Mass. Dept. of Public Utilities Ruling to Allow Berkshire Gas to Purchase Natural Gas from Proposed Tennessee Gas Pipeline

The Commonwealth of Massachusetts
——
DEPARTMENT OF PUBLIC UTILITIES
D.P.U. 15-48 August 31, 2015
Petition of The Berkshire Gas Company for Approval of a Precedent Agreement with Tennessee
Gas Pipeline Company, LLC, pursuant to G.L. c. 164, § 94A.
____________________________________________________________________________
APPEARANCES: James Avery, Esq.
Nicholas P. Brown, Esq.
Pierce Atwood, LLP
100 Summer Street, Suite 2250
Boston, Massachusetts 02110
FOR: THE BERKSHIRE GAS COMPANY
Petitioner
Maura Healey, Attorney General
Commonwealth of Massachusetts
By: Elizabeth Anderson
Matthew Saunders
William Stevens
Jamie Tosches
Assistant Attorneys General
Office of Ratepayer Advocacy
One Ashburton Place
Intervenor
Rachel Graham Evans, Esq.
Michael J. Altieri, Esq.
Elizabeth Mahony, Esq.
Department of Energy Resources
100 Cambridge Street, Suite 1020
Intervenor

D.P.U. 15-48 Page ii
Caitlin Peale Sloane, Esq.
Gregory Cunningham, Esq.
David Ismay, Esq.
Conservation Law Foundation
62 Summer Street
Intervenor
Richard D. Bralow, Esq.
TransCanada USPL
717 Texas St., Ste. 2400
Houston, Texas 77002
FOR: PORTLAND NATURAL GAS TRANSMISSION
SYSTEM
Intervenor
Richard A. Kanoff, Esq.
Zachary R. Gates, Esq.
Burns & Levinson LLP
125 Summer Street
FOR: STATE REPRESENTATIVE STEPHEN KULIK
AND PIPE LINE AWARENESS NETWORK FOR
THE NORTHEAST, INC.
Limited Participant
Vincent DeVito, Esq.
Anthony Dragga, Esq.
Bowditch & Dewey, LLP
One International Place, 44th
Floor
FOR: NORTHEAST ENERGY SOLUTIONS, INC.
Limited Participant

D.P.U. 15-48 Page iii
TABLE OF CONTENTS
I. INTRODUCTION AND PROCEDURAL HISTORY .....................................................1
II. STANDARD OF REVIEW .............................................................................................3
III. DESCRIPTION OF COMPANY’S PROPOSAL.............................................................4
IV. POSITIONS OF THE PARTIES ...................................................................................13
A. Attorney General................................................................................................13
B. Department of Energy Resources .......................................................................16
C. Conservation Law Foundation............................................................................19
D. PNGTS ..............................................................................................................23
E. PLAN ................................................................................................................23
F. NEES.................................................................................................................25
G. Berkshire Gas ....................................................................................................26
V. ANALYSIS AND FINDINGS.......................................................................................34
A. Introduction .......................................................................................................34
B. Company’s Motion to Reopen the Record..........................................................35
1. Background............................................................................................35
1. Positions of the Parties ...........................................................................36
2. Standard of Review ................................................................................38
3. Analysis and Findings ............................................................................38
C. Consistency with the Public Interest...................................................................40
1. Consistency with Portfolio Objectives ....................................................40
2. Comparison to Alternatives ....................................................................45
D. GWSA Considerations.......................................................................................51
VI. CLF MOTION TO AMEND THE PROCEDURAL SCHEDULE .................................54
A. Background........................................................................................................54
B. Analysis and Findings........................................................................................57
VII. CONCLUSION .............................................................................................................58
VIII. ORDER.........................................................................................................................59

D.P.U. 15-48 Page 1
I. INTRODUCTION AND PROCEDURAL HISTORY
On April 21, 2015, The Berkshire Gas Company (“Berkshire” or “Company”) filed a
petition with the Department of Public Utilities (“Department”) pursuant to G.L. c. 164, § 94A
(“Section 94A”) seeking approval of a precedent agreement for a 20-year firm transportation
contract with Tennessee Gas Pipeline, LLC (“Tennessee”).1
Tennessee is seeking to expand its
pipeline capacity from Wright, New York, to Dracut, Massachusetts, and this expansion, referred
to as the Northeast Energy Direct (“NED”) project, is expected to go into service on
November 1, 2018 (Exh. BGC-JMB-1, at 9). The precedent agreement sets forth the rights and
obligations of Berkshire and Tennessee during the NED project pre-approval process before the
Federal Energy Regulatory Commission (“FERC”) (Exh. BGC-JMB-1, at 13 & Att. (a)). Upon
satisfaction of the conditions precedent and receipt of FERC approval, Berkshire will execute a
20-year firm transportation service agreement with Tennessee, beginning with the in-service date
of the NED project (Exh. BGC-JMB-1, at 11). The precedent agreement is for a period in excess
of one year and, therefore, subject to the Department’s jurisdiction under Section 94A.
On April 27, 2015, the Attorney General of the Commonwealth (“Attorney General”)
filed a notice of intervention pursuant to G.L. c. 12, § 11E(a), and was recognized as a full party
to this proceeding. The Department received petitions to intervene as full participants in the
matter from the following: Massachusetts Department of Energy Resources (“DOER”);
Conservation Law Foundation (“CLF”); Portland Natural Gas Transmission System (“PNGTS”);
1
Boston Gas Company d/b/a National Grid and Bay State Gas Company d/b/a Columbia
Gas of Massachusetts filed petitions on April 1, 2015, and April 3, 2015, respectively,
seeking the Department’s approval of similar precedent agreements with Tennessee.
Those matters are docketed as D.P.U. 15-34 and D.P.U. 15-39, respectively.

D.P.U. 15-48 Page 2
State Representative Stephen Kulik and Pipe Line Awareness Network for the Northeast, Inc.
(“PLAN”); and Northeast Energy Solutions, Inc. (“NEES”). The Department held a public
hearing and procedural conference on May 26, 2015, in Boston, Massachusetts, pursuant to a
duly issued notice, and a second public hearing on June 11, 2015, in Greenfield, Massachusetts.
The Department subsequently established the procedural schedule for this proceeding.2
On
May 29, 2015, the hearing officer issued a ruling allowing intervention for DOER, CLF, and
PNGTS, and denying intervention for PLAN and NEES, but granting them limited participant
status.3
The Department conducted evidentiary hearings in the three NED dockets on June 24,
June 25, and June 26, 2015.4
The Company sponsored the testimony of Jennifer M. Boucher,
2
On June 1, 2015, CLF filed a motion to amend the procedural schedule. Specifically,
CLF sought an extension of the deadline for intervenors to submit prefiled testimony, and
an extension of the deadlines for issuing and responding to discovery on intervenor
testimony, but leaving all other dates in the schedule the same, including the June 24,
2015 date for commencing the evidentiary hearing. The Company opposed CLF’s
motion. On June 5, 2015, the hearing officer issued a memorandum denying CLF’s
motion for lack of good cause shown, and stating that the analysis outlining the reasons
for denying the motion would be provided in a substantive ruling at a later date. The
Department provides the substantive ruling in Section VI, below.
3
PLAN and NEES subsequently filed appeals of the hearing officer’s ruling. On June 11,
2015, NEES filed an expedited petition with the Supreme Judicial Court, seeking to stay
the proceeding pending the outcome of the appeal. On June 19, 2015, the Department
issued an Interlocutory Order denying PLAN’s and NEES’s appeals and upholding the
hearing officer’s ruling. Thereafter, the Department filed this Interlocutory Order with
the Court, along with a motion to dismiss. On June 24, 2015, a single justice of the Court
denied NEES’s expedited petition.
4
While not consolidating the three dockets filed by Boston Gas Company, Bay State Gas
Company, and Berkshire, the Department held a joint evidentiary hearing on June 25 and
June 26, 2015, in all three NED dockets (D.P.U. 15-34/D.P.U. 15-39/D.P.U. 15-48) for
purposes of examining CLF’s and PNGTS’s witnesses.

D.P.U. 15-48 Page 3
manager of regulatory economics for Berkshire. CLF sponsored the testimony of Gregory
Lander, president of Skipping Stone, LLC. PNGTS sponsored the testimony of its president,
Keith D. Nelson. In addition to the exhibits contained in the original filing and the prefiled
witness testimony and exhibits, the record contains responses to 99 information requests,
nine record requests, and two additional exhibits produced at the evidentiary hearing. On
July 17, 2015, the Company, Attorney General, DOER, CLF, PNGTS, PLAN, and NEES filed
initial briefs. On July 24, 2015, the Company, CLF, PNGTS, and NEES filed reply briefs.
II. STANDARD OF REVIEW
In evaluating a gas company’s options for the acquisition of commodity resources as well
as for the acquisition of capacity under Section 94A, the Department examines whether the
acquisition of the resource is consistent with the public interest. Commonwealth Gas Company,
D.P.U. 94-174-A at 27 (1996). In order to demonstrate that the proposed acquisition of a
resource that provides commodity and/or incremental resources is consistent with the public
interest, a local gas distribution company (“LDC”) must show that the acquisition is:
(1) consistent with the company’s portfolio objectives; and (2) compares favorably to the range
of alternative options reasonably available to the company at the time of the acquisition or
contract renegotiation. D.P.U. 94-174-A at 27.
In establishing that a resource is consistent with the company’s portfolio objectives, the
company may refer to portfolio objectives established in a recently approved forecast and
requirements plan or in a recent review of supply contracts under Section 94A, or may describe
its objectives in the filing accompanying the proposed resource. D.P.U. 94-174-A at 27-28. In
comparing the proposed resource acquisition to current market offerings, the Department

D.P.U. 15-48 Page 4
examines relevant price and non-price attributes of each contract to ensure a contribution to the
strength of the overall supply portfolio. D.P.U. 94-174-A at 28. As part of the review of
relevant price and non-price attributes, the Department considers whether the pricing terms are
competitive with those for the broad range of capacity, storage, and commodity options that were
available to the LDC at the time of the acquisition, as well as with those opportunities that were
available to other LDCs in the region. D.P.U. 94-174-A at 28. In addition, the Department
determines whether the acquisition satisfies the LDC’s non-price objectives including, but not
limited to, flexibility of nominations and reliability and diversity of supplies. D.P.U. 94-174-A
at 28-29. In making these determinations, the Department considers whether the LDC used a
competitive solicitation process that was fair, open, and transparent. The Berkshire Gas
Company, D.T.E. 02-56, at 10 (2002); Bay State Gas Company, D.T.E. 02-52, at 8-9 (2002);
KeySpan Energy Delivery New England, D.T.E. 02-54, at 9-10 (2002); The Berkshire Gas
Company, D.T.E. 02-19, at 6, 11 (2002).
III. DESCRIPTION OF COMPANY’S PROPOSAL
On February 27, 2015, Berkshire entered into an amended precedent agreement for
two complementary 20-year firm gas transportation service agreements on Tennessee’s NED
project (Petition at 1; Exh. BGC-JMB-1, at 3 & Att. (a)).5
The NED project is expected to go
into service on November 1, 2018, and is designed to provide up to 2.2 billion cubic feet per day
(“Bcf/day”) of transportation service from Wright, New York, to Dracut, Massachusetts
5
The parties had initially executed the precedent agreement on October 8, 2014 (Petition
at 1; Exhs. BGC-JMB-1, at 3 & Att. BGC-JMB-1(a)).

D.P.U. 15-48 Page 5
(Exh. BGC-JMB-1, at 3, 9).6
Pursuant to the transportation agreements, Tennessee will deliver a
total of 36,000 dekatherms per day (“Dth/day”) of interstate pipeline capacity from the receipt
point of Wright, New York, to the Company’s distribution system (Petition at 1;
Exh. BGC-JMB-1, at 10, 11). The transportation agreements will provide incremental deliveries
to the Company’s existing citygates at North Adams, Massachusetts, and Pittsfield,
Massachusetts, and to a new primary delivery point to be known as the West Greenfield Gas
Station in the Company’s Eastern Division (Petition at 1; Exh. BGC-JMB-1, at 10-11).
The precedent agreement is for “Market Path” facilities, which are all of the facilities
constructed under the NED project downstream of Wright, New York (Exhs. BGC-JMB-1,
Att (a) at 1, 3; AG 3-1). This is in contrast to the “Supply Path” facilities, which may be
constructed upstream of Wright, New York (Exh. BCG-JMB-1, Att. (a) at 1). The Company is
pursuing a separate precedent agreement to purchase capacity on the Supply Path segment of the
NED project, which, the Company states, is to increase liquidity at Wright, New York, the
receipt point for the Market Path segment (Exh. DPU 2-1(b); Tr. 3, at 34-35). The Company
states that it seeks to enter into the precedent agreement for the Market Path segment because the
NED capacity will enable the Company: (1) to continue to serve existing customer requirements
6
On July 16, 2015, Tennessee’s parent company, Kinder Morgan, announced that the NED
project would be scaled back to provide up to 1.3 Bcf/day, rather than the 2.2 Bcf/day
originally proposed.
www.masslive.com/news/index.ssf/2015/07/kinder_morgan_to_scale_back_ca.html.
This announced reduction does not alter our review of the precedent agreement as
originally filed.

D.P.U. 15-48 Page 6
both reliably and at least-cost; (2) to meet future customer growth; and (3) to resolve capacity
and distribution constraints in the Company’s Eastern Division (Exh. BGC-JMB-1, at 2-3, 5).7
The Company analyzed its need for incremental resources using its established forecast
and supply planning process, which determines trends in customer requirements and determines
whether the Company’s resource portfolio meets customer needs during normal and design
conditions (Exh. BGC-JMB-1, at 4-6). The Company states that it based its demand forecast on
the base-case scenario from its most recently filed five-year forecast and supply plan, The
Berkshire Gas Company, D.P.U. 14-98,8
which demonstrated a need for substantial incremental
resources under essentially all of the Department’s major planning standards
(Exhs. BGC-JMB-1, at 5-6, 11; AG 1-3).9
More specifically, the D.P.U. 14-98 forecast and
supply plan demonstrated that the Company’s resource portfolio was adequate in meeting normal
demand only for the first few years of the planning period, and that its resources were inadequate
for most if not all cases under design-year and design-day conditions (Exh. BGC-JMB-1, at 5).10
7
Berkshire’s service territory consists of two non-contiguous regions in western
Massachusetts: the Western Division in Berkshire county; and the Eastern Division in
Franklin and Hampshire counties (Exh. BCG-JMB-1, at 7 & Att. (b)).
8
The Department issued an Order approving this forecast and supply plan on July 30,
2015.
9
The Company states that its analysis shows that its resource portfolio was inadequate to
meet normal, annual demand beyond the first few years of the planning period, and also
inadequate to meet design year, cold snap and design day standards (Exh. BGC-JMB-1,
at 5-6).
10
A design condition signifies an extreme weather scenario. For example, a design day
would be the coldest day for which an LDC would plan (Tr. 1, at 48). Boston Gas
Company, Colonial Gas Company, and Essex Gas Company, D.T.E. 05-68, at 5 n.4
(2006).

D.P.U. 15-48 Page 7
The Company’s analysis reflected the application and consideration of the Company’s energy
efficiency programs and a number of load management agreements that provide for more
efficient use of the Company’s resources (Exhs. BGC-JMB-1, at 5-6; DPU 1-5, at 1-3 & Att.).
In addition, the Company’s filing in D.P.U. 14-98 outlined an action plan including the expected
imposition of a moratorium that would preclude the provision of distribution service to new
customers or expanded service to existing customers in its Eastern Division (Exh. BGC-JMB-1,
at 6; Tr. 3, at 74). The Company imposed the moratorium in the northern portion of the
Company’s Eastern Division in December 2014, extended it to the entire Eastern Division in
March 2015, and could impose a similar moratorium in the Western Division if necessary
(Exhs. BGC-JMB-1, at 6; CLF 2-4; CLF 2-5). The Company states that the moratorium will last
until a new resource is available to provide additional capacity to the Eastern Division
(Exh. BGC-JMB-1, at 7).
In this case, the Company estimated its planning load demand over a ten-year planning
horizon by applying the average annual design-day growth rate of 2.38 percent to the base case
demand requirements from the Company’s most recent five-year forecast and supply plan period,
thus determining the forecast demand requirements through 2023/2024 (Exhs. BGC-JMB-1,
at 11 & Att. (c); DPU 1-5, at 1). Based on this, the Company determined a planning load
demand of approximately 20,000 Dth/day (Exh. BGC-JMB-1, at 11). The Company also
evaluated the specific requirements related to a large, special contract customer seeking to
expand its gas use (Exh. BGC-JMB-1, at 11). The Company initially anticipated the expanded
requirements of this customer to be approximately 5,000 to 6,000 Dth/day (Exh. BGC-JMB-1,
at 11). The Company’s agreement with this customer includes a commitment to coordinate the

D.P.U. 15-48 Page 8
customer’s requirements relative to Tennessee capacity, and the Company is currently
negotiating an agreement with terms for enhanced service with this customer (Exh. BGC-JMB-1,
at 11-12). The precedent agreement includes a “regulatory out” provision so that the Company,
consistent with the Department’s final Order, may modify its capacity commitment to reflect the
ultimate level of capacity associated with the Company’s arrangement with this special contract
customer (Exhs. BGC-JMB-1, at 12 & Att. (a); AG 3-5).
Finally, the Company updated its forecast planning load to address the anticipated
migration of capacity-exempt customers11
to default service (Exh. BGC-JMB-1, at 12).12
The
return of capacity-exempt customers to default service reclassifies these customers as
capacity-eligible and makes them part of the Company’s planning load thereafter, pursuant to the
applicable tariff. Emergency Authorization for Gas Capacity Planning, D.P.U. 14-111, at 6, 17
(2014). As of May 1, 2015, the Company’s design-day load associated with capacity-exempt
customers was approximately 9,000 Dth/day, plus an additional 12,000 Dth/day of
capacity-exempt load related to special contracts (Exh. DPU 1-9; Tr. 3, at 24-25). Over
Winter 2014/2015, approximately 1,400 Dth of capacity-exempt customer load migrated to
default service, pursuant to D.P.U. 14-111 (Exh. DPU 1-9; Tr. 3, at 24). The Company states
11
Capacity-exempt customers are either: (1) new customers who have elected to purchase
commodity from competitive suppliers or marketers, rather than default service from the
LDC, while relying on the LDC for transportation of the commodity; or (2) customers
who were receiving transportation-only service prior to the unbundling of gas services in
1998 and for whom the LDCs ordinarily have no obligation to procure pipeline capacity.
Emergency Authorization for Gas Capacity Planning, D.P.U. 14-111, at 2 n.1 (2014).
12
Default service means gas commodity service that an LDC provides to a customer who
does not receive service from a third-party supplier. It is the equivalent of basic service
for electric distribution company customers.

D.P.U. 15-48 Page 9
that, in recent years, it has experienced an increase in capacity-exempt customers seeking to
initiate default service, with customer interest at approximately 15 percent (Exh. BGC-JMB-1,
at 12; Tr. 3, at 24-25). The Company states that, based on recent experience and the nature of its
capacity-exempt customers -- many of which are usage-sensitive schools, nursing homes and
hospitals -- it included in its capacity needs up to an additional 10,000 Dth/day for its
capacity-exempt customer requirements, and plans to contract for at least 50 percent of those
customer requirements (5,000 Dth/day) (Exhs. BGC-JMB-1, at 12; DPU 1-5, at 1 & Att.;
RR-AG-1). Thus, the Company seeks to secure up to a total of 36,000 Dth/day from the NED
project to meet its incremental and growth needs (Exh. BGC-JMB-1, at 11).
The Company states that there are no reasonable and viable pipeline alternatives to the
NED project for the Company because Berkshire’s service territory does not have access to any
regional pipeline other than Tennessee, and Tennessee’s existing pipeline capacity to the
Company’s Eastern Division is fully subscribed (Exh. BGC-JMB-1, at 7, 9, 15). Moreover, the
Company states that the NED project is the only pipeline project under development in the
region that could conceivably address the Company’s capacity (Exh. BGC-JMB-1, at 7). The
Company states that, other than limited, on-system peaking resources (i.e., liquid propane (“LP”)
and liquefied natural gas (“LNG”)), it has no physical access to other supplies of natural gas or
interstate pipelines (Exh. BGC-JMB-1, at 7). Over the years, the Company has sought to
respond to its Eastern Division deliverability concerns in other ways, including: (1) introducing
a load management rate, a demand-side management resource to provide customers with a
demand credit based on curtailing demand during peak periods; (2) constructing a new LNG
storage and vaporization facility in Whately, Massachusetts; and (3) reactivating its LP facility in

D.P.U. 15-48 Page 10
Greenfield, Massachusetts to meet increased peak demand requirements (Exh. BGC-JMB-1,
at 7-8; Tr. 3, at 74). The Company states that it has exhausted all available options to increase
deliverability to its Eastern Division and has reached its limits with respect to providing safe,
reliable, and least-cost service to customers (Exh. BGC-JMB-1, at 7-8).
Nevertheless, the Company evaluated and engaged in exploratory discussions concerning
Algonquin Gas Transmission’s Atlantic Bridge project, but determined that this was not a
feasible or viable project alternative without the necessary Tennessee capacity to deliver the
Atlantic Bridge volumes from the Maritimes and Northeast Pipeline to the Company’s citygates
(Exh. BGC-JMB-1, at 15). The Company also determined that the Atlantic Bridge project would
not have addressed the Company’s need to increase deliverability to the Eastern Division
The Company also considered two conceptual alternatives to the NED project: the
expansion of on-system peaking resources; and long-term reliance on third-party, seasonal
citygate-delivered resources (Exh. BGC-JMB-1, at 16). The Company determined that neither of
these alternatives was viable (Exh. BGC-JMB-1, at 16). First, with regard to the expansion of
on-system peaking resources, the Company states that it could not meet its identified design-day
needs with this alternative, even with modifications or improvements to its LP/LNG facilities
(Exh. BGC-JMB-1, at 16). Furthermore, the Company notes that an over-reliance on system
peaking would present operational considerations such as gas-mixing constraints, product and
trucking availability, and increased reliance on mechanical facilities that affect reliability
(Exh. BGC-JMB-1, at 16; Tr. 3, at 80, 83). Moreover, the Company states that LNG costs are

D.P.U. 15-48 Page 11
typically higher and subject to price volatility driven by international markets
Second, with regard to third-party, seasonal citygate-delivered resources, the Company
states that these resources are increasingly difficult to acquire, contain contract terms that limit
flexibility, and command substantial premiums on the secondary market (Exh. BGC-JMB-1,
at 16). Thus, the Company states that it is not practical or economical for the Company to rely
on these resources for more than 25 percent of its design-day requirements in the long term
The Company also considered both price and non-price factors in evaluating the NED
project (Exh. BGC-JMB-1, at 18-20). With respect to price factors, the precedent agreement
provides that the initial negotiated reservation rate is subject to cost adjustments and cost caps
(Exh. BGC-JMB-1, at 12-13). The Company evaluated the costs of its portfolio both with and
without the NED project (Exh. BGC-JMB-1, at 18). With the NED project, the Company states
that it would be able to access reliable, lower-cost supplies from the Marcellus Shale region, and
would not have to dispatch LP and LNG resources for distribution system pressure support,
thereby reducing the annual requirements of those higher-priced resources (Exh. BGC-JMB-1,
at 18-19). Compared to the other conceptual alternatives, the Company estimates that customers
will save approximately $2 million in 2018/2019, with annual savings projected to increase
through 2023/2024 to reach approximately $9 million (Exh. BGC-JMB-1, at 19). According to
the Company, these savings are a result of: (1) gaining access to lower-cost supplies on a
year-round basis; (2) displacing the need for citygate-delivered resources; and (3) reducing the
use of higher-priced on-system LNG and LP resources (Exh. BGC-JMB-1, at 19). The Company

D.P.U. 15-48 Page 12
did not include savings associated with potential portfolio optimization activities in its cost
savings estimates (Exh. BGC-JMB-1, at 19).
With respect to non-price factors, the Company states that the most significant of these
that the Company considered is the ability to meet future customer requirements and end the
moratorium in the Eastern Division, and to substantially enhance existing system reliability
(Exh. BGC-JMB-1, at 15, 20). The Company states that, without the NED project, the ongoing
moratorium will continue in the Eastern Division indefinitely, with continuing adverse economic
and environmental impacts to the area, and could be extended to the Western Division
(Exh. BGC-JMB-1, at 17, 20). The Company states that the NED project’s interconnections in
the northern portions of both the Eastern and Western Divisions will not only provide additional
capacity to those regions, but will also provide a tremendous reliability enhancement by adding a
secondary feed from a major pipeline and mitigating existing pressure constraints
(Exh. BGC-JMB-1, at 20). This will alleviate the Company’s need to dispatch LNG and LP
purely for distribution pressure reinforcement purposes, and will enhance reliability to all of New
England by adding a substantial new capacity resource (Exh. BGC-JMB-1, at 20). Moreover, the
NED capacity will guarantee an increased minimum delivery pressure of 200 psig to all of the
Company’s delivery points, and will provide increased flexibility and diversity to the Company’s
existing resource portfolio (Exh. BGC-JMB-1, at 14, 20). The Company also believes that the
NED project will lower and stabilize regional electric prices, promote economic development
opportunities, and allow natural gas expansion in the Commonwealth (Exh. BGC-JMB-1,
at 20-21).

D.P.U. 15-48 Page 13
IV. POSITIONS OF THE PARTIES
A. Attorney General
The Attorney General argues that the Department should reject the precedent agreement
as filed because the Company failed to prove that the agreement is consistent with the public
interest (Attorney General Brief at 3, 19-20). Regarding compliance with the Company’s
portfolio objectives, the Attorney General first contends that the Department should reject the
Company’s reliance on its 2014 forecast and supply plan, filed in D.P.U. 14-98, because that
forecast and supply plan has not yet been approved by the Department (Attorney General Brief
at 9 and n.31).13
The Attorney General also argues that because the difference between the
2014/2015 base case demand and the projected 2023/2024 base case demand is only
13,384 Dth/day, the Company has not proven a need for the 20,000 Dth/day of additional
capacity that the Company seeks to acquire (Attorney General Brief at 9, citing
Exh. BGC-JMB-1, at 11 & Att. (c)). Furthermore, the Attorney General challenges the
Company’s application of the average annual growth rate of the five-year forecast period in
D.P.U. 14-98, arguing that the growth rate of the most recent two years of the plan period
recognizes the declining growth trend and is therefore more realistic (Attorney General Brief
at 10, citing Exhs. BGC-JMB-1, Att. (c); DPU 1-5; Tr. 3, at 33-34; RR-AG-3).
Second, the Attorney General asserts that the inclusion of the estimated design-day
requirements associated with the anticipated migration of capacity-exempt customers to default
service is inappropriate and overstates the total contract quantity (Attorney General Brief at 3,
11-13). According to the Attorney General, LDCs are not allowed to include the requirements of
13
As noted, the Department approved D.P.U. 14-98 on July 30, 2015.

D.P.U. 15-48 Page 14
such customers in their planning load unless the Department grants an exemption, which the
Department has not granted to the Company other than for the limited term of Winter 2014-2015
(Attorney General Brief at 11-12, citing G.L. c. 164, § 69I; D.P.U. 14-111). The Attorney
General argues that the Department should reject the Company’s proposal to include
capacity-exempt customers in its design-day and design-year requirements because this was not
part of the Company’s latest Department-approved forecast and supply plan, has not been
exempted from the requirements of G.L. c. 164, § 69I, and is not in the public interest (Attorney
General Brief at 13). The Attorney General argues, however, that if the Department approves the
Company’s petition, it should direct the Company to exclude capacity-exempt volumes from the
precedent agreement (Attorney General Brief at 13). Even if the Department disagrees with
excluding capacity-exempt customers, the Attorney General asserts that the Company
acknowledges that its capacity-exempt customer migration load of 10,000 Dth/day is overstated,
and therefore, argues the Attorney General, the Company’s projection is unreliable and
inconsistent with Department precedent (Attorney General Brief at 13-14, citing
Exh. BGC-JMB-1, at 12).
Third, the Attorney General argues that the Company failed to adequately consider
energy efficiency and LNG to meet its incremental capacity needs, including the price and non-
price attributes of these alternatives, and therefore, failed to consider a reasonable range of
alternative options (Attorney General Brief at 3, 15-16). The Attorney General takes issue with
the Company’s failure to use its most recently proposed energy efficiency goals in its load
forecast, and urges the Department to direct the Company to update its projected gas savings to
reflect the more aggressive, positive energy efficiency goals (Attorney General Brief at 17). The

D.P.U. 15-48 Page 15
Attorney General further argues that the Company did not adequately consider an expansion of
its on-line LNG facilities, and that the Company should conduct a cost-benefit analysis regarding
the expansion of its Whately storage facility, which currently has two LNG storage tanks on site
but was approved to accommodate five tanks (Attorney General Brief at 17-18).
Finally, the Attorney General argues that the Company overstates the NED project’s
price and non-price advantages because of how the precedent agreement is structured (Attorney
General Brief at 3, 18-19). The Attorney General contends that the advantages of the Market
Path segment capacity are not as robust as originally indicated, as demonstrated by the
Company’s need for the Supply Path segment to address the concern that the market at Wright,
New York, will not be sufficiently liquid (Attorney General Brief at 18-19, citing
Exh. BGC-JMB-1, at 20; Tr. 3, at 35). Further, the Attorney General describes the Company’s
conclusion that the NED project ranks highest in terms of reliability, flexibility and diversity as
“tenuous,” noting that the Company’s decision to pursue the Supply Path segment capacity
indicates that the precedent agreement does not provide a diversity of supply (Attorney General
Brief at 19). The Attorney General therefore argues that the Company’s petition does not
provide assurance that the NED capacity is the best alternative to meet customer demand, and
that the Department should review the Supply Path and Market Path precedent agreements
together (Attorney General Brief at 19). In addition, the Attorney General asserts that the
precedent agreement includes a non-price benefit of a higher minimum delivery pressure of
200 psig, but the Company did not prove that it experienced any days of recorded minimum
delivery at or near 100 psig during the last two winters (Attorney General Brief at 19). In sum,
the Attorney General recommends that the Department either reject the precedent agreement or

D.P.U. 15-48 Page 16
reopen the record to allow the Company to address the deficiencies identified above (Attorney
General Brief at 19-20).
B. Department of Energy Resources
DOER contends that the Company has demonstrated a forecast supply shortfall and,
therefore, has met the burden of showing a need for additional capacity, and has shown that the
NED project is consistent with the Company’s portfolio objectives (DOER Brief at 4-6, 14).
DOER states that no party has challenged the Company’s forecast or introduced an alternative
forecast (DOER Brief at 5).
DOER argues that the Company has demonstrated that design-day growth of
20,000 Dth/day is a reasonable expectation due to actual growth experienced by the Company,
even with the Company’s Eastern Division moratorium (DOER Brief at 5). DOER notes that the
Company relied on its more conservative base-case forecast in D.P.U. 14-98, but that relying on
a reasonable high-case forecast would be appropriate here because recent trends are more closely
aligned with the high-case forecast, and because the moratorium is likely causing pent-up
demand which could be accommodated once the NED project goes into service (DOER Brief
at 4-5, citing Tr. 3, at 12-13; RR-AG-2). Furthermore, DOER points out that even when the
Company’s more conservative growth rates noted in 2017/2018 and 2018/2019 are applied to the
five-year period beyond the Company’s D.P.U. 14-98 forecast, this results in a lower design-day
requirement for 2023/2024 of between 2,000 to 3,000 Dth/day (DOER Brief at 4-5, citing
Exh. AG-1-5, at 35, 38; RR-AG-3).
DOER also supports the Company’s proposal to secure capacity from the NED project to
serve at least 50 percent of the anticipated capacity-exempt customer demand (DOER Brief at 6).

D.P.U. 15-48 Page 17
DOER contends that this approach represents prudent planning intended to mitigate both winter
reliability concerns and winter supply cost issues (DOER Brief at 7). DOER notes that the
Company continues to receive interest from capacity-exempt customers wishing to return to sales
service (DOER Brief at 6, citing Exh. BCG-JMB-1, at 12; Tr. 3, at 24-25). DOER argues,
however, that with insufficient long-term resources to serve its existing capacity-eligible
customers, the Company will need to purchase additional citygate resources for the migration of
capacity-exempt customers (DOER Brief at 6-7). According to DOER, these additional citygate
purchases will further constrict the already-tight winter capacity, causing prices to escalate and
more capacity-exempt customers to migrate, and creating the possibility of capacity becoming so
constrained that it is no longer available at any price (DOER Brief at 6-7). In fact, DOER
argues, this has already occurred in the Company’s Eastern Division as evidenced by the
moratorium (DOER Brief at 7, citing Exh. BGC-JMB-1, at 6). Because the Company is limited
to Tennessee capacity, and in light of the threat of additional moratoriums as well as the
anticipated expansion of an existing customer, DOER asserts that the Company should not miss
an opportunity to secure sufficient capacity to serve all its gas customers through the NED
project (DOER Brief at 7, citing Exh. BGC-JMB-1, at 12).
DOER further observes that the Company has considered alternatives to the NED project,
but no alternative was able to supply the incremental capacity of 36,000 Dth/day that the
Company proposes to acquire on the NED project (DOER Brief at 8). DOER notes that no
pipeline project, including the Atlantic Bridge project, presents a viable option because it would
require an expansion on the Tennessee pipeline (DOER Brief at 8). Regarding the conceptual
alternatives considered, DOER notes that these alternatives posed operational issues that

D.P.U. 15-48 Page 18
impacted reliability (DOER Brief at 8, citing Exh. BGC-JMB-1, at 16). DOER states that the
Company demonstrated the NED project to be superior due to the significant gas cost savings
and the system reliability enhancement provided by having a secondary feed into the Company’s
Eastern and Western Divisions (DOER Brief at 8-9, citing Exh. BGC-JMB-1, at 16, 19-20).
DOER further notes that the NED project will eliminate the need to dispatch LNG or LP to
maintain system pressures (DOER Brief at 9, citing Exh. BGC-JMB-1, at 20).
DOER argues that no other party identified more favorable alternative options (DOER
Brief at 9). DOER maintains that the Department should reject CLF’s assertion that additional
energy efficiency measures would offset the need for any new supplies because CLF provided no
cost basis, reference, or analysis to evaluate the reasonableness of this alternative (DOER Brief
at 9). Moreover, DOER contends that CLF’s proposal for the Company to use more LNG gives
no weight to supply reliability and security, and ignores pricing issues (DOER Brief at 9-11).
Thus, DOER argues that CLF has not demonstrated that LNG is available as a reasonable
alternative to the NED project (DOER Brief at 11). As for PNGTS as an alternative, DOER
argues that none of PNGTS’s evidence demonstrates that PNGTS’s Continent-to-Coast (“C2C”)
expansion project is superior to the NED project (DOER Brief at 11-13).
Regarding CLF’s proposed greenhouse gas mitigation mechanism, DOER states that CLF
offered the same proposal to the Department in the Algonquin Incremental Market (“AIM”)
project dockets, Boston Gas Company and Colonial Gas Company, D.P.U. 13-157 (2014), Bay
State Gas Company, D.P.U. 13-158 (2014), and NSTAR Gas Company, D.P.U. 13-159 (2014),
and recommends that the Department reject CLF’s proposal in this proceeding for the same
reasons set forth in the AIM decisions (DOER Brief at 13). Further, DOER states that there is no

D.P.U. 15-48 Page 19
evidence in this docket that the NED project will result in increased greenhouse gas emissions
(DOER Brief at 13). To the extent that the NED project results in the use of natural gas
replacing the use of oil for heating, DOER argues that this increased gas capacity will reduce
greenhouse gas emissions (DOER Brief at 13).
C. Conservation Law Foundation
CLF argues that the Department should reject the precedent agreement as inconsistent
with both Section 94A and the Global Warming Solutions Act (“GWSA”) (CLF Brief at 2, 6).14
CLF argues in the alternative that if the Department chooses to approve the precedent agreement,
it should condition its approval on a mechanism that would ensure compliance with the GWSA
(CLF Brief at 2-3 & n.2).
CLF first claims that the Company failed to demonstrate that the precedent agreement is
consistent with the portfolio objectives established in the Company’s most recent forecast and
supply plan (CLF Brief at 7; CLF Reply Brief at 2). CLF notes that the Department has
previously stated that a company’s process for identifying and evaluating resources in a forecast
and supply plan must include a mechanism for comparing all resources, including energy
efficiency, on an equal basis (CLF Brief at 7, citing The Berkshire Gas Company, D.P.U. 12-62,
at 25 (2013)). CLF argues that the amount of capacity being sought above 20,000 Dth/day
renders the precedent agreement imprudent, and that the use of firm pipeline capacity to meet
peak demand is an inefficient use of ratepayer funds (CLF Brief at 8, citing Exh. DPU-CLF 1-1).
14
The GWSA, St. 2008, c. 298, established clean energy goals for the state and created a
framework to reduce greenhouse gas emissions so as to avoid the worst effects of global
warming.

D.P.U. 15-48 Page 20
Further, CLF agrees with the Attorney General that the Company is prevented by statute
from including capacity-exempt customers in its planning load (CLF Reply Brief at 2).
According to CLF, the inclusion of these customers in this proceeding is also a violation of
G.L. c. 164, § 69I’s requirement that all resources, including demand-side resources, be
considered on an equal footing in an LDC’s planning analysis (CLF Reply Brief at 2-3). In
addition, CLF argues that the Company is including capacity-exempt customers in its planning
load for the purposes of procuring capacity, but that capacity will not come into service for three
or more years (CLF Reply Brief at 3). CLF describes this as a fundamental violation of the
Company’s fiduciary duties to its ratepayers, who fund such pipeline capacity purchases (CLF
Reply Brief at 3). To the extent that LDCs might be allowed to plan for capacity-exempt
customers, CLF argues that fairness and Massachusetts law dictate that the ground rules for such
planning must be established on an industry-wide basis pursuant to G.L. c. 164, § 69I, not on an
ad hoc basis to justify the Company’s overbuying firm pipeline capacity (CLF Reply Brief at 3).
CLF next contends that the Company has failed to provide sufficient evidence of
reasonably available alternatives (CLF Brief at 8-9; CLF Reply Brief at 3). According to CLF,
there are reasonably available alternatives, such as pipeline capacity options, LNG storage and
supply options, and demand-side resources, but the Company failed to show that it conducted a
request for proposals (“RFP”) process or credibly considered any of the alternatives (CLF Brief
at 9, citing Tr. 3, at 67, lines 17-23). Instead, CLF maintains, the Company decided to reject all
conceptual alternatives because those alternatives could not offer the full amount of capacity that
the NED project could offer (CLF Brief at 9). According to CLF, this does not comply with the

D.P.U. 15-48 Page 21
Department’s requirement of a fair, open, or transparent solicitation process (CLF Brief at 9;
CLF Reply Brief at 3).
Further, CLF claims that the Company summarily dismissed other capacity sources that
exist or are in development (CLF Brief at 10, citing Exh. CLF-1, at 16). CLF argues that the
Company did not provide an adequate accounting of price and non-price factors regarding other
pipeline capacity options, did not provide cost information for an LNG alternative, and did not
indicate that it considered a combination of supply options to meet its need (CLF Brief at 10-11).
CLF maintains that the market for LNG in New England has undergone a fundamental shift,
making it a far more reliable resource for the Company than the Company is willing to admit
(CLF Brief at 10, citing Exh. CLF-1, at 22). Moreover, CLF contends that it was egregious for
the Company not to conduct an RFP for peaking supplies or compare the daily-use cost of NED
capacity to LNG prices, given that the Company’s use of the additional NED capacity would
occur on only a few peak days during the year (CLF Brief at 10-11).
Next, CLF argues that the Company made no real efforts to quantify the amount of
demand-side capacity or the cost of procuring energy efficiency, and did not issue any RFPs to
determine if energy efficiency or demand-response measures could reduce peak day and peak
season demands (CLF Brief at 11-12, citing Tr. 3, at 67, lines 17-23). CLF asserts that the
Company instead relied on its joint efforts with all electric and natural gas distribution
companies as evidence that it adequately considered energy efficiency as an alternative (CLF
Brief at 12, citing Exh. CLF-1, at 18). CLF contends that the Company’s reliance on the existing
three-year energy efficiency programs is misplaced because the cost-effectiveness analysis
required by the energy efficiency programs is far different from the energy efficiency analysis

D.P.U. 15-48 Page 22
required in the forecast and supply plan proceedings conducted pursuant to G.L. c. 164, § 69I
(CLF Brief at 12-13). CLF maintains that the Company’s participation in the three-year energy
efficiency programs does nothing to demonstrate that the Company considered demand-side
resources as an alternative to some or all of the anticipated capacity, and has failed to provide
any evidence that the alternative of energy efficiency is unavailable or more expensive than the
NED capacity (CLF Brief at 13).
In addition, CLF argues that the Company failed to provide evidence regarding climate
impacts and greenhouse gas emissions (CLF Brief at 14-15; CLF Reply Brief at 4). CLF asserts
that the GWSA requires the Department to consider reasonably foreseeable climate change
impacts and effects, including additional greenhouse gas emissions, when considering and
issuing permits, licenses, and other administrative approvals and decisions (CLF Brief at 5-6,
citing GWSA, § 7). CLF argues that the Department cannot approve the precedent agreement
without quantifying the potential greenhouse gas emissions and the impact that the additional
capacity will have on Massachusetts’ GWSA obligations (CLF Brief at 14-15). Moreover, CLF
contends that the Company has provided little more than an assumption that, to the extent the
additional capacity replaces fuel oil for space heating, it will provide a net greenhouse gas
reduction (CLF Brief at 15, citing Tr. 3, at 69-70). CLF maintains that the Company has not
provided any credible evidence on how much of the proposed additional capacity might actually
be used for converting heating oil customers to natural gas, rather than releasing it or selling it
for other uses -- all of which CLF argues will ultimately lead to greenhouse gas emissions (CLF
Brief at 15; CLF Reply Brief at 4). In addition, CLF maintains that the Company did not attempt
to quantify the greenhouse gas emissions that will result from the additional capacity not used for

D.P.U. 15-48 Page 23
heating oil conversions (CLF Reply Brief at 4). CLF further argues that the Company has not
addressed the consequences of converting customers to natural gas instead of low- or no-carbon
renewable thermal resources such as solar thermal heating, geothermal heating, or even LNG
(CLF Brief at 16).
Finally, CLF argues that although the Department cannot find that the precedent
agreement is consistent with the GWSA, the Department has the authority to condition its
approval to ensure consistency with the GWSA (CLF Brief at 16). CLF offers as an example a
climate change mitigation mechanism that could be used to fund energy efficiency measures so
as to offset increases in emissions and bring the precedent agreement into compliance with the
GWSA (CLF Brief at 16-17; CLF Reply Brief at 4). CLF contends that the mechanism would
enable the Company to consider energy efficiency on an equal basis with other resources, and
would require the Company either to procure energy efficiency in lieu of additional gas supplies,
or to develop one or more mechanisms to mitigate the greenhouse gas impacts from additional
supply (CLF Brief at 17-18).
D. PNGTS
PNGTS states that the Company spoke to PNGTS about PNGTS’s C2C expansion
project, but that the Company decided to enter into the NED project agreement instead (PNGTS
Brief at 4, citing RR-CLF-PNGTS-2). Nevertheless, PNGTS takes no position on whether the
Department should approve the precedent agreement (PNGTS Brief at 2, 4).
E. PLAN
PLAN argues that the Company has failed to provide sufficient evidence that the
precedent agreement is in the public interest (PLAN Brief at 4). First, PLAN alleges that

D.P.U. 15-48 Page 24
Berkshire’s commitment to the NED project is causing the Company to forgo additional gas
resources needed to meet the short-term requirements of Berkshire’s firm customers, and that the
NED project is not the solution to the Company’s current moratorium but, rather, is the cause of
it (PLAN Brief at 5). More specifically, PLAN maintains that because the Company was
pursuing the NED project, the Company was not pursuing other distribution system investments
and upstream pipeline expansions that could be in service prior to the NED project (PLAN Brief
at 5, citing Exh. AG 4-1).
Second, PLAN notes that the Company limited its consideration to only two conceptual
alternatives to the NED project, considered very limited analyses of real market alternatives, and
failed to consider other reasonable alternatives (PLAN Brief at 6, citing Exh. BGC-JMB-1,
at 16). According to PLAN, the Company appears to reject automatically any alternative that
would not by itself meet all the Company’s long-term supply and operational objectives (PLAN
Brief at 6). In addition, PLAN contends that Company failed to analyze other possible capacity
options, including the availability of PNGTS capacity and Spectra Energy’s Access Northeast
project (PLAN Brief at 6). PLAN argues that the Company’s proposal to rely entirely on NED
capacity is less flexible and entails greater risks to reliability and cost than would a supply plan
based on a more diverse set of resources (PLAN Brief at 6).
Finally, PLAN claims that the Company failed to adequately assess the risks and
uncertainties associated with pipeline connections to Wright, New York, or to appropriately
consider environmental and GWSA implications (PLAN Brief at 6-7). In sum, PLAN argues
that the Company has not demonstrated that it adequately considered that the proposed precedent

D.P.U. 15-48 Page 25
agreement represents the best and least-cost option given other possible alternatives and
associated risks (PLAN Brief at 7).15
F. NEES
NEES argues that the Department should disapprove the precedent agreement as
inconsistent with the public interest and with the Company’s portfolio objectives as reflected in
its most recent forecast and supply plan (NEES Brief at 4-5). NEES contends that the precedent
agreement fails to provide price and non-price advantages, is not the sole, practicable resource
available to Berkshire to address reliability concerns, and will not secure economic development
and environmental benefits (NEES Brief at 4-5).
More specifically, NEES argues that: (1) the Company has not properly evaluated
Tennessee’s open season opportunities or the expansion of alternatives available at Wright, New
York (NEES Brief at 5-6, citing Exh. BGC-JMB-1, at 15; Bay State Gas Company,
D.P.U. 15-39, Exh. CMA/MDA-1, at 45); (2) without the specific terms and arrangement for the
Supply Path portion of the NED project, the Department cannot accurately determine cost or
accurately forecast pricing (NEES Brief at 6-7, citing Exh. BGC-JMB-1, at 34-35); (3) the
Company has not provided any analysis of increased reliance on LNG as a viable alternative,
even though such analysis is mandatory to evaluate the cost-effectiveness of the precedent
15
PLAN also raises Department error in denying PLAN any meaningful right to intervene
and participate as a full party, in denying PLAN the opportunity to access confidential
materials, and in unnecessarily adopting an unreasonable and accelerated procedural
schedule (PLAN Brief at 2, 9-18). PLAN urges the Department to re-open hearings to
allow PLAN an opportunity to participate as a full intervenor, to sponsor a witness, and
to access the complete record (PLAN Brief at 18). As noted above, the Department
issued an Interlocutory Order upholding the hearing officer’s ruling that denied PLAN
full party status. Accordingly, PLAN’s arguments on these points are dismissed as moot.

D.P.U. 15-48 Page 26
agreement (NEES Brief at 7, citing Exhs. BGC-JMB-1, at 16; CLF-1, at 18-22); (4) the
Company has not provided sufficient information on how much incremental capacity would be
required to lift the current moratorium, the impact of the moratorium (or the lifting thereof) on
expected future demand, and the potential impact on the precedent agreement of Berkshire’s
acquisition by a third-party (NEES Brief at 7-8, citing Exh. BGC-JMB-1, at 6-7, Tr. 3, at 74-80);
(5) the Company did not consider PNGTS as an alternative supply source from Wright, New
York, and does not explain how the precedent agreement is superior (NEES Brief at 8, 10, citing
KN-1, at 1-13); (6) there has been no analysis in this proceeding to show that the NED project
will reduce electric rates across New England (NEES Brief at 8-9); and (7) no party sufficiently
or adequately attempted to evaluate the alternatives to the precedent agreement if the NED
project should not come on line, nor did they sufficiently or adequately investigate least-cost
alternatives (NEES Brief at 9, citing Bay State Gas Company, D.P.U. 15-39, Exh. CMA/MDA-1,
at 45). Based on the foregoing, NEES requests that the Department either disapprove the
precedent agreement or reopen the hearing for further review of these issues on its own motion,
in accordance with 220 C.M.R. § 1.11(8) (NEES Brief at 11).16
G. Berkshire Gas
The Company argues that the precedent agreement is consistent with the portfolio
objectives established in the Company’s forecast and supply plan, and compares favorably to the
range of available alternatives (Company Brief at 14, 16-17, 18-19; Company Reply Brief at 1).
First, the Company argues that the NED capacity is necessary to ensure the Company’s ability to
16
In its reply brief, NEES disputes the Company’s claim that the requested approval
deadline of September 1, 2015, is “mandated and mandatory,” and alleges that there is no
need for an expedited proceeding here (NEES Reply Brief at 1-3).

D.P.U. 15-48 Page 27
continue to serve existing customer load reliably at least cost, and to serve future customer
growth, including new customers, a large, special contract customer, and capacity-exempt
customers who return to default service (Company Brief at 2-4, 9). The Company contends that
it has identified a long-term need for substantial incremental resources under essentially all of the
Department’s planning standards, particularly for design years and design days (Company Brief
at 2, 7-8, citing Exh. BGC-JMB-1, at 5-6; Tr. 3, at 33; Company Reply Brief at 7). The
Company argues that it cannot meet this need with its current resources, as evidenced by the
moratorium, and that it must also address the planning challenges associated with
capacity-exempt customers’ migrating to default service (Company Brief at 2-4, 8; Company
Reply Brief at 1, 6-7). Thus, the Company maintains that the NED capacity is necessary to
address the Company’s operational and reliability concerns and remove the moratorium
(Company Brief at 2, 8, citing Exh. BGC-JMB-1, at 6, 17).
In addition, the Company states that it secured a tentative aggregate commitment of
36,000 Dth/day, but that the precedent agreement contains a “regulatory out” provision that
enables the Company to modify its capacity commitment based on the Department’s specific and
detailed findings (Company Brief at 3). Thus, the Company asks the Department to expressly
and specifically authorize the Company to execute the proposed agreements with a capacity
commitment of at least 28,000 Dth/day allocated as follows: (1) 20,000 Dth/day to serve the
Company’s planning load; (2) approximately 3,000 Dth/day for a large, special contract
customer seeking to expand its current gas use; and (3) at least 5,000 Dth/day to address the
reverse migration of capacity-exempt customers (Company Brief at 3-4, 20, citing

D.P.U. 15-48 Page 28
Exhs. BGC-JMB-1, at 11-12; DPU 1-5; DPU 1-9; Tr. 3, at 10-11, 14-15, 23-26; Company Reply
Brief at 1, 13).17
The Company states that it applied its established and well-accepted planning process to
establish a need for an incremental resource to meet peak, seasonal, and design-day planning
standards (Company Brief at 6-9, 13, 16-17, citing Exh. BGC-JMB-1, at 7-8; Tr. 3, at 28-29,
69-70; Company Reply Brief at 4, 7-8). In response to CLF’s argument that Berkshire is facing
only a design-day planning concern, the Company maintains that its base or conservative
forecast shows that incremental resources are required to meet an extensive range of planning
standards (Company Reply Brief at 7, citing CLF Brief at 11). Further, the Company argues that
the Attorney General is seeking to understate the Company’s forecast, and ignores that the
overall growth rate offered by the Company is consistent with recent history, reflects a base case
(versus high case), and does not reflect pent-up demand associated with the Company’s
moratorium or the expectation of lower prices from nearby production zones (Company Brief
at 7-8, citing Attorney General Brief at 5-6, 16-17; Exh. BGC-JMB-1, at 6, 17; Company Reply
Brief at 2, 7-8, citing DOER Brief at 4-5). Regarding arguments that the portfolio standards
from the Company’s recent forecast and supply plan have not yet been accepted in a final
decision or somehow may not fully support the precedent agreement, the Company states that
such portfolio standards may also be presented in the evidence submitted in this proceeding
(Company Reply Brief at 5-6, citing Attorney General Brief at 7; CLF Brief at 7;
17
Reverse migration includes and is indicative of the return of capacity-exempt customers
to default service.

D.P.U. 15-48 Page 29
The Company further asserts that the Attorney General is incorrect in arguing that the
Department does not have the statutory authority to address the migration of capacity-exempt
customers (Company Reply Brief at 6, citing Attorney General Brief at 11-13, G.L. c. 164,
§ 69I). While the Attorney General suggests that supply planning is limited to addressing the
requirements of projected firm customers, the Company maintains that migrating
capacity-exempt customers arguably become firm customers (Company Reply Brief at 6).
Moreover, the Company argues that it is inappropriate and unwise to ignore the impact that
actions by capacity-exempt customers can and would have on the Company’s ability to provide
safe and reliable service to firm customers (Company Reply Brief at 6). The Company further
argues that the Attorney General’s suggested approach would lead to irrational results, namely
that short-term or emergency remedies are permissible, while more effective, longer-term
options would be barred (Company Reply Brief at 6, citing D.P.U. 14-111).
The Company also maintains that this proceeding provides the G.L. c. 30A form of
adjudicatory proceeding that the Attorney General suggests is a prerequisite to implementing
company-specific planning decisions (Company Reply Brief at 6). According to the Company,
while an “industry” solution might, in fact, be preferable, the failure to approve the NED
precedent agreement will effectively limit, if not preclude, the Company from any meaningful
industry opportunity to address these same concerns (Company Reply Brief at 6-7).
As for the Attorney General’s recommendation regarding the Company’s energy
efficiency goals, the Company contends that its analysis properly assumed the continuation of its
existing programs -- an accurate and slightly conservative assumption -- and took into
consideration all load reductions associated with its energy efficiency programs (Company Brief

D.P.U. 15-48 Page 30
at 7-8; Company Reply Brief at 8). The Company further states that a more precise application
of the latest energy efficiency projections confirms the reasonableness of this assumption and
actually suggests a slightly larger need for NED capacity (Company Brief at 7-8; Company
Reply Brief at 8).
The Company maintains that there are no realistic or practical alternatives available to
provide a reliable, long-term solution to meet the Company’s identified needs (Company Brief
at 9-13; Company Reply Brief at 9). The Company states that it relies primarily on deliveries of
natural gas from Tennessee, the sole interstate pipeline to the Company, and from the
Northampton Lateral, a pipeline off of the Tennessee mainline that has no available capacity and
no current means for expansion (Company Brief at 6-7; Company Reply Brief at 4, citing The
Berkshire Gas Company, D.P.U. 10-60 (2010); The Berkshire Gas Company, EFSB 99-2
(1999)). Thus, the Company asserts that there are no meaningful pipeline alternatives that could
provide incremental capacity for delivery to the Company’s citygates or meet the Company’s
Eastern Division needs (Company Brief at 9 & n.9, citing Exh. BGC-JMB-1, at 15; Company
Reply Brief at 9-10, citing Tr. 3, at 58; CLF Brief at 10). The Company maintains that Dracut,
Massachusetts, is not a meaningful source given the Northampton Lateral constraint as well as
the lack of availability of Tennessee Zone 6 mainline deliverability (Company Reply Brief at 9).
The Company argues that the alternatives suggested by CLF, PLAN, and NEES are not valid or
relevant to the Company’s reliability analysis because those resources would not deliver to the
Company’s citygates, only to Dracut, Massachusetts, or elsewhere in the region (Company Reply
Brief at 9-11, citing Exhs. BGC-JMB-1, at 19; KN-1, at 13; Tr. 3, at 58, 78; CLF Brief at 10;
PLAN Brief at 6; NEES Brief at 6, 10). In response to PNGTS’s proposal of a Wright, New

D.P.U. 15-48 Page 31
York, to Dracut, Massachusetts route, the Company argues that it is not viable because the
Company does not seek delivered capacity to Dracut, other than to enhance its ability to secure
greater optimization benefits (Company Brief at 11, citing Exhs. BGC-JMB-1, at 19; KN-1,
at 13; Tr. 3, at 78).
The Company states that it engaged in some exploratory discussions regarding the
Atlantic Bridge project but quickly abandoned these discussions, and disputes PNGTS’s
assertion that it ever spoke with PNGTS regarding its C2C project (Company Brief at 9 n.9,
citing Exh. BGC-JMB-1, at 15; RR-CLF-PNGTS-1). Moreover, the Company explains that it
did not pursue a competitive solicitation to evaluate pipeline options because it would have
issued the request for proposals either to just one bidder or to several pipelines that would be
rejected for failing to meet a clear and necessary threshold requirement (Company Brief at 9, 16,
citing Exh. BGC-JMB-1, at 15; Company Reply Brief at 10-11).
The Company maintains that it identified but ultimately rejected two conceptual
alternatives because they presented cost and reliability concerns: (1) expanded reliance on
on-system peaking resources, such as LNG; and (2) long-term reliance on third-party, seasonal,
citygate-delivered resources (Company Brief at 9-12; citing Exhs. BGC-JMB-1, at 16; AG 3-19;
Tr. 3, at 68, 80; Company Reply Brief at 4, 11-12). Regarding expansion of the Company’s
on-system peaking resources, the Company states that this was not a feasible or prudent
alternative because it would place all customers at risk given the reliability and deliverability
concerns (Company Brief at 10, citing Exh. AG 3-19; Tr. 3, at 80; Company Reply Brief at 11).
The Company further notes that this alternative would be more expensive than accessing closer
production areas with supplies delivered by pipeline (Company Reply Brief at 11). In addition,

D.P.U. 15-48 Page 32
the Company points out that full expansion of the Company’s Whately facility would provide
only a fraction of the Company’s resource need (Company Brief at 10, citing Exh. AG 3-15;
Company Reply Brief at 11-12). The Company contends that CLF’s LNG-related proposals are
theoretical, flawed, and fail to address the Company’s identified needs (Company Brief at 11-13,
citing Exhs. AG 4-2; AG 4-3; CLF 2-5; CLF 3-2; Tr. 3, at 68; Company Reply Brief at 3, 11).
With regard to long-term reliance on third-party seasonal citygate deliveries, the
Company states that such resources are difficult to acquire, inflexible, and expensive (Company
Brief at 10; Company Reply Brief at 12). Therefore, the Company argues that overreliance on
this resource is not prudent in terms of reliability, and that it would not address the Company’s
range of needs other than as a short-term approach (Company Brief at 11, citing
Exh. BGC-JMB-1, at 16; Tr. 3, at 68; Company Reply Brief at 12).
The Company contends that the NED project (unlike the various conceptual alternatives)
also provides a number of other benefits (Company Brief at 13). With respect to price factors,
the Company argues that the proposed precedent agreement provides substantial customer
savings, as much as $9 million in 2023/2024 as a result of access to lower cost supplies
(Company Brief at 13, 17, citing Exhs. BGC-JMB-1, at 18-19; DPU 1-3; AG 2-1; AG 2-3;
AG 3-7; Tr. 3, at 35, 78). The Company explains that it secured the Dracut, Massachusetts path
because such access may enable the Company to further reduce costs though optimization
strategies (Company Brief at 13, citing Tr. 3, at 78).
With respect to non-price factors, the Company argues that the NED project will provide
substantial reliability benefits by adding a new gate station in the Eastern Division (Company
Brief at 14, citing Exh. BGC-JMB-1, at 20; Tr. 3, at 20). The Company further argues that the

D.P.U. 15-48 Page 33
NED project provides reliability enhancements through increased guaranteed delivery pressure
and the addition of a secondary feed to the Company’s Western Division (Company Brief at 14,
citing Exh. AG 3-15; Tr. 3, at 47). In addition, the Company states that the precedent agreement
will enable the Company to end its moratorium and add new customers to its Eastern Division,
with a possible reduction in per customer distribution costs (Company Brief at 14, 18, citing
Further, the Company argues that the precedent agreement will facilitate the goals of the
GWSA by enabling the Company to serve new customers converting from oil heating to natural
gas (Company Brief at 18; Company Reply Brief at 12). The Company notes that the
Department previously found evidence in the AIM precedent agreement proceedings that the
additional capacity would be used to serve mostly new customers converting from oil heating to
natural gas, and determined that this was adequate to show consistency with the GWSA
(Company Brief at 18, citing D.P.U. 13-159, at 23). The Company maintains that, in this case,
there is evidence that virtually all historic and potential conversions are from more expensive,
higher-emission oil use, and thus the Department should find that the proposed agreements are
consistent with the GWSA (Company Brief at 18, citing Tr. 3, at 28-29, 62, 69-70).
The Company also contends that the Department should reject CLF’s proposed
mitigation charge rate proposal because it is a recycled version of a previously rejected proposal
(Company Brief at 18 n.12; Company Reply Brief at 12). In addition, the Company argues that
CLF has offered no additional support to overcome the proposal’s failure to properly address
cost recovery, failure to comply with the requirements of G.L. c. 164, § 94, and likely unintended

D.P.U. 15-48 Page 34
effect of increasing emissions as a result of higher natural gas prices (Company Brief at 18 n.12,
citing D.P.U. 13-159, at 24-25; Company Reply Brief at 12).
The Company maintains that any theoretical, future, alternative pipeline project would be
rare, would most likely not offer such favorable terms, and would probably not enable Berkshire
to negotiate favorable terms or comparable anchor shipper status (Company Brief at 2-3, 13).
According to the Company, the NED project is unique in that it crosses the Company’s service
area (thus avoiding the need for reliance on the constrained Northampton Lateral), enhances
reliability by doubling the Company’s primary feeds, and eliminates the need for distribution
system enhancements otherwise necessary to maintain operating pressures in the northern
portions of the Company’s Eastern Division (Company Reply Brief at 10). Moreover, the
Company contends that the failure of the NED project could mean no incremental capacity
opportunity for delivery to the Company’s service area for decades (Company Brief at 13, citing
Exh. BGC-JMB-1, at 9). Therefore, the Company argues that the NED project represents the
most viable, reasonably available alternative for the Company to meet the current and forecast
customer requirements in a least-cost, reliable manner (Company Brief at 14).
V. ANALYSIS AND FINDINGS
A. Introduction
The Department must evaluate whether the proposed acquisition is consistent with the
public interest. Section 94A; D.P.U. 94-174-A at 27. To make this determination, the
Department considers whether the acquisition is consistent with the Company’s portfolio
objectives and compares favorably to the range of alternative options reasonably available to the
Company at the time of the acquisition or contract negotiations. D.P.U. 94-174-A at 27. Then,

D.P.U. 15-48 Page 35
the Department will consider the consistency of the proposed acquisition with the GWSA. As an
initial matter, however, the Department will address the Company’s motion to reopen the record
(“Motion”).
B. Company’s Motion to Reopen the Record
1. Background
On August 17, 2015, the Company filed a Motion to introduce into evidence an
amendment to the precedent agreement (“Amendment 3”).18
Amendment 3 provides that:
[A]s a result of certain changes to the routing of the Market Path facilities of
Tennessee’s Northeast Energy Direct Project, Tennessee will not be able to
provide Berkshire with primary delivery rights at the Dalton Delivery Meter.
Specifically, Amendment 3 revises the precedent agreement by revising the gate station
allocations to account for elimination of a proposed gate station, the Dalton meter station, in the
Western Division (Exhs. DPU 3-2; AG 6-4(e)).19
In its Motion, the Company states that Amendment 3 was described in substantial detail
during the evidentiary record, and that the information therein was fully reviewed and considered
during cross-examination (Motion at 2). In addition, the Company states that Amendment 3 is
related to an issue that is arguably material to the proceeding, but that it has no effect on the
18
The Company had initially provided Amendment 3 to the Department and the parties by
letter dated August 13, 2015, without the corresponding motion or explanation for the
changes. To be consistent with Department regulations, the Company refiled
Amendment 3 with the Motion on August 17, 2015.
19
Amendment 3 contains a reference to a previous amendment to the precedent agreement,
Amendment 2, which provided a ministerial change of a date in accordance with the
dates changed in Amendment 1 (which accompanied the initial filing) (Exh. DPU 3-2).
We note that the Company has not sought to reopen the record to admit Amendment 2
into evidence, and because of the nature of Amendment 2, we do not consider it
necessary to our review of the precedent agreement (Exh. DPU 3-2).

D.P.U. 15-48 Page 36
merits or substance of the Company’s petition and should not affect the outcome of the case
(Motion at 1). Further, the Company argues that its primary purpose in submitting Amendment
3 was to demonstrate the completion of a process described within the evidentiary record
(Motion at 1). Thus, the Company contends that good cause exists to allow Amendment 3 into
the record because it may be relevant to the Company’s petition and was previously unavailable
or undisclosed to the Company (Motion at 1, 2). In the alternative, if Amendment 3 is not
viewed as necessary, the Company requests that the amendment be considered as merely
informational and not part of the evidentiary record (Motion at 1).
The Department provided the parties an opportunity to respond to the Motion and
comment on Amendment 3. The Attorney General and CLF provided comments, to which the
Company responded, and the Company responded to limited discovery.20
1. Positions of the Parties
In her comments, the Attorney General argues that Amendment 3 presents new evidence
regarding meter total quantities, which may require the construction of new facilities and incur
additional costs (Attorney General Comments at 2). The Attorney General contends that the
Company cannot construct new facilities unless they are consistent with the Company’s most
recently approved forecast and supply plan (Attorney General Comments at 3, citing G.L. c. 164,
§ 69J). Moreover, the Attorney General argues that the Company submitted no cost data
regarding Amendment 3, nor any information on the impact that this change in capacity
allocation will have on the Company’s plan to use the NED project to lift its moratorium
20
Pursuant to 220 C.M.R. § 1.10, the Department on its own motion moves into the
evidentiary record the following information requests: DPU 3-1 through DPU 3-2;
AG 6-1 through AG 6-5; and DOER 1-1 through DOER 1-2.

D.P.U. 15-48 Page 37
(Attorney General Comments at 3). The Attorney General also argued that Amendment 3
referred to a previous amendment executed on June 23, 2015, Amendment 2, which does not
appear on the record in this proceeding, and that Amendment 3 requires a sworn affidavit from a
Company witness (Attorney General Comments at 2, 3-4). The Attorney General asserts that the
Department should require the Company to supplement its Motion to address these latter
two issues (Attorney General Comments at 3-4).
In its comments, CLF states that Amendment 3 implicates the portfolio objectives portion
of the standard of review, but that CLF would require discovery to comment further (CLF
Comments at 1).21
In its responsive comments, the Company states that it committed to submit a necessary
amendment to the precedent agreement during the hearing, and that the need for and content of
the amendment were the subject of detailed cross-examination without any reservation of rights
for further review (Company Response at 1, citing Tr. 3, at 30; RR-CLF-1). The Company
contends that Amendment 3 makes very minor adjustments to gate station allocations
necessitated by a pipeline route change, and that the Attorney General’s and CLF’s comments
rely on erroneous and misplaced arguments seeking additional process in this proceeding, which
the Department should disregard (Company Response at 1). First, the Company argues that the
Attorney General is incorrect that Amendment 3 may somehow trigger the need for
“jurisdictional” facilities because the testimony indicated that only a gate metering station would
be required, which is not a jurisdictional facility implicating G.L. c. 164, § 69J (Company
21
Both the Attorney General and CLF requested further discovery regarding what, if any,
effect Amendment 3 would have on the merits of the Company’s petition.

D.P.U. 15-48 Page 38
Response at 1).22
Second, the Company points out that the amendment makes no change to
capacity allocation for the new gate station in the Eastern Division, no change to the total
capacity to be delivered to the Western Division, and thus no change to the Company’s effective
ability to serve customers other than a beneficial route change (Company Response at 1, citing
Tr. 3, at 40). Finally, the Company contends that there is no need for an affidavit given the
Company’s testimony and prior record request response, and no need for further discovery or
process given the Company’s submission of the amendment pursuant to a commitment made
during testimony after a full opportunity for cross-examination (Company Response at 1-2).
2. Standard of Review
The Department’s Procedural Rule on reopening hearings, 220 C.M.R. § 1.11(8), states,
in pertinent part, “[n]o person may present additional evidence after having rested nor may any
hearing be reopened after having been closed, except upon motion and showing of good cause.”
Good cause for purposes of reopening has been defined as a showing that the proponent has
previously unknown or undisclosed information regarding a material issue that would be likely
to have a significant impact on the decision. Machise v. New England Telephone and Telegraph
Company, D.P.U. 87-AD-12-B at 4-7 (1990); Boston Gas Company, D.P.U. 88-67 (Phase II) at 7
(1989); Tennessee Gas Pipeline Company, D.P.U. 85-207-A at 11-12 (1986).
3. Analysis and Findings
The Department must afford all parties an opportunity for a full and fair hearing.
G.L. c. 30A, § 10. Every party has the right to call and examine witnesses, to introduce exhibits,
22
The Company later clarified that the gate station to which it refers is the one to be
constructed in the Eastern Division, and is unaffected by the route change to which
Amendment 3 pertains (Exhs. DPU 3-1; DPU 3-2; AG 6-2).

D.P.U. 15-48 Page 39
and to cross-examine witnesses who testify or sponsor exhibits. G.L. c. 30A, § 11(3). As a
general rule, once evidentiary hearings are completed, additional information may not be entered
into evidence. See 220 C.M.R. § 1.11(8). To permit additional evidence after the close of
hearings, absent a showing of good cause and without adequate procedural due process, would
deprive parties of their right to a full and fair hearing. See G.L. c. 30A, § 10; 220 C.M.R.
§ 1.11(8).
In limited circumstances, such as rate case proceedings, the Department has allowed
companies to supplement certain evidence after the close of the hearings where such evidence is
noncontroversial, such as routine, anticipated, and verifiable adjustments. See, e.g.,
Massachusetts Electric Company/Nantucket Electric Company, D.P.U. 09-39-A at 26-27 (2010).
For example, the Department has allowed companies to provide supplemental evidence after the
close of the rate case hearings on (1) property tax, (2) rate case expense, and (3) inflation.
D.P.U. 13-90-A at 27 n.12. The Department has determined that it is appropriate to permit such
updates because they are based on information external to a company and almost entirely outside
the control of the company. D.P.U. 13-90-A at 27.
In this case, the Company has filed an amendment to the precedent agreement,
Amendment 3, and has also submitted a motion to reopen the record to admit this item. The
changes noted in Amendment 3 were thoroughly discussed during the proceeding, the
amendment itself was anticipated, and the timing of it was arguably beyond the Company’s
control (Tr. 3, at 38-40, 46-48, 52-53; RR-CLF-1). In addition, Amendment 3 is
non-controversial because it does not raise any cost implications (Exhs. DPU 3-1; AG 6-2;
AG 6-4(e)). While the Attorney General suggests that the capacity reallocation “may require the

D.P.U. 15-48 Page 40
construction of new facilities and incur additional costs,” the evidence demonstrates that
Amendment 3 does not require any infrastructure improvements and, therefore, will not lead to
any additional costs (Exhs. AG 6-2; AG 6-4(e)). Most importantly, Amendment 3 does not
affect our review of whether the acquisition of NED capacity is consistent with the public
interest because the amendment simply revises the gate station allocations to account for
elimination of the Dalton meter station, and does not alter the Company’s resource commitment
or how the NED capacity compares to the available alternatives (Exhs. DPU 3-2; AG 6-4(e)).
Therefore, pursuant to our standard for reopening the record, we find that the Company
has not shown that Amendment 3 concerns a material issue that would be likely to have a
significant impact on the decision. Rather, upon review of the Company’s discovery responses,
we find that it is more appropriate to treat Amendment 3 as consistent with the Company’s
ongoing obligation to update the record (see Tr. 3, at 38-40, 46-48, 52-53; RR-CLF-1).
Accordingly, based on the nature of the amendment -- and with guidance from our rate case
procedures where we allow in certain anticipated, noncontroversial information after the record
has closed -- we will allow Amendment 3 into the record as an update to the testimony
concerning changes to the gate station allocations and as a supplement to the related record
request (Tr. 3, at 38-40, 46-48, 52-53; RR-CLF-1). Based on this determination, we do not
require the Company to provide a supporting affidavit.
C. Consistency with the Public Interest
1. Consistency with Portfolio Objectives
In establishing that the acquisition of a resource is consistent with a company’s portfolio
objectives, a company may refer to portfolio objectives established in a recently approved

D.P.U. 15-48 Page 41
forecast and supply plan or in a recent review of supply contracts under Section 94A, or may
describe its objectives in the filing accompanying the proposed resource. D.P.U. 94-174-A
at 27-28. In the instant proceeding, the Company argues that acquisition of the NED capacity
will contribute to a least-cost resource portfolio consistent with the Company’s portfolio
objectives (Company Brief at 14, 16-17). The Company analyzed its need for incremental
resources using its established forecast and supply planning process (Exh. BGC-JMB-1, at 4-6).
The Company updated its forecast and supply plan filed in D.P.U. 14-98 to cover a ten-year
planning period, rather than the usual five-year planning horizon, then included in its planning
load the expanded requirements of a special contract customer and the forecast demand load of
capacity-exempt customers returning to default service (Exhs. BGC-JMB-1, at 11-12 & Att. (c);
DPU 1-5, Att.). Based on this analysis, the Company determined a long-term need for
substantial additional capacity under essentially all of the Department’s planning standards
(Exhs. BGC-JMB-1, at 5-6, 11-12 & Att. (c); DPU 1-5, Att.).
The Attorney General challenges the Company’s reliance on its forecast and supply plan
in D.P.U. 14-98 because that plan had not yet been approved by the Department when the
Company filed this petition (Attorney General Brief at 9). We find no cause for concern. When
the Company filed this petition on April 21, 2015, the evidentiary record in D.P.U. 14-98 was
complete and only the briefs remained to be filed. Notably, no other party, including the
Attorney General, filed a brief challenging the Company’s forecast or the methods employed.
D.P.U. 14-98, at 2. Moreover, as noted above, the Department has since approved the
Company’s five-year forecast and supply plan in D.P.U. 14-98, finding the Company’s
forecasting method reviewable, appropriate, and reliable, and finding that the forecast meets the

D.P.U. 15-48 Page 42
G.L. c. 164, § 69I requirements. D.P.U. 14-98, at 14-15. Further, the Department found that the
Company had formulated an appropriate process for identifying a comprehensive array of supply
options, and had developed appropriate criteria for screening and comparing resources on an
equal basis. D.P.U. 14-98, at 29-30. In addition, requiring the Company to rely on an approved
but outdated forecast would not be prudent. In the previously approved forecast, D.P.U. 12-62,
the Department found that Berkshire had adequate supplies to meet its sendout requirements, but
in D.P.U. 14-98, the Company projected significant shortfalls in design-day, design-year, and
cold-snap planning standards. D.P.U. 14-98, at 28-30; D.P.U. 12-62, at 41. In sum, we conclude
that the Company’s decision to rely on its D.P.U. 14-98 forecast was reasonable and appropriate
in this proceeding
Next, the Attorney General argues that the Company’s forecast capacity needs are
overstated and urges the Department to require the Company to apply a growth rate based on the
most recent two years of the forecast period (Attorney General Brief at 10). The Company based
its 2.38 percent average annual growth rate on the recently approved five-year forecast and
supply plan, and it is consistent with the Company’s historical growth rate (Exhs. BGC-JMB-1,
at 11 & Att. (c); DPU 1-5, at 1; Tr. 3, at 11-13). In fact, the Company has not only exceeded the
historical growth rate recently, with higher base-case demand in 2014/2015, but the Company’s
forecast also reflects a more conservative base-case scenario even though recent trends are more
aligned with the high-case scenario (Tr. 3, at 11-13). Furthermore, we agree with DOER and the
Company that the current Eastern Division moratorium is likely causing pent-up demand that
could be served by the NED project (DOER Brief at 5; Company Brief at 8; Exh. BGC-JMB-1,

D.P.U. 15-48 Page 43
at 6-7, 17; Tr. 3, at 79). Under these circumstances, we find the Company’s use of the
2.38 percent growth rate to be reasonable.
Additionally, the Attorney General argues that the Company has not proven the need for
an incremental capacity need of 20,000 Dth/day, arguing that the difference between the
2014/2015 demand and the 2023/2024 demand is only 13,384 Dth/day (Attorney General Brief
at 9). We disagree with the Attorney General’s logic. The record clearly shows that the forecast
2023/2024 design-day demand is 70,120 Dth/day, but the resources available to meet that
demand amount to only 51,206 Dth/day, or a shortfall of 18,914 Dth/day (Exh. DPU 1-5, Att.;
see also Exh. AG 2-2, Att. (b)). Moreover, this incremental capacity need incorporates an offset
of 4,247 Dth/day from the Company’s energy efficiency savings (Exh. DPU 1-5, Att.). In sum,
we find that the Company has demonstrated the need for 20,000 Dth/day of incremental capacity.
Further, we disagree with the Attorney General’s and CLF’s opposition to including the
expected load for capacity-exempt customers in the planning load (Attorney General Brief
at 11-13; CLF Reply Brief at 2-3). First, in the Department’s Emergency Authorization for Gas
Capacity Planning proceeding, D.P.U. 14-111, the Department authorized the LDCs to plan for a
portion of the Winter 2014/2015 gas supply requirements of capacity-exempt customers
migrating to default service, finding that negative impacts could occur if the LDCs were not
prepared to serve these customers. D.P.U. 14-111, at 15. The Department is currently reviewing
another request by the LDCs to plan and procure short-term resources to address the reverse
migration of capacity-exempt customers in Winter 2015/2016 (docketed as Gas Capacity
Planning for Winter 2015/2016, D.P.U. 15-43).

D.P.U. 15-48 Page 44
Second, the Attorney General and CLF are incorrect that G.L. c. 164, § 69I, precludes the
Company from including the capacity-exempt requirements in its planning load (Attorney
General Brief at 11-12; CLF Reply Brief at 2-3). The Company has projected that a number of
capacity-exempt customers will return to default service over the planning period
(Exhs. BGC-JMB-1, at 12; Tr. 3, at 24-25). See D.P.U. 15-43; D.P.U. 14-111. Once those
customers return to default service, they become firm, capacity-eligible customers for planning
purposes, pursuant to the applicable tariff. D.P.U. 14-111, at 6. Where G.L. c. 164, § 69I, states
that the forecast of gas requirements shall consist of the gas sendout necessary to serve projected
firm customers, the Company properly included the anticipated load of those customers in its
planning load as projected firm customers, consistent with G.L. c. 164, § 69I.
Third, the Department is acutely aware that pipeline capacity is not always available in
increments that match precisely with a company’s load growth. If it were, the Northeast region
would not have the shortfalls in pipeline availability that it has experienced recently. See
D.P.U. 14-111, at 15. Moreover, when an LDC is entering into a capacity agreement, it
behooves the LDC to acquire the capacity necessary to serve not only its current load but also
potential future load, consistent with G.L. c. 164, § 69I. The Department finds that the
Company’s inclusion of capacity-exempt load in the updated forecast is appropriate. Indeed, we
agree with DOER that the Company’s anticipated migration of capacity-exempt load represents a
prudent planning process intended to alleviate reliability concerns (DOER Brief at 7).
We also disagree with the Attorney General’s contention that the Company’s projection
regarding its expected capacity-exempt load is faulty because it is based on a short-term trend
and assumes that all capacity-exempt customers experience the same maximum daily

D.P.U. 15-48 Page 45
requirements at the same time. Reverse migration has occurred in the region for several years
now and is likely to continue (Exhs. BGC-JMB-1, at 12; AG 2-1, Att.; AG 2-5, Att.; Tr. 3, at 20,
23-25; RR-AG-1, Att.). See D.P.U. 14-111, at 3-4, 15; see also D.P.U. 15-43. Moreover, the
reverse migration trend has recently accelerated because of natural gas pricing dynamics arising
from constrained pipeline capacity (Tr. 2, at 84). Bay State Gas Company, D.P.U. 15-39, at 34
(August 31, 2015). Thus, the Company is not relying on a short-term trend.
With regard to the Company’s assumptions about capacity-exempt customers’ maximum
daily requirements, we find that the Company used the most reliable information available to
make these estimations, used an appropriate projection method, and properly supported its
proposal to plan for these customers with data and testimony (Exhs. BGC-JMB-1, at 12; AG 2-1,
Att.; AG 2-5, Att.; Tr. 3, at 20, 23-25; RR-AG-1, Att.). We further find that the Company has
reduced its planning load for capacity-exempt customer migration from 10,000 Dth/day to
5,000 Dth/day, and that this amount is adequately supported by the record (Exhs. BGC-JMB-1,
at 12; AG 2-1, Att.; AG 2-5, Att.; Tr. 3, at 20, 23-25; RR-AG-1, Att.). Therefore, based on the
foregoing, we find that the Company properly updated its now-approved forecast and supply
plan submitted in D.P.U. 14-98 to determine its ten-year planning load, and find that the
proposed acquisition is consistent overall with the Company’s portfolio objectives.23
2. Comparison to Alternatives
The Section 94A public interest standard also requires the Company to demonstrate that
the proposed acquisition compares favorably to the range of alternative options reasonably
23
We further note that the Company has appropriately reduced the estimated need of a
large, special contract customer from 6,000 Dth/day to approximately 3,000 Dth/day
(Exh. BGC-JMB-1, at 11-12; Company Brief at 3-4).

D.P.U. 15-48 Page 46
available to the Company at the time of the acquisition. D.P.U. 94-174-A at 27. In evaluating
this aspect of the proposed acquisition, the Department considers whether the Company used a
competitive solicitation process that was fair, open and transparent. D.T.E. 02-56, at 10;
D.T.E. 02-52, at 8-9; D.T.E. 02-54, at 9-10; D.T.E. 02-19, at 6, 11. The record shows that
Berkshire could not identify any other pipeline resources before negotiating the precedent
agreement, although it engaged in exploratory discussions with Algonquin regarding the Atlantic
Bridge project,24
and did not conduct a competitive solicitation because there were no other
pipelines that could deliver to the Company’s citygates or address the Company’s need to
increase deliverability to the Eastern Division (Exh. BGC-JMB-1, at 7, 9, 15; Tr. 3, at 56-58, 67,
68). Thus, we do not consider the lack of a competitive solicitation process to be fatal to the
Company’s petition as there would have been only one respondent who could meet the
Company’s needs.
In addition to the pipeline alternatives, the Company identified two conceptual
alternatives: the expansion of on-system peaking resources; and long-term reliance on
third-party, seasonal, citygate-delivered resources (Exh. BGC-JMB-1, at 16; Tr. 3, at 80). Based
on the record, the Company appropriately concluded that these were not viable alternatives to
serve the Company’s needs because of cost and reliability issues (Exh. BGC-JMB-1, at 16; Tr. 3,
at 68, 80). First, the evidence shows that an increased use of on-system peaking resources could
not meet the Company’s identified design-day needs even with improvements to its LNG/LP
facilities (Exhs. BGC-JMB-1, at 16; AG 3-15; AG 3-19). Moreover, where full expansion of the
24
Although PNGTS says otherwise, the Company disputes that it spoke to PNGTS about its
C2C expansion project (see Company Brief at 9 n.9; PNGTS Brief at 4).

D.P.U. 15-48 Page 47
Company’s Whately storage facility would provide only a fraction of the Company’s resource
need, we do not see the need for an evaluation of the cost-benefit analysis regarding expansion of
this facility, as the Attorney General suggests (Exhs. AG 3-15; CLF 5-7). Second, an
over-reliance on system peaking would lead to operational considerations such as gas-mixing
constraints, product and trucking availability, and reliance on mechanical facilities that affect
reliability (Exh. BGC-JMB-1, at 16; Tr. 3, at 80, 83, 84-85). Third, LNG costs are more
expensive and subject to price volatility (Exh. BGC-JMB-1, at 16). Fourth, reliance on
deliveries of LNG from tankers from around the world in lieu of the NED capacity, as CLF
suggests, would disregard safety, scheduling restrictions, and reliability concerns (see Tr. 2,
at 82). Fifth, the Company cannot prudently rely on third-party, seasonal, citygate-delivered
resources to serve more than 25 percent of the Company’s long-term design-day requirements
because these resources are increasingly difficult to acquire, offer limited flexibility, and
command substantial premiums on the secondary market (Exh. BGC-JMB-1, at 16). Thus, we
find that the Company appropriately considered the logistics, safety, reliability, and flexibility
associated with these options and properly concluded that they were not viable alternatives to the
NED project. We further find that the alternatives suggested by the other parties would not meet
the Company’s needs, would not deliver to the Company’s citygates, or would present
significant reliability, deliverability, cost, and environmental issues (Exhs. BGC-JMB-1, at 15;
AG 4-2; AG 4-3; CLF 2-5; CLF 3-2; KN-1, at 13; Tr. 3, at 56-58).
The Company also considered energy efficiency in determining its load requirements. In
Three-Year Energy Efficiency Plan for 2013 through 2015, D.P.U. 12-100 through
D.P.U. 12-111, at 161 (2013), the Department found that the energy savings expected to be

D.P.U. 15-48 Page 48
generated through the Company’s energy efficiency programs are consistent with the
achievement of all available cost-effective energy efficiency. Once these energy efficiency
savings are netted out from the demand side, there is no requirement that the Company model
energy efficiency as a supply resource because there are no Department-approved energy
efficiency or demand reduction measures on which the Company can rely to meet its design-day
or design-season requirements. D.P.U. 13-157, at 23. Although savings from gas energy
efficiency programs are reliable and verifiable, unlike gas supply resources, gas energy
efficiency and demand-response resources are not dispatchable resources on which LDCs can
rely to meet design-day or design-season demand. D.P.U. 13-157, at 23. In this case, the
Company appropriately took into account energy efficiency by adjusting its forecast to include a
load reduction based on energy efficiency (Exhs. BGC-JMB-1, at 5-6; DPU 1-5, at 1 & Att.).
This approach is consistent with the approach approved in the AIM precedent agreement cases.
See, e.g., D.P.U. 13-157, at 23. Thus, we disagree with CLF’s claim that the Company relied
solely on its existing energy efficiency programs and did not consider energy efficiency in
determining load requirements. In addition, while the Attorney General recommends that the
Company update its energy efficiency forecast, we note that the Company’s 2016-2018 energy
efficiency savings goals are not yet finalized and will not be filed with the Department until
October 31, 2015 (Attorney General Brief at 3, 17). G.L. c. 25, § 21. The Department therefore
finds that the Company appropriately considered energy efficiency measures consistent with
Department policy.
Further, the Company considered both price and non-price factors in support of the
precedent agreement. With respect to price factors, the precedent agreement provides that the

D.P.U. 15-48 Page 49
initial negotiated reservation rate is subject to cost adjustments and cost caps (Exh. BGC/JMB-1,
at 12-13). Moreover, the Company has shown that access to lower-cost supplies will allow
customers to achieve commodity cost savings, estimated to be $2 million in 2018/2019,
increasing annually to $9 million in 2023/2024 (Exh. BGC-JMB-1, at 18-19; Tr. 3, at 78). We
disagree with the Attorney General that these estimated cost savings are unreliable or otherwise
flawed (Attorney General Brief at 3, 18). The Company explained that these savings are a result
of: (1) access to lower-cost supplies; (2) reduced reliance on citygate-delivered supplies; and
(3) a reduction in the use of higher-priced on-system LNG and LP resources (Exhs. BGC-JMB-1,
at 19; DPU 1-3). In particular, the Company used its SENDOUT®
model (an analytical software
tool in the portfolio design process) to evaluate its portfolio with and without the NED project
(Exhs. BGC-JMB-1, at 18-19 & Att. (c); DPU 1-5, Att.). Because there are no published price or
forward indices for the Wright, New York receipt point, the Company relied on pricing
indications developed by an LDC consortium of regional gas supply experts, and refined the
pricing methodology by converting seasonal basis indices into monthly pricing (Exhs. AG 2-3;
AG 4-4; Tr. 3, at 36). This estimate approximates the delivered cost of Marcellus Shale supplies
to Wright, and thus we find it a reasonable proxy. Moreover, the Company may be able to
reduce costs further through optimization strategies (Exh. BGC-JMB-1 at 19; Tr. 3, at 78). Thus,
based on the evidence presented, we find that the Company has shown that the supplies
accessible from the NED project will be the Company’s most economic source of supply.
Regarding non-price factors -- in particular, reliability -- the NED project will provide
increased guaranteed delivery pressure at existing delivery points, a new gate station in the
Company’s Eastern Division, and a secondary feed to the Company’s Western Division

Mass. Dept. of Public Utilities Ruling to Allow Berkshire Gas to Purchase Natural Gas from Proposed Tennessee Gas Pipeline

Mass. Dept. of Public Utilities Ruling to Allow Berkshire Gas to Purchase Natural Gas from Proposed Tennessee Gas Pipeline

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Mass. Dept. of Public Utilities Ruling to Allow Berkshire Gas to Purchase Natural Gas from Proposed Tennessee Gas Pipeline