, Cavus 2 net bene?ts are negative throughout the term on an LDC basis,
and generally negative for the State of Maine, although at the tail end the net bene?ts do swing
positive. The NPV of the total annual net bene?ts over the term comes to negative $66 million, with
an ROI of negative 35%, as shown in Section 7.7, and thus Cavus 2 is not considered a viable option
for the program, under the ?with Access Northeast? scenario.

 

 

Cavus 1
2015 5 in millions 2022 2032 2042 2052
LDC
Gross Margin 2.17 2.28 3.37 
Less Total Contract Cost 24.12 19.94 16.59 
Net Bene?t (21.95) (17.67) (13.22) 
Maine
Gross Margin 4.76 5.82 9.22 
Less Total Contract Cost 24.12 19.94 16.59 
Net Bene?t (19.36) (14.12) (7.37) 
Out of State
Plus Gross Margin 5.34 4.73 6.11 
Total Bene?t
Net Benefit (14.02) (9.39) (1.26) 

 

 

 

 

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Cavus 2
2015 5 in millions 2022 2032 2042 2052
LDC
Gross Margin 4.32 4.54 6.72 
Less Total Contract Cost 20.55 17.01 14.17 
Net Bene?t (16.23) (12.47) (7.45) 
Maine
Gross Margin 9.48 10.51 15.28 
Less Total Contract Cost 20.55 17.01 14.17 
Net Benefit (11.08) (6.50) 1.11 
Out of State
Plus Gross Margin 0.57 0.00 0.00 
Total Benefit
Net Benefit (10.51) (6.50) 1.11 

 

 

 

 

7.1.2. Without Access Northeast

Modeled as outlined above, Cavus 1 net bene?ts are negative for the LDC and for the State of Maine,
across each of the applicable three snapshot years. For total contract volumes, the net bene?ts do
become positive at the tail end of the term. The NPV of the total annual net bene?ts over the term comes
to negative $29 million, with an ROI of negative 13%, as shown in Section 8.1. Thus, Cavus 1 is not
considered a viable option for the program, even under the ?without Access Northeast? scenario.

Modeled as outlined above, Cavus 2 net bene?ts are negative throughout the term on an LDC basis, and
generally negative for the State of Maine, although at the tail end the net bene?ts do swing positive. The
NPV of the total annual net bene?ts over the term comes to $3 million, as shown in Section 8.1.
However, the ROI of the Cavus 2 option is only insuf?cient financial value to meet project goals in
an economically desirable manner. Thus, Cavus 2 is not considered a viable option for the program,
even under the ?without Access Northeast? scenario.

 

 

 

Cavus 1
2015 millions 2022 2032 2042 2052
LDC
Gross Margin 2.92 3.76 5.86 NIA
Less Total Contract Cost 
Net Bene?t (21.27) (16.32) (10.95) 
Maine
Gross Margin 6.39 9.61 16.05 NIA
Less Total Contract Cost 24.19 
Net Bene?t (17.80) (10.47) (0.77) 
Out of State
Plus Gross Margin 
Total Bene?t
Net Bene?t (10.63) (2.67) 9.87 NIA

 

 

 

 

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Cavus 2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 5.81 7.50 11.71 NIA
Less Total Contract Cost 
Net Bene?t (14.81) (9.64) (2.69) 
Maine
Gross Margin 12.73 17.37 26.64 NIA
Less Total Contract Cost 
Net Bene?t (7.89) 0.23 12.24 
Out of State
Pius Gross Margin 
Total Bene?t
Net Bene?t (7.12) 0.23 12.24 NIA

 

 

 

 

7.2. Eagle Partners

Eagle has proposed two different trucked-in LNG options, one with a capacity of (Eagle 1)
and one with a capacity of. (Eagle 2). Navigant has modeled Eagle 1 as avin. days of
sendout at. and Eagle 2 as having days of sendout The ?xed charges
have been stated as -million for Eagle 1 and million for Eagle 2. Both options are for.
years. It should be noted that the bids state that land cost and ?xed operating costs have not been
accounted for nor included.

7.2.1. With Access Northeast

Modeled as outlined above, Eagle 1 net bene?ts are negative for the LDC, and for the State of Maine
(and in total), across all three snapshot years. The NPV of the total annual net bene?ts over the term
comes to negative $28 million, with an ROI of negative 85%, as shown in Section 7.7. Thus, Eagle 1
is not considered a viable option for the program, under the ?with Access Northeast? scenario.

Modeled as outlined above, Eagle 2 net bene?ts are negative for the LDC, and for the State of Maine
(and in total), across all three snapshot years. The NPV of the total annual net bene?ts over the term
comes to negative $22 million, with an ROI of negative 69%, as shown in Section 7.7. Thus, Eagle 2
is not considered a viable option for the program, under the ?with Access Northeast? scenario.

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Eagle Partners 1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 
Less Total Contract Cost NA
Net BeneMaine
Gross Margin 
Less Total Contract Cost 
Net Benefit (3.17) (2.57) (1.90) 
Out of State
Plus Gross Margin - - - 
Total Benefit
Net Benefit (3.17) (2.57) (1.90) 
Eagle Partners 2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 
Less Total Contract Cost 
Net Bene?t (2.60) (2.06) (1.25) 
Maine
Gross Margin 
Less Total Contract Cost 
Net Bene?t (2.60) (2.06) (1.25) 
Out of State

Plus Gross Margin - - - 

Total Benefit
Net Benefit (2.60) (2.06) (1.25) 

 

 

 

 

7. 2.2. Without Access Northeast

Modeled as outlined above, Eagle 1 net bene?ts are negative for the LDC, and for the State of Maine
(and in total), across all three snapshot years. The NPV of the total annual net bene?ts over the term
comes to negative $25 million, with an ROI of negative 77%, as shown in Section 8.1. Thus, Eagle 1
is not considered a viable option for the program, even under the ?without Access Northeast?
scenario.

Modeled as outlined above, Eagle 2 net bene?ts are negative for the LDC, and for the State of Maine
(and in total), across all three snapshot years. The NPV of the total annual net bene?ts over the term
comes to negative $16 million, with an ROI of negative 52%, as shown in Section 8.1. Thus, Eagle 2
is not considered a viable option for the program, even under the "without Access Northeast?
scenario.

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Eagle Partners 1
2015 In millions 2022 2032 2042 2052
LDC
Gross Margin - - - 
Less Total Contract Cost - - 
Net Bene?t (3.03) (2.30) (1 .44) 
Maine
Gross Margin I - - 
Less Total Contract Cost 
Net Bene?t (3.03) (2.30) (1 .44) 
Out of State
Plus Gross Margin - 
Total Benefit
Net Bene?t (3 03) (2 30) (1 44) MIA
Eagle Partners 2
2015 In millions 2042 2052
LDC
Gross Margin 
Less Total Contract Cost 
Net Bene?t (0.35) 
Maine
Gross Margin 
Less Total Contract Cost 
Net Bene?t (0.35) 
Out of State
Plus Gross Margin 
Total Benefit
Net Bene?t (2.32) (1.51) (0.35) NIA
7.3. Engie

 
 
 
   

Engie has proposed two options, one (Engie 1), and one
(Engie 2). The tank size is the same at Bcf. The vaporization rate is under either

option, yielding .effective use days. The ?ll rate for the? offer is. 
yielding a ?ll time ofIdays. For the? option, ere IS an assumption of

Dth/day, for a total of fill days. The ?xed costs for the option are higher at

million per year, as opposed to .million per year for the option. Engie has also stated
variable costs totalling- million and- million annually, for the respective options. Fuel use
and losses are stated as included in the annual costs. Engie?s options are proposed for. years, the
only proposed PESCs with a term that long.

 

7.3.1. With Access Northeast

Modeled as outlined above, Engie 1 net bene?ts are negative throughout the term on an LDC basis,
and generally negative for the State of Maine, although for the later parts of the term the net bene?ts
do swing positive. The NPV of the total annual net bene?ts over the term comes to negative $42
million, with an ROI of negative 15%, as shown in Section 7.7, and thus Engie 1 is not considered a
viable option for the program, under the ?with Access Northeast? scenario.

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Modeled as outlined above, Engie 2 net bene?ts are negative throughout the term on an LDC basis,
and generally negative for the State of Maine, although for the later parts of terms the net bene?ts do
swing positive. The NPV of the total annual net bene?ts over the term comes to negative $8 million,
with an ROI of negative as shown in Section 7.7, and thus Engie 2 is not considered a viable
option for the program, under the ?with Access Northeast? scenario.

 

 

 

 

 

 

 

 

Engie 1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin
less Total Contract Cost I
Net Benefit (20.77) (15.94) (9.55) (6.56)
Maine
Gross Margin
Less Total Contract Cost
Net Benefit (14.56) (7.44) 4.44 8.2
Out of State
Plus Gross Margin - -
Total Benefit
Net Benefit (11.45) (6.21) 4.44 8.58
Engie 2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin
less Total Contract Cost I I I
Net Benefit (15.37) (13.32) (8.94) (7.11)
Maine
Gross Margin
less Total Contract Cost
Net Benefit . . .
Out of State
Plus Gross Margin - - - -
Total Benefit
Net Benefit (6.04) (3.59) 5.05 8.03

 

 

 

 

7. 3.2. Without Access Northeast

Modeled as outlined above, Engie 1 net bene?ts are negative throughout the term on an LDC basis,
but swing positive for the State of Maine. The NPV of the total annual net bene?ts over the term

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comes to $103 million, with an ROI of 37%, as shown in Section 8.1, and thus Engie 1 is considered
a viable option for the program, under the ?without Access Northeast" scenario.

Modeled as outlined above, Engie 2 net bene?ts are negative throughout the term on an LDC basis,
but swing positive for the State of Maine. The NPV of the total annual net bene?ts over the term
comes to $137 million, with an ROI of 56%, as shown in Section 8.1, and thus Engie 2 is considered
a viable option for the program, under the ?without Access Northeast? scenario.

 

 

 

 

Engie 1
2015 in millions 2022 2032 2042 2052
Loc 
I I I 
Less Total Contract Cost 
Net Bene?t (18.99) (12.39) (3.56) (1.06)
Maine
Gross Margin - -
Less Total Contract Cost
Net Bene?t (10.65) 1.66 20.80 23.91
Out of State
Plus Gross Margin - - -
Total Benefit
Net Bene?t (6.47) 3.67 20.80 24.52
Engie 2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin - - - -
Less Total Contract Cost 
Net Bene?t (13.59) (9.76) (2.95) (1.62)
Maine
Gross Margin - -
Less Total Contract Cost -
Net Bene?t (5.25) 4.28 21.40 23.35
Out of State
Pius Gross Margin - - -
Total Benefit
Net Bene?t (1.07) 6.30 21.40 23.96

 

 

 

 

7.4. Maine Energy Storage (Northern)

Northern has proposed one option, based on facilities. The tank size is Bcf.
The vaporization rate is. yielding effective use days. The ?ll rate for isl yield
?ll time of days. The ?xed costs are stated as million per year, plus CPI escalation on a 
portion. Northern has also added a variable cost of per Mcf, plus CPI escalation. Northern has
stated a vaporization loss factor of percent, which has been applied as a deduction from the
calculated value of gross sales, an us gross margin. Northern has also stated a_ -

applied as an additional ?ll cost.

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7.4.1. With Access Northeast

Modeled as outlined above, Northern net bene?ts are negative for the LDC, and for the State of
Maine, across all three snapshot years. The NPV of the total annual net bene?ts over the term
comes to negative $98 million, with an ROI of negative 40%, as shown in Section 7.7. Thus,
Northern is not considered a viable option for the program, under the ?with Access Northeast?

 

 

 

scenario.
Northern 1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 
Less Total Contract Cost NA
Net Bene?t (20.88) 
Maine
Gross Margin I 
Less Total Contract Cost MA
Net Benefit (15.70) 
Out of State
Plus Gross Margin - 
Total Benefit
Net Bene?t (13.11) (9.88) (2.02) 

 

 

 

 

7.4.2. Without Access Northeast

Modeled as outlined above, Northern net bene?ts are negative for the LDC, and generally negative
for the State of Maine, although for the later parts of the term the net bene?ts do swing positive. The
NPV of the total annual net bene?ts over the term comes to negative $16 million, with an ROI of
negative as shown in Section 8.1. Thus, Northern is not considered a viable option for the
program, even under the ?without Access Northeast" scenario.

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Northern 1
2015 in millions
LDC
Gross Margin
Less Total Contract Cost
Net Bene?t
Maine
Gross Margin
Less Total Contract Cost
Net Bene?t
Out of State
Plus Gross Margin
Total Benefit
Net Bene?t

 

 

2022 2032 2042 2052

(19.48) (15.19) (8.96) 
I I I

(12.53) (3.49) 11.33 
- - - 
(9.05) (1.31) 11.33 NIA

 

 

 

 

7.5. Norths tar

has proposed two options, one with
2). The tank size is same at .3 The vaporization rate 15

under either option, yielding effective use days. The ?ll rate for the
IS yielding a fill time of

247 days for a full tank, yielding

   
 
 

  
  

 

1), and one

offer

days. For the_ option, there is an assumption of
days for the PESC volumes. The ?xed and variable costs for

both options total million per year.
ontract terms are years.

7.5.1. With Access Northeast

Modeled as outlined above, 1 net bene?ts are negative throughout the term on an LDC
basis, and generally negative for the State of Maine, although for the later parts of the term the net
bene?ts do swing positive for Maine as real gross margin increases while real contract costs
decrease, and then with out-of-state sales included bene?ts swing noticeably positive9. The NPV of
the total annual net bene?ts over the term comes to plus $6 million, as shown in Section 7.7.
However, the ROI of the 1 option is only indicating insuf?cient ?nancial value of the
option to meet project goals in an economically ef?cient manner. Thus, 1 would not be
considered a viable option for the program, under the ?with Access Northeast? scenario.

Modeled as outlined above, 2 net benefits are negative throughout the term on an LDC
basis, and generally negative for the State of Maine. While gross margins are the same as with
1 due to the same sendout and volumes, the net benefits are more negative/less positive
due to the LNG premium associated with the trucked-in LNG supply in conjunction with otherwise
equivalent costs. The NPV of the total annual net bene?ts over the term comes to negative $33
million, with an ROI of negative 15%, as shown in Section 7.7, and thus 2 is not considered
a viable option for the program, under the ?with Access Northeast? scenario.

 

8 proposed facility is actually

9 It should be noted that relying on out-year net benefits to sw

Bcf, but with only!? committed to the PESC.
Ing analysis of net bene?ts positive may

be subject to an extra risk factor as outcomes further into the future are generally more uncertain.

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1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 
Less Total Contract Cost 
Net Benefit (7.20) 
Maine
Gross Margin 
less Total Contract Cost 
Net Bene?t 4.50 
Out of State
Plus Gross Margin - A
Total Benefit
Net Benefit (3.88) (0.38) 9 06 
2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin 
Less Total Contract Cost 
Net Benefit . . . 
Maine
Gross Margin 
Less Total Contract Cost 
Net Benefit . . . 
Out of State
Plus Gross Margin - - - 
Total Benefit
Net Benefit (6.78) (4.26) 4.59 

 

 

 

 

7.5.2. Without Access Northeast

Modeled as outlined above, 1 net benefits are negative throughout the term on an LDC
basis, but swing positive for the State of Maine, as real gross margin increases while real contract
costs decrease, and then with out-of-state sales included bene?ts swing noticeably positive. The
NPV of the total annual net bene?ts over the term comes to plus $109 million with an ROI of 61%, as
shown in Section 8.1. Thus, 1 would be considered a viable option for the program, under
the ?without Access Northeast" scenario.

Modeled as outlined above, 2 net benefits are negative throughout the term on an LDC
basis, but swing positive for the State of Maine. While gross margins are the same as with 
1 due to the same sendout and volumes, the net benefits are less positive due to the

in conjunction with otherwise equivalent costs.
Nevertheless, the NPV of the total annual net bene?ts over the term comes to $70 million, with an
ROI of 32%, as shown in Section 8.1, and thus 2 is considered a viable option for the
program, under the ?without Access Northeast? scenario.

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1
201 5 in millions 2022 2032 2042 2052
LDC
Gross Margin - - - NIA
Less Total Contract Cost 
Net Bene?t (13.30) (8.89) (2.55) 
Maine
Gross Margin - - NJA
Less Total Contract Cost 
Net Bene?t (6.35) 2.81 17.82 
Out of State
Plus Gross Margin - 
Total Bene?t
Net Bene?t 1.20 9.71 25.75 NIA
2
2015 millions 2022 2032 2042 2052
LDC
Gross Margin - - 
Less Total Contract Cost - 
Net Bene?t (16.20) (12.77) (7.02) 
Maine
Gross Margin - - 
Less Total Contract Cost 
Net Bene?t (9.25) (1.07) 13.35 
Out of State
Plus Gross Margin - Ni
Total Benefit
Net Bene?t (1.71) 5.83 21.28 NIA

 

 

 

 

7.6. Reliable

Reliable has roposed two options, one with _(Reliable 1), and one-
?Reliable 2). The tank size for the _option is _Bcf, with a vaporization
rate of yielding .effective use days. The tank size for the _option is-3cf,
with a vaporization rate of also yielding .effective use days but with the reater
sendout. The ?ll rate for the _ffer is-lecfd, yielding a ?ll time of ays. For
the option, a total of -?ll days has been stated. The ?xed costs for the 
option is million per year, while ?xed costs are _million per year for the _option.

Contract terms

 
 
 

  
   
   

  
 

are years.

7.6.1. With Access Northeast

Modeled as outlined above, Reliable 1 net benefits are negative throughout the term on an LDC
basis, and generally negative for the State of Maine, although for the later parts of the term the net
benefits do swing positive. With the sendout rate of there are some limited out-of-state
sales for Reliable 1. The NPV of the total annual net bene?ts over the term comes to negative $44

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million, with an ROI of negative 22%, as shown in Section 7.7, and thus Reliable 1 is not considered a
viable option for the program, under the ?with Access Northeast? scenario.

Modeled as outlined above, Reliable 2 net benefits are negative throughout the term on an LDC
basis, and generally negative for the State of Maine, although for the later parts of the term the net

benefits do swing positive. With the sendout rate of

significant out-of-state sales for Reliable 2. Nevertheless, the
to cost and the NPV of the total annual net bene?ts over the term comes to negative $12 million, with
an ROI of negative as shown in Section 7.7. Thus, Reliable 2 is not considered a viable option

for the program, under the ?with Access Northeast? scenario.

 

 

 

 

 

 

 

Reliable 1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin - - 
Less Total Contract Cost 
Net Benefit (17.00) (13.32) (8.32) 
Maine
Gross Margin - - 
Less Total Contract Cost 
Net Benefit (11.83) (6.23) 3.38 
Out of State
Plus Gross Margin - - - 
Total Benefit
Net Benefit (8.73) (4.69) 4.11 
Reliable 2
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin - - - 
Less Total Contract Cost 
Net Benefit (21.35) (19.26) (15.28) 
Maine
Gross Margin - - 
Less Total Contract Cost 
Net Benefit (16.17) (12.17) (3.58) 
Out of State
Plus Gross Margin - - - 
Total Benefit
Net Benefit (5.50) (2.72) 8.64 

 

 

7.6.2. Without Access Northeast

and the .Bcf tank size, there are
contributes

Modeled as outlined above, Reliable 1 net benefits are negative throughout the term on an LDC
basis, but swing positive for the State of Maine. With the sendout rate of there are some
limited out-of-state sales for Reliable 1. The NPV of the total annual net bene?ts over the term comes

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to $43 million, with an ROI of 22%, as shown in Section 8.1, and thus Reliable 1 is considered a
viable option for the program, under the ?without Access Northeast" scenario.

Modeled as outlined above, Reliable 2 net bene?ts are negative throughout the term on an LDC
basis, and generally negative for the State of Maine, although for the later parts of the term the net
bene?ts do swing positive. With the sendout rate of and the tank size, there are
significant out-of-state sales for Reliable 2. Despite the ?the NPV of the
total annual net bene?ts over the term comes to $127 million, with an ROI of 49%, as shown in

Section 8.1. Thus, Reliable 2 is considered a viable option for the program, under the ?without
Access Northeast? scenario.

 

 

 

 

 

 

   

   

Reliable 1
2015 in millions 2022 2032 2042 2052
LDC
Gross Margin - - - NIA
Less Total Contract Cost 
Net Bene?t (15.58) (10.49) (3.54) 
Maine
Gross Margin - - NIA
Less Total Contract Cost 
Net Bene?t (8.63) 1.22 16.83 
Out of State
Plus Gross Margin - 
Total Bene?t
Net Bene?t (4.47) 3.77 18.09 NIA
Reliable 2
2015 in millions 2032 2042 2052
LDC
Gross Margin - NIA
Less Total Contract Cost 
Net Bene?t (10.63) 
Maine
Gross Margin - 
Less Total Contract Cost 
Net Bene?t 9.73 
Out of State
Pius Gross Margin - 
Total Benefit
Net Bene?t 1.31 10.81 31.01 NIA

 

 

 

 

7. 7. Summary of PESC Bid Total Net Benefits

Following is a summary table showing the NPV of each PESC option annual net bene?ts. As can be
seen, only 1 shows a positive NPV, but with an ROI of only 

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Table 8: PESC Option NPV and ROI, With Access Northeast

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 5.8 3.2%

?yie 2 (8.2) 
Reliable 2 (11.7) 
?yie 1 (41.8) -15.0%
2 (33.2) -15.3%
Reliable 1 (43.7) -22.2%
Cavus 2 (65.8) -35.1%
Northern 1 (98.4) -40.1%
Cavus 1 (97.7) -44.4%
gale Partners 2 (22.0) -69.2%
gale Partners 1 (28.0) -85.1%

 

 

8. Other Factors

8.1. Without Access Northeast Scenario

As noted in the prior section, only one PESC option has a positive NPV using Navigant?s Daily Model
analysis based on the ?with Access Northeast? scenario. Following is a table showing the difference
in forecast average and peak prices for the snapshot years between the ?With Access Northeast?
scenario and the without Access Northeast? scenario.

Table 9: Winter Prices, Base Case and No Access NE Scenario

 

 

 

 

2015$mm With Access Northeast Without Access Northeast
February 15-Day Average February 15-Day Average

Year

Average Peak Average Peak
2022 $4.71 $13.42 $5.24 $16.88
2032 $5.55 $14.99 $7.02 $21.86
2042 $6.57 $20.44 $9.43 $31 .80
2052 $6.69 $21.24 $9.95 $32.31

 

 

 

 

 

 

As can be seen, there is a general increase in both average and peak forecasted prices when Access
Northeast is excluded. The impact of these price increases on PESC option NPV and ROI is shown
in the following table, where project NPVs and ROls become more favorable, with seven PESC
options having positive NPV. While Access Northeast has experienced some delays, there is no
speci?c indication that the project is not intended to be pursued. Further, the continued need for
pipeline capacity to meet existing and growing New England demand, as well as the new political
environment in Washington and announced appointments in the new administration, tend to support

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the ?with Access Northeast? scenario. In addition, even if Access Northeast is not built, the market
will likely respond accordingly with some other pipeline project being built, as has historically been the
case when the need for additional capacity is indicated by the market.

Table 10: PESC Option NPV and ROI, Without Access Northeast

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 109.1 60.7%
Engie 2 136.8 55.7%
Reliable 2 126.8 49.1%
Engie 1 103.2 37.0%
2 70.1 32.0%
Reliable 1 42.8 21.6%
Cavus 2 3.1 1.6%

Northern 1 (15.7) 
Cavus 1 (28.8) -13.0%
Eagle Partners 2 (16.4) -51.6%
Eagle Partners 1 (25.2) -76.6%

 

 

 

 

 

8.2. Use of Average Prices

The results presented above assume that avoided costs relate to an estimated average peak price. In
practice, this may be an optimistic assumption. As a contrast, Navigant also analysed net bene?ts and
associated NPV and ROI assuming that avoided costs are based on average wintertime prices. The
results of this analysis indicate consistent negative PESC valuation, as shown in the following sections.

8.2.1. With Access Northeast

Table 11 presents the NPV and ROI results in the ?with Access Northeast? scenario, assuming average
wintertime price avoided costs. These results are the most unfavorable of the presented results.

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Table 11: PESC Option NPV and ROI, With Access Northeast, Avg. Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 (153.1) -87.8%
Reliable 2 (224.6) -88.7%
E_ngie 2 (219.4) -89.3%
2 (192.1) -90.0%
Engie 1 (253.0) -90.6%
Reliable 1 (176.8) -90.9%
Cavus 2 (171.7) -92.6%
Northern 1 (225.5) -93.0%
Cavus 1 (203.6) -93.5%
E_agle Partners 2 (30.7) -96.4%
E_lagle Partners 1 (32.3) -98.3%

 

 

8. 2.2. Without Access Northeast

Table 12 presents the NPV and ROI results in the ?without Access Northeast? scenario, also assuming
average wintertime price avoided costs. These results are also signi?cantly unfavorable.

Table 12: PESC Option NPV and ROI, Without Access Northeast, Avg. Prices

 

 

 

 

 

 

 

 

 

 

 

 

2015 in millions NPV Net Bene?t ROI

1 (130.9) -74.8%
Engie 2 (185.7) -75.6%
Reliable 2 (194.8) -76.8%
mie 1 (219.3) -78.5%
2 (169.9) -79.4%
Reliable 1 (158.2) -81.2%
Cavus 2 (156.9) -84.5%
Northern 1 (207.7) -85.5%
Cavus 1 (188.8) -86.5%
Eagle Partners 2 (29.5) -92.6%
Eagle Partners 1 (31.7) -96.4%

 

 

 

 

 

8.3. Historical Snapshot Review
Navigant?s analytical conclusions and ?ndings focus on the forecast analysis outlined previously. For
informational purposes, Navigant also prepared snapshots of net bene?ts for both the Polar Vortex

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winter of 2013/2014 (for extreme cold) and the warmer winter of 2015/2016. Detailed results appear
in Appendix C.

For the Polar Vortex, one-year net bene?ts show positive value for nine out of eleven PESC options,
ranging from about $10 million to $47 million in one-year net bene?ts. As an indication of the
magnitude of effects, the total net bene?ts for all PESC options increases by $320 million from
negative $86 million to positive $234 million from the net bene?ts for the 2022 ?with Access
Northeast? scenario snapshot, due to the much higher avoided costs following from the high historical
average peak prices during that event.

For the warmer winter of 2015/2016, one-year net bene?ts for all PESC options show a deterioration
of about $100 million, from negative $86 million to negative $185 million, when compared to the
already unfavorable net bene?ts of the "with Access Northeast? scenario forecast analysis for the
2022 snapshot. All eleven PESC options show negative bene?t for the warmer winter, ranging up to
negative $24 million.

8.4. Power Market Impacts

As indicated in Section 6.2 above, the impacts on wholesale gas market prices of these proposed
LNG facilities are very small. Merchant generators purchase fuel on the market and incorporate their
fuel cost into their price bids to the ISO. Since the gas price changes will be small, these price bids to
the ISO and the resultant wholesale market prices will be barely affected. Navigant?s conclusion is
that the LNG impacts will have a de minimis effect on wholesale power prices.

9. Findings

Navigant?s ?ndings relate to the two scenarios, with and without Access Northeast. Under the ?with
Access Northeast? scenario, Navigant?s ?ndings re?ect the almost universal negative net bene?ts of the
PESC options, with only one option 1) having a positive NPV (at only $6 million), but while
also having an ROI of only three percent, considered insuf?cient under typical investment criteria. Thus,
while the ?gross margin" part of the analyses could indicate that an option might provide the opportunity
for access to lower cost natural gas at times of regional peak demand, on a net basis including full
contract costs such a benefit would be illusory as contract net bene?ts are almost universally negative
under this scenario.

With regard to materially enhancing LNG gas storage capacity in the State, most options would actually
accomplish this objective, but again in a ?nancially undesirable manner. Put another way, any bene?t of
having LNG storage capacity is negated by contract costs.

These results are despite the fact that Navigant assumed that the full market value of the proposal will be
available to the ratepayers of the contracting which could realize the value of the total volumes
proposed, whether used to avoid peak priced supplies by the LDC, within the balance of Maine, or as
sales providing gross margin to the contract from out-of-state sales. Thus, not only were the PESC
options not bene?cial at the LDC level, they were also not beneficial with respect to total contract
volumes. The results also are likely generous in that Navigant?s 15-day average peak price methodology

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assumes that projects will be able to sell into the market during the top 15 price days in the winter, which
is an optimistic assumption. We would expect the actual results to be worse to the extent projects were
delivering on more average-level price days, as discussed in Section 8.2.

Under the ?without Access Northeast? scenario, NPV and ROI results became favorable for seven of the
PESC options, re?ecting the higher forecast prices at under this scenario. Compared to the ?with
Access Northeast? scenario, gross margin estimates increase, thus increasing the net bene?ts of the
PESC options. The best of the options end up with ROls in the 50% to 60% range under this scenario,
with several others in the 20% to 40% range. These bene?ts, it should be noted, are contingent on both
the ?without Access Northeast? assumption, as well as assuming that peak prices can be consistently
avoided in practice. As discussed in Section 8.2, if avoided costs are more likely based on average-type
prices, then the results (even under the ?without Access Northeast? scenario) all become unfavorable,
with ROls in the negative 75% to negative 96% range.

With respect to natural gas and electric system reliability, we would expect that some of the storage
facilities, especially if proposed to be located near the facilities of the Portland Natural Gas or Maritimes
and Northeast pipelines, could allow for the more reliable operation of such systems. It is our
understanding, however, that there have not been instances of curtailment of firm transport service in the
State to date.

To conclude, we ?nd that based on our current market view, the PESC options proposed do not appear to
present positive and economically desirable net bene?t analysis results under a ?with Access Northeast?
scenario. Other criteria could exist that may in?uence an ultimate decision, such that a combination of
factors may warrant proceeding, without economic return being the primary driver. In contrast, under the
?without Access Northeast? scenario, some results appear to be economically desirable, although such a
?nding would be assuming optimistic results in practice. Unexpected changes in the market could also
impact all ?ndings, but at this time any such market circumstances that would cause the findings to
change are unforeseen.

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(see separate document)

Final Report: Economic Analysis and Findings Related to

AVIGANT Proposals for LNG Storage Capacity

 

(see separate document)

Final Report: Economic Analysis and Findings Related to

AVIGANT Proposals for LNG Storage Capacity

 

(see separate document)

Final Report: Economic Analysis and Findings Related to

AVIGANT Proposals for LNG Storage Capacity

 

(see separate document)

Final Report: Economic Analysis and Findings Related to

AVIGANT Proposals for LNG Storage Capacity

 

(see separate document)