mass. dept. of public utilities ruling to allow berkshire gas to purchase natural gas from proposed...

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.

http://www.masslive.com/news/index.ssf/2015/07/kinder_morgan_to_scale_back_ca.html

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

D.P.U. 15-48 Page 50

(Exhs. BGC-JMB-1, at 20; AG 3-15; Tr. 3, at 47). The Attorney General questioned the need for

increased minimum delivery pressure (Attorney General Brief at 19). We note, however, that as

growth on the Company’s system increases, the increased minimum delivery pressure will

enable the Company to serve all its customers more reliably. In addition, the NED project will

enable the Company to end the moratorium and add new customers in its Eastern Division --

possibly reducing customer distribution costs -- and avoid a moratorium in its Western Division

(Exhs. BGC-JMB-1, at 17, 21; CLF 2-4; CLF 2-5; Tr. 3, at 74-75, 79).25

In addition to the reliability benefits, the NED project will enhance the Company’s

flexibility and add diversity to the Company’s existing resource portfolio (Exh. BGC-JMB-1,

at 20). We disagree with the Attorney General’s conclusion that the proposed agreement does

not provide diversity of supply (Attorney General Brief at 18-19). Rather, we find that the

Company appropriately concluded that the NED project is the best choice on the basis of

reliability, flexibility, and diversity. Further, the Company decided to pursue the Supply Path

segment of the NED project to increase liquidity at Wright New York (Tr. 3, at 34-36). The

existence of the Constitution Pipeline at Wright combined with the Supply Path segment of the

NED project clearly indicates that the Wright, New York location can become a hub with

reliable, flexible, and diverse resources (Exhs. DPU 2-1; CLF 3-10; AG 2-3). Thus, the

proposed agreement will provide the Company with the opportunity to access a diversity of

25

As for PLAN’s assertion that the Company pursued the NED project in lieu of seeking

other resources to meet its short-term requirements, PLAN has offered no evidence to

support this assertion, and this proceeding is focused on whether the NED project is

appropriate to meet the Company’s long-term requirements. Moreover, we note that the

Company has taken numerous steps in an attempt to alleviate its short-term requirements

(Exh. BGC-JMB-1, at 7-8; Tr. 3, at 74).

D.P.U. 15-48 Page 51

supply. Moreover, the Department sees no need to review the Market Path precedent agreement

in conjunction with the Supply Path precedent agreement, particularly where the Company has

not yet filed a Supply Path precedent agreement with the Department. Further, without the NED

project, the Company might not have an opportunity for incremental capacity to be delivered to

the Company’s service area for decades, or on such beneficial terms (Exhs. BGC-JMB-1, at 9,

10, 17; Tr. 3, at 82).26

Therefore, the Company has established that, based on both price and non-price factors,

the NED project represents the most viable alternative reasonably available for the Company to

meet its long-term demand requirements in a least-cost, reliable manner. Based on the

foregoing, we find that the Company has shown that the proposed acquisition compares

favorably to the range of reasonably available alternative options.

D. GWSA Considerations

CLF argues that the Department should reject the Company’s petition because it is not

consistent with the GWSA, alleging that the Company failed to provide evidence regarding the

climate impacts and effects of the precedent agreement (CLF Brief at 14-15). According to CLF,

the Company did not provide credible evidence regarding how much of the additional capacity

might be used to convert heating oil customers to natural gas, and failed to address the

consequences of moving more customers to gas consumption versus using low- or no-carbon

renewable thermal resources or LNG (CLF Brief at 15-16).

26

Regarding NEES’s concern that there has been no analysis regarding the reduction of

electric rates across New England, the issue is not before us in this proceeding. In

addition, NEES’s concern regarding the impact on the precedent agreement of the

Company’s acquisition by a third party is not relevant to our review. As such, the

Department declines to address those concerns here.

D.P.U. 15-48 Page 52

CLF argues that the GWSA requires the Department in its Section 94A review of the

precedent agreement to analyze “potential greenhouse gas impacts” and prohibits the Department

from approving the precedent agreement unless the Department finds it consistent with the

GWSA’s mandates to reduce greenhouse gas emissions (CLF Brief at 5-6). Regardless of

whether the GWSA requires such a review or outcome,27

in this case, the Department considers

as a factor in its public interest review whether the Company has provided adequate evidence of

the precedent agreement’s consistency with the GWSA. D.P.U. 13-157, at 24.

The record evidence indicates that the additional capacity will be used, in large part, to

serve new customers converting from oil heating to natural gas, and therefore the Department

expects that the acquisition of the proposed capacity will further reduce greenhouse gas

emissions and contribute towards GWSA goals (Exh. DPU 1-5; Tr. 3, at 17, 28-29, 62-63, 68-70,

77).28

Based on the foregoing, the Department finds that the Company has provided adequate

evidence regarding the precedent agreement’s consistency with the GWSA.

27

See, e.g., In the Matter of Palmer Renewable Energy LLC, Final Decision, OADR

Docket No. 2011-021 & -022, at 1, n. 1 (September 11, 2012) (commissioner did not

ratify or reject presiding officer’s recommended final decision after remand that GWSA

Section 7 does not obligate MassDEP to consider reasonably foreseeable climate change

impacts when considering and issuing permits that do not trigger MEPA), appeal

pending, Ten Residents of the Commonwealth v. Department of Environmental

Protection, Hampden County Superior Court Department, Docket No. 1279CV00833,

Civil Action No. 12-833; Notice of Solicitation of Amicus Briefs, Conservation Law

Foundation v. Energy Facilities Siting Board, No. SJC-11600 (regarding agency’s

obligations under the GWSA in approving power generating facility; case voluntarily

dismissed before oral argument).

28 Neither the GWSA nor the Department has imposed an obligation on companies to

compare the consequences of natural gas consumption versus the use of low- or

no-carbon renewable resources or LNG. Therefore, the Department rejects CLF’s

argument that the Company’s failure to provide such analysis could serve as a basis for

rejecting the precedent agreement (CLF Brief at 16).

D.P.U. 15-48 Page 53

Moreover, the Department declines to adopt CLF’s recommendation for a climate change

mitigation mechanism that, according to CLF, could be used to fund energy efficiency measures,

offset increases in emissions, and bring the precedent agreement into compliance with the

GWSA (CLF Brief at 16-17; CLF Reply Brief at 4). This proposal is substantially the same as

the one that CLF offered in the AIM proceedings, and which the Department rejected (Tr. 2,

at 65-66). See, e.g., D.P.U. 13-157, at 26-27. The charges that CLF seeks to impose are based

on the premise that the proposed NED capacity will increase natural gas emissions in

Massachusetts, and are designed to capture some of the economic benefit generated when

customers switch from oil to gas heating (Exh. CLF-1, at 29).29

CLF contends that the climate change 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).

The Department considers energy efficiency funding at the same time that it determines the

cost-effectiveness of energy efficiency programs, and approves charges designed to recover the

costs of the programs pursuant to G.L. c. 25, § 21. See D.P.U. 12-100 through D.P.U. 12-111,

at 105. CLF’s charges are not designed to recover the costs of any Department-approved energy

efficiency programs and would result in approximately $181 million being collected from

ratepayers over a 20-year period without any consideration as to whether the programs are

cost-effective (see Exhs. CLF-1, at 34, 38; CLF-9, at 4, line 43; CLF-11, at 4, line 39).

29

CLF also proposes adjustment mechanisms to reduce the bill impact of the proposed new

charges on customers (Exh. CLF-1, at 29).

D.P.U. 15-48 Page 54

Moreover, CLF’s charges would be recovered prior to the Company’s actual incurrence of the

costs of the programs, which is inconsistent with Department precedent authorizing recovery of

energy efficiency funds from customers only after programs commence implementation.

D.P.U. 13-157, at 26; see D.P.U. 12-100 through D.P.U. 12-111.

Further, we find that CLF’s proposed charges represent a general rate increase under

G.L. c. 164, § 94 and are beyond the scope of this proceeding. The Department noticed the

precedent agreement under Section 94A. New reconciling rates may be reviewed and approved

only in the context of a G.L. c. 164, § 94 petition and not in the context of a long-term agreement

under Section 94A. Finally, we note that the implementation of CLF’s proposed charges may

have the unintended effect of increasing rather than lowering greenhouse gas emissions over

time. The proposed charges will increase the cost of gas from what it would otherwise be and

thereby lessen the price differential between natural gas and home heating oil. As a result, fewer

customers may choose to convert from oil to gas. Accordingly, based on all of the above, the

Department finds that CLF’s proposed charges are not appropriate, and we reject CLF’s proposal

that they be implemented as a condition of approving the Company’s precedent agreement.

VI. CLF MOTION TO AMEND THE PROCEDURAL SCHEDULE

A. Background

As noted in the procedural history above, the Department held a procedural conference

on May 26, 2015, and, on May 29, 2015, the hearing officer granted CLF’s petition to intervene

and established a procedural schedule, a schedule to which no parties objected.30

On June 1,

30

The schedule was designed to accommodate, to the extent possible, the Company’s

request for a decision by September 1, 2015, to meet contractual obligations.

D.P.U. 15-48 Page 55

2015, CLF filed a motion to amend the procedural schedule. Specifically, CLF sought a

seven-day extension of the deadline for intervenors to submit prefiled testimony, a new deadline

of June 15, 2015, for parties to issue discovery on the intervenor witnesses, and a new deadline

of June 22, 2015, for parties to respond to discovery on the intervenor witnesses but leaving all

other dates in the schedule intact, including the June 24, 2015 date for commencing the

evidentiary hearing (CLF Motion at 1). The Company opposed CLF’s motion.

In support of its Motion, CLF asserted that the precedent agreement has significant

implications for ratepayer interests, reliability of the gas and electric system, and the

Commonwealth’s ability to meet the requirements of the GWSA (CLF Motion at 1). CLF also

asserted that the only proffered rationale for the expedited schedule was to meet a deadline in the

precedent agreement that has been and can be further modified (CLF Motion at 1-2, citing

Exh. BGC-JMB-1, Att. (a) at 42). In addition, CLF argued that the deadline to file intervenor

testimony in this docket and the concurrent dockets (D.P.U. 15-34 and D.P.U. 15-39) is

significantly shorter than the deadline originally proposed by the hearing officer at the

procedural conference (Friday, June 5, as compared to Monday, June 8) (CLF Motion at 2). CLF

also argued that the deadline for responses to CLF’s discovery in D.P.U. 15-48 coincided with

the deadline for CLF to file intervenor testimony (CLF Motion at 2).

CLF contended that the requested amendments would not materially prejudice any party,

that the foreshortened nature of the schedule was prejudicial to the rights of the public,

intervenors, and limited participants under G.L. c. 30A, § 11, and that failure to amend the

procedural schedule as requested would materially prejudice CLF’s rights as an intervenor under

G.L. c. 30A, § 11(3) (CLF Motion at 2, 3). CLF also noted that the Company chose to file its

D.P.U. 15-48 Page 56

petition in this proceeding more than three months after a parallel proceeding was filed by a

fellow LDC in New Hampshire (CLF Motion at 2-3). Finally, CLF maintained that to the extent

that its proposed amendment to the procedural schedule had the potential to interfere with the

resolution of this proceeding according to the Company’s preferred timeline, the Company’s

convenience in the form of satisfying a deadline in a private agreement between the Company

and a third party is outweighed by the parties’ and the public’s right to meaningful participation

in this proceeding (CLF Motion at 3).

The Company opposed CLF’s motion and asserted that CLF’s rights to participate in this

proceeding as an intervenor would not be prejudiced by maintaining the original discovery

schedule (Company Opposition at 1). The Company asserted that CLF, by its own admission,

had known for over four months about a parallel proceeding in New Hampshire concerning the

approval of an essentially identical precedent agreement (Company Opposition at 1). The

Company further argued that CLF had been an active party in two parallel Massachusetts

proceedings where it had received identical precedent agreements with the only difference being

the parties to the contracts (Company Opposition at 2). The Company argues, therefore, that

CLF had more than sufficient time to prepare testimony concerning the precedent agreement for

use in this proceeding regardless of the timing of Berkshire’s petition (Company Opposition

at 2).

On June 5, 2015, the hearing officer issued a memorandum denying CLF’s motion for

lack of good cause shown, and stated that the analysis outlining the reasons for denial would be

provided in a substantive ruling at a later date.

D.P.U. 15-48 Page 57

B. Analysis and Findings

As a threshold matter, and for purposes of administrative efficiency,31

the Department

adopts the hearing officer’s initial ruling as our own. We further find that CLF failed to show

good cause to amend the procedural schedule for the reasons discussed below.

Pursuant to the Department’s procedural rule at 220 C.M.R. § 1.02(5), the Department or

its appointed hearing officer has the discretion, for good cause shown, to extend any time limit

imposed in a particular proceeding. The Department’s “good cause” standard provides that good

cause is a relative term and depends on the circumstances of an individual case. Good cause is

determined in the context of any underlying statutory or regulatory requirement and is based on a

balancing of the public interest, the interest of the party seeking an exception, and the interests of

any other affected party. Nunnally, D.P.U. 92-34-A at 3 (1993), citing Boston Edison Company,

D.P.U. 90-335-A at 4 (1992).

On May 29, 2015, the hearing officer granted CLF’s petition to intervene and established

a procedural schedule that attempted to meet the Company’s requested timeline for a decision

(based on contractual commitments). No party objected to the schedule. The procedural

schedule provided intervenors 21 days within which to file their witness testimony, and we find

that this afforded CLF a “reasonable opportunity to prepare and present evidence and argument”

in accordance with G.L. c. 30A, § 11. Accordingly, the Department concludes that the denial of

CLF’s request for an additional seven days to file witness testimony, along with five-day

31

In its brief, CLF notes that the hearing officer has not yet produced “its full order” laying

out the grounds for denying the motion, and states that it intends to appeal the decision

when “this order” is filed (CLF Brief at 3 n.4).

D.P.U. 15-48 Page 58

extensions of subsequent deadlines for issuing and responding to discovery, did not materially

prejudice CLF’s rights pursuant to G.L. c. 30A, § 11.

Indeed, despite the hearing officer’s denial of its June 1, 2015 motion to amend the

procedural schedule, CLF filed its witness testimony on June 5, 2015, pursuant to the established

schedule, issued six sets of information requests to the Company, responded to one set of

information requests issued by the Department, and fully participated in the evidentiary hearing

(see Trs. 1, 1A, 2, 3). Thus, CLF demonstrated that compliance with the procedural schedule

was achievable.

We further note that, if granted, CLF’s motion would have left only two days after final

discovery responses were filed before the start of the evidentiary hearings on June 24, 2015.

Under these circumstances, it was appropriate to deny CLF’s motion so as to maintain

reasonable deadlines and ensure that the hearing schedule would not be disrupted. In sum, the

Department determines that CLF was afforded a reasonable opportunity to prepare and present

evidence and argument under the procedural schedule established by the hearing officer. For the

above-stated reasons, the Department denies CLF’s motion to amend the schedule for failure to

show good cause.

VII. CONCLUSION

The Department has reviewed the Company’s petition and the evidence presented to

determine whether acquisition of capacity on the NED project is (1) consistent with the

Company’s portfolio objectives and the GWSA, and (2) compares favorably to the range of

available alternative options. The Department finds that the Company has identified a need for

incremental capacity to ensure reliability and deliverability of natural gas to meet customer

D.P.U. 15-48 Page 59

requirements. We also find that the Company has established that the proposed acquisition of

capacity on the NED project will enable the Company to meet its short- and long-term

requirements. We further find that the proposed acquisition will enhance the reliability,

flexibility, and diversity of the Company’s supply portfolio.

Accordingly, based on our review, the Department finds that the Company’s proposed

acquisition of NED project capacity is consistent with both the Company’s portfolio objectives

and the GWSA, compares favorably to the range of reasonable alternatives, and is therefore

consistent with the public interest. For all of the foregoing reasons, the Department approves the

precedent agreement. Further, the Department authorizes the Company to execute the proposed

NED 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.

VIII. ORDER

Accordingly after due notice, hearing, and consideration, it is hereby

ORDERED: That the precedent agreement for two 20-year firm transportation contracts

between The Berkshire Gas Company and Tennessee Gas Pipeline Company, LLC is

APPROVED; and it is

D.P.U. 15-48 Page 60

FURTHER ORDERED: That The Berkshire Gas Company shall comply with all

directives contained in this Order.

By Order of the Department,

/s/

Angela M. O’Connor, Chairman

/s/

Jolette A. Westbrook, Commissioner

/s/

_______________________________

Robert E. Hayden, Commissioner

D.P.U. 15-48 Page 61

An appeal as to matters of law from any final decision, order or ruling of the Commission may

be taken to the Supreme Judicial Court by an aggrieved party in interest by the filing of a written

petition praying that the Order of the Commission be modified or set aside in whole or in part.

Such petition for appeal shall be filed with the Secretary of the Commission within twenty days

after the date of service of the decision, order or ruling of the Commission, or within such further

time as the Commission may allow upon request filed prior to the expiration of the twenty days

after the date of service of said decision, order or ruling. Within ten days after such petition has

been filed, the appealing party shall enter the appeal in the Supreme Judicial Court sitting in

Suffolk County by filing a copy thereof with the Clerk of said Court. G.L. c. 25, § 5.

mass. dept. of public utilities ruling to allow berkshire gas to purchase natural gas from proposed...

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