STATE OF ALASKA BEFORE THE REGULATORY COMMISSION OF …€¦ · Before Commissioners: Robert M. Pickett, Chairman Stephen McAlpine Rebecca L. Pauli Norman Rokeberg Janis W. Wilson

PREFILED DIRECT TESTIMONY OF DANIEL M. DIECKGRAEFF Docket No. U-16-____: June 1, 2016 Page 1 of 59

STATE OF ALASKA

BEFORE THE REGULATORY COMMISSION OF ALASKA

Before Commissioners: Robert M. Pickett, Chairman Stephen McAlpine Rebecca L. Pauli Norman Rokeberg Janis W. Wilson

In the Matter of the Consideration of the Revenue Requirement Designated as TA 285-4 Filed by ENSTAR NATURAL GAS COMPANY, A DIVISION OF SEMCO ENERGY, INC.

) ) ) ) )

Docket No. U-16-____

PREFILED DIRECT TESTIMONY OF

DANIEL M. DIECKGRAEFF


PREFILED DIRECT TESTIMONY OF

DANIEL M. DIECKGRAEFF

TABLE OF CONTENTS

I. POSITION AND QUALIFICATIONS .........................................................................3

II. PURPOSE OF TESTIMONY AND BACKGROUND .................................................4

III. 275(a) FILING DATA ...................................................................................................6

IV. ENSTAR’S BASE RATE CASE HISTORY ..............................................................12

V. YEAR-END RATE BASE ..........................................................................................14

VI. CAPITAL STRUCTURE ............................................................................................22

VII. GAS SALES AND TRANSPORTATION REVENUE ADJUSTMENTS .................23

VIII. ADJUSTMENTS TO OPERATING EXPENSES ......................................................27

IX. RATE BASE ADJUSTMENTS ..................................................................................35

X. HOMER EXTENSION ................................................................................................36

XI. COST-OF-SERVICE STUDY AND RATE DESIGN ................................................39

XII. REQUEST FOR INTERIM RATE RELIEF ...............................................................50

XIII. MOVING STORAGE FEES FROM COST OF GAS STORED ................................52

XIV. CONCLUSION ............................................................................................................59

EXHIBITS

Exhibit DMD-1 Resume of Daniel M. Dieckgraeff

Exhibit DMD-2 NARUC Resolution

Exhibit DMD-3 Calculation of Interim Increase


I. POSITION AND QUALIFICATIONS 1

Q. State your name, business address, and present position. 2

A. My name is Daniel M. Dieckgraeff. My business address is 3000 Spenard Road, 3

Anchorage, Alaska 99503. I am the Director of Rates and Regulatory Affairs for 4

ENSTAR Natural Gas Company (“ENSTAR”) and Alaska Pipeline Company 5

(“APC”). APC and ENSTAR are regulated as a single entity. For convenience, I will 6

refer to these two entities collectively as “ENSTAR” or the “Company” throughout 7

my testimony. I am appearing in this proceeding on behalf of ENSTAR. 8

Q. Briefly describe your professional experience and educational background. 9

A. I have been employed by ENSTAR since July 12, 1982, and have held various 10

supervisory and managerial positions with responsibility for ENSTAR regulatory 11

matters since then. From 2000 to early 2008, I also had primary responsibility for gas 12

supply contract negotiation and administration. Prior to joining ENSTAR, I spent 13

three years with the Anchorage office of the accounting firm of Price Waterhouse 14

(now known as PricewaterhouseCoopers). I received a Bachelor of Business 15

Administration degree with a major in public accounting from Gonzaga University in 16

1979 and a Master of Business Administration with a concentration in Global Finance 17

from Alaska Pacific University in 2007. My resume is attached hereto as Exhibit 18

DMD-1. 19

Q. Briefly describe your current professional responsibilities. 20

A. I am responsible for all of ENSTAR’s regulatory matters before the Regulatory 21

Commission of Alaska (the “RCA” or the “Commission”), as well as those of Cook 22

Inlet Natural Gas Storage Alaska, LLC (“CINGSA”) pursuant to an administrative 23

services contract between ENSTAR and CINGSA. 24


Q. Have you previously testified before the RCA or any other regulatory 1

commission? 2

A. Yes, I have testified before the RCA and its predecessor agency numerous times, 3

including in ENSTAR’s 2000 test year base rate and rate redesign case (Docket U-00-4

88). I also submitted written testimony in ENSTAR’s 2008 test year base rate and 5

rate redesign case (Dockets U-09-69 and U-09-70) and ENSTAR’s 2013 test year 6

base rate and rate redesign case (Docket U-14-111), but those cases were settled 7

before going to hearing. I most recently appeared before the Commission as a 8

witness in Docket U-15-016 on behalf of CINGSA. 9

II. PURPOSE OF TESTIMONY AND BACKGROUND 10

Q. What is the purpose of your direct testimony? 11

A. I am sponsoring various schedules supporting ENSTAR’s revenue requirement filed 12

pursuant to Commission regulation 3 AAC 48.275(a) (“275(a) filing”), which is 13

included as Attachment B to ENSTAR’s overall rate filing. I describe several of the 14

adjustments to test year data that ENSTAR witness Dr. Bruce H. Fairchild 15

incorporates in his cost of service (“COS”) study to calculate ENSTAR’s normalized 16

revenues, expenses, and rate base using a test year ending December 31, 2015. I also 17

discuss various aspects of ENSTAR’s COS study and its proposed rate design. 18

Finally, I discuss ENSTAR’s proposed revision to its gas cost adjustment (“GCA”) 19

provision related to stored gas costs. I am also sponsoring the related tariff sheets that 20

present the proposed interim and permanent rates, as well as the proposed change to 21

ENSTAR’s GCA provision. 22


Q. What information is the Company filing in this proceeding? 1

A. ENSTAR is filing revenue requirement and COS information for the year ended 2

December 31, 2015, and rate design proposals for the Commission’s consideration, 3

pursuant to the stipulation accepted by the Commission in ENSTAR’s last rate case, 4

Docket U-14-111(18). The revenue requirement data are being filed in accordance 5

with 3 AAC 48.275(a), in the form of a tariff filing as prescribed by 3 AAC 48.270. 6

The COS study and rate design information are being filed in accordance with 3 AAC 7

48.275(h), which is Exhibit BHF-2 to the testimony of Dr. Fairchild. In accordance 8

with both 3 AAC 48.275(a) and (h), ENSTAR is providing prefiled direct testimony 9

supporting the filing. ENSTAR is also including a request for interim rates, a rate 10

refund plan, and proposed revisions to its GCA. 11

Q. Which schedules in ENSTAR’s 275(a) filing are you specifically sponsoring? 12

A. I am sponsoring the following schedules: 13

Comparative Statement of Assets, Liabilities and Other Credits; 14

Comparative Statement of Income and Operating Expenses; 15

Comparative Statement of Changes in Equity Position; 16

Plant in Service and Accumulated Depreciation – 2014 and 2015; 17

Depreciation Expense – 2014 and 2015; 18

Long-Term Debt Outstanding – 2014 and 2015; and 19

Effective Proposed Rate Increases. 20

These schedules are required by 3 AAC 48.275(a)(1)-(4), (10) and (13). 21


Q. Describe the source of the information contained on these schedules. 1

A. These schedules contain historical financial data compiled from ENSTAR’s 2

accounting books and records, or are based on such data, for the test year ended 3

December 31, 2015. ENSTAR’s accounting books and records are maintained in 4

accordance with the Uniform System of Accounts (“USOA”) prescribed by the 5

Federal Energy Regulatory Commission and required by this Commission pursuant to 6

3 AAC 48.277(a)(5). Internal controls are in place to assure compliance with the 7

applicable accounting instructions, including internal and external audit functions that 8

are performed by two of the largest four international accounting firms. For internal 9

reporting purposes, ENSTAR uses a more detailed chart of accounts than is 10

prescribed by the USOA, but the Company’s accounting system summarizes the 11

accounts into categories that match the USOA. These accounting records are 12

consistent with prior presentations of similar data to the Commission. 13

III. 275(a) FILING DATA 14

Q. Have you reviewed ENSTAR’s books and records in connection with this filing 15

and made any adjustments to the data? 16

A. Yes. In preparing this filing, I (or ENSTAR employees acting under my direction and 17

supervision) reviewed the data contained in ENSTAR’s accounting books and records 18

and identified unusual events, non-recurring expense and revenue items, areas 19

requiring or warranting adjustments for known and measurable changes, and other 20

necessary and/or appropriate revenue, expense, and investment adjustments. This 21

review identified and quantified adjustments needed for a fair and reasonable 22

evaluation of the adequacy of ENSTAR’s base rates. 23


The results of this review are reflected in various adjustments to test year data 1

made to arrive at the “normalized” test year included in this filing. Normalizing test 2

year data is a standard regulatory practice and is intended to give the Commission a 3

reasonable accounting basis for evaluating and establishing ENSTAR’s revised base 4

rates. 5

Q. What is the requirement for 275(a) filing data? 6

A. In addition to the six schedules that I am sponsoring that are listed above, 3 AAC 7

48.275(a) requires schedules showing: 8

computations of revenue requirement, and revenue deficiency or surplus, in 9

both absolute dollars and as a percentage of revenues, for the normalized test 10

year; 11

test year operating revenues and expenses, pro forma adjustments, and the 12

resulting normalized test year operating revenues and expenses; 13

the computation of and a narrative explanation for any pro forma adjustments 14

to the test year results of operations; 15

the computation of the pro forma provision for income taxes for the 16

normalized test year; 17

the computation of rate base using a 13-month average of all rate base 18

components except cash working capital allowance, and using any other rate 19

base theory the utility considers appropriate and supportable (in this case, the 20

computation of a year-end rate base); 21

the pro forma cash working capital requirement based on the normalized test 22

year; and 23


the computation of weighted cost of capital. 1

These schedules are all contained in Attachment B to ENSTAR’s rate filing 2

and are sponsored by Dr. Fairchild. 3

Q. What is a “normalized test-year”? 4

A. 3 AAC 48.820(42) defines "normalized test-year" as “historical test-year adjusted to 5

reflect the effect of known and measurable changes and to delete or average the effect 6

of unusual or nonrecurring events, for the purpose of determining a test year which is 7

representative of normal operations in the immediate future.” In other words, it is 8

used to develop a representative cost of service for the period during which the rates 9

being set will be in effect. This is the traditional cost of service approach that the 10

Commission has routinely followed in rate case orders over the years. For example, 11

in Order U-05-043(15)/U-05-044(15), the Commission stated: 12

[T]he goal of cost-based ratemaking is not to recover past costs 13 but to predict the rates necessary to yield revenue adequate to 14 cover the utility's costs and provide the opportunity to earn a 15 reasonable return on investment during the future period when 16 the rates are likely to be in effect. 17 18

(p. 6-7). Other examples include Order U-87-084(8) dated February 10, 1989, p. 13-19

14; Order U-93-058(8) dated December 21, 1993, p. 7; Order U-00-088(12) dated 20

August 8, 2002, p. 5; and Order P-97-004(151) et. al., dated November 27, 2002, p. 21

6-7. The fact that the Commission utilizes a historical test year, not a future period 22

test year, makes the adjustments to the historical test year data very important. 23

Q. Why are adjustments to historical test year data important? 24

A. A utility filing a rate request before the RCA must base its request on a completed test 25

year. Generally, it takes three to nine months after the test year ends to prepare a rate 26


request. Conditions change, operations and construction (new investment) continue, 1

inflation occurs, labor rates increase, and overall costs almost always increase. 2

Pursuant to Alaska Statute (“AS”) 42.05.175(c), the statutory timeline for the 3

Commission to rule on rate cases is 15 months. If the full amount of time is taken, by 4

the time the new rates are put into effect, the costs from the historical test year will be 5

more than two years old. Without taking into account changes that have occurred 6

since the test year, the utility’s rates will almost certainly be based on costs that are 7

below those that it is actually incurring. 8

Q. Is there a utility industry common term for this delay in implementing new final 9

rates? 10

A. Yes, the common term is “regulatory lag,” of which this is one component. 11

Q. Is Alaska’s 15-month statutory timeline for ruling on a rate case typical when 12

compared to other jurisdictions? 13

A. No. According to data from Regulatory Research Associates (“RRA”), 76% of the 14

regulatory jurisdictions in the United States are required to rule on a rate case within 15

twelve months of filing. 16

Q. Does a long regulatory lag have an adverse impact on a utility? 17

A. Yes. Both ENSTAR witnesses Mr. Robert B. Hevert and Mr. Jared B. Green discuss 18

regulatory lag in their testimony. In addition, according to the RRA, on pages 5-6 of 19

its Regulatory Focus publication dated January 16, 2015: 20

[I]f the state requires that a filing be based on fully historical 21 data, i.e., the test year in the case is a historical one, the inputs 22 used to set rates such as expenses and asset values included in 23 rate base will be close to two years old by the time a rate 24 change is implemented. In a construction cycle, when new 25 capital spending is outpacing depreciation, this timing 26


mismatch is perhaps the single largest contributor to a utility’s 1 failing to earn its authorized ROE. 2

Q. How did ENSTAR’s capital spending in 2015 compare to its depreciation 3

expense? 4

A. ENSTAR’s capital expenditures in 2015 were $40.7 million, which were 2.56 times 5

its depreciation expense of $15.9 million. The combination of ENSTAR’s 6

significantly greater capital spend relative to its internal cash generation through 7

depreciation expense and the Alaskan statutory construct subjects ENSTAR to 8

extraordinary regulatory lag and exacerbates the risk that it will not be able to realize 9

its authorized rate of return. 10

Q. What are the normal types of pro forma adjustments made to test years in rate 11

requests? 12

A. Adjustments are commonly grouped into: (1) normalizing adjustments; (2) 13

annualizing adjustments; (3) out-of-period adjustments; (4) attritional adjustments; 14

and (5) reclassification adjustments. 15

Q. What is a normalizing adjustment? 16

A. A normalizing adjustment restates the period’s data for abnormal conditions. 17

Q. What is an annualizing adjustment? 18

A. An annualizing adjustment extends over the period, or eliminates from the period, 19

events that have had partial period effects and are either recurring or have been 20

terminated. 21

Q. What is an out-of-period adjustment? 22

A. An out-of-period adjustment is used to adjust expenses to address known and 23

measurable events that occur before or after the test period. 24


Q. What is an attritional adjustment? 1

A, An attritional adjustment recognizes changing conditions, including annualizing 2

conditions, updating of conditions, or adjusting for any known and measurable 3

changes in events or conditions that will affect the utility’s future cost or revenue 4

levels. 5

Q. What is a reclassification adjustment? 6

A. A reclassification adjustment adds or removes items from one account to another for 7

the purpose of rate recovery. 8

Q. For an adjustment to be approved, what requirements must be satisfied? 9

A. Normally, adjustments must be: (1) reasonably known and measurable; 10

(2) synchronized with other expenses, rate base, and revenue; (3) supportable; and 11

(4) disclosed. 12

Q. Do ENSTAR’s proposed pro forma adjustments meet these requirements? 13

A. Yes, as described below and in the direct testimony of ENSTAR witness Dr. 14

Fairchild. 15

Q. Why did ENSTAR choose 2015 as the test year? 16

A. ENSTAR was required to use a 2015 test year as a condition of the settlement of 17

Docket U-14-111, ENSTAR’s last rate case, which was submitted to the Commission 18

in August 2015 and accepted in Order U-14-111(18) (the “U-14-111 Stipulation”). 19

Q. What does ENSTAR’s 275(a) filing demonstrate? 20

A. ENSTAR’s 275(a) filing demonstrates that even with the interim rate increase that 21

became effective January 1, 2016, ENSTAR is under-earning. Page 4 of the 275(a) 22


filing, Attachment B to the rate filing, shows an annual revenue deficiency of 1

$11,812,191. 2

IV. ENSTAR’S BASE RATE CASE HISTORY 3

Q. Briefly summarize ENSTAR’s history of base rate changes since it began 4

operating. 5

A. ENSTAR’s base rates (i.e., the rates that recover the Company’s costs of providing 6

service to customers exclusive of gas costs) remained unchanged between 1961 7

through 1974, except for a modest reduction ($1 per customer per month) instituted in 8

1972. In 1976, ENSTAR filed its first base rate increase with the Commission 9

(Docket U-75-95). At the conclusion of that case, the Company’s base rates were 10

increased and ENSTAR was authorized to earn a return on equity of 14.25%. 11

ENSTAR filed its second rate case in 1981 (Docket U-81-101) and was granted 12

another base rate increase based on a 16.65% return on equity. In connection with the 13

construction of the Beluga Pipeline in 1984, ENSTAR filed its third base rate case 14

(Docket U-84-59) and was granted another base rate increase based on a 15.65% 15

return on equity. 16

ENSTAR’s base rates remained the same from 1987 through 2002. As a 17

condition of approval of SEMCO Energy, Inc.’s (“SEMCO”) purchase of ENSTAR, 18

the Company was required to file information regarding the adequacy of its base rates 19

in 2000, using a test year ending December 31, 1999.1 ENSTAR filed this data, but 20

the Commission later determined that a test year ended December 31, 2000, would be 21

a better basis from which to evaluate rates.2 ENSTAR then submitted information for 22

1 Order U-99-93(1)/U-99-94(1), dated October 19, 1999. 2 Order U-00-88(3), dated March 5, 2001.


the test year ended December 31, 2000, which became the basis for a base rate review 1

in Docket U-00-88. 2

Phase One of Docket U-00-88 dealt with ENSTAR’s revenue requirement. 3

Based on its review, the Commission granted a 12.55% return on equity and ordered a 4

base rate reduction.3 The Commission also instituted a second phase of the 5

proceeding to focus on rate design.4 ENSTAR filed the required rate design 6

information in December 2002, and the rate design portion of the proceeding was 7

settled by a stipulation accepted by the Commission.5 8

Order U-04-106(5), dated June 16, 2005,6 required ENSTAR to file, among 9

other things, a revenue requirement and cost of service study. Order U-04-106(8)/U-10

08-123(1) revised the filing deadline to June 1, 2009, and established a test year 11

ending on December 31, 2008. Following ENSTAR’s filing, the Commission 12

suspended and bifurcated it into two dockets: U-09-69 (revenue requirement) and U-13

09-70 (rate design). Both dockets were settled by a stipulation accepted by the 14

Commission,7 which resulted in the four general service rate classes and the rate 15

structure currently in place. The stipulation provided for a total increase of 16

$10,761,729 on a rate base of $199,000,000, with a cost of equity of 12.55%. The 17

stipulation also provided that ENSTAR would file “a base rate case no later than 18

3 Orders U-00-88(12) and U-00-88(15), dated August 8, 2002 and September 16, 2002,

respectively.

4 There was a third phase of this proceeding that related to transportation terms and conditions. That phase was completed and the entire docket was closed effective May 17, 2006 (Order U-00-88(40)).

5 Order U-00-88(22), issued May 21, 2003.

6 In the Matter of the Investigation into the Financing Provided by K-1 GHM, LLLP to SEMCO Energy, Inc. Order No. 5 also granted a motion to withdraw and terminate the proceeding.

7 Order U-09-69(10)/U-09-70(10), issued August 9, 2010.


August 1, 2014 based upon a test year ended December 31, 2013.”8 In Order U-09-1

69/U-09-70(12), dated August 6, 2014, the Commission granted ENSTAR’s request 2

to extend the filing deadline to September 5, 2014. 3

In September 2014, ENSTAR submitted the required revenue requirement 4

filing along with a 275(h) COS and supporting testimony. The Commission 5

suspended the filing into Docket U-14-111 and granted an interim increase of 3.75% 6

effective November 1, 2014.9 The docket was settled by a stipulation accepted by the 7

Commission, which resulted in a permanent rate increase based upon a revenue 8

requirement of $81,088,932 effective October 1, 2015, and an interim rate increase 9

based upon a revenue requirement of $83,288,932 effective January 1, 2016. The 10

January 2016 rates are interim and refundable pending resolution of this case.10 11

V. YEAR-END RATE BASE 12

Q. Please describe the rate base calculation methodology that ENSTAR is 13

requesting for ratemaking purposes. 14

A. ENSTAR is requesting that its revenue requirement be based on the rate base 15

measured as of December 31, 2015, the end of its test year. 16

Q. Does ENSTAR’s filing comport with 3 AAC 48.275(a)(9)? 17

A. Yes. ENSTAR’s schedule of rate base (page 2 of Attachment B to the overall rate 18

filing) presents the required computation of rate base using a 13-month average and, 19

following pro forma adjustments, the computation of the test year-end rate base. 20

Schedule N also provides the detailed calculation of the 13-month averages and the 21 8 Id. Appendix at 8. The requirement is reiterated in Ordering Paragraph No. 5 of Order U-09-

69(10)/U-09-70(10).

9 Order U-14-111(1), issued October 27, 2014.

10 Order U-14-111(18), issued September 29, 2015.


test year-end balances of rate base items. In addition, Attachment C contains a 1

schedule of rate base and revenue requirement calculations based upon the 13-month 2

average rate base method to support ENSTAR’s additional interim increase request. 3

Q. Can you explain the difference between 13-month average and test year-end rate 4

base treatment? 5

A. Yes. Pursuant to 3 AAC 275(a)(9), the 13-month average method totals balances of 6

the rate base components at the beginning of each month of the test year, plus the 7

balance at the end of the twelfth month, and then divides it by thirteen to arrive at the 8

figure to be applied for the filing party’s rate base. Pursuant to 3 AAC 48.275(a)(9), 9

however, an applicant may use “any other rate-base theory the utility or pipeline 10

carrier considers appropriate and supportable.” A test year-end rate base is an 11

example of such a theory wherein the actual rate base at the end of the test year is 12

used to calculate the revenue requirement. 13

Q. What is ENSTAR’s basis for requesting a test year-end rate base? 14

A. As I discussed above, the purpose of a 275(a) filing is to develop a representative cost 15

of service for the period during which the rates being set will be in effect. As 16

discussed by Mr. Green, a test year-end rate base is more representative of the future 17

period for which rates are being set, especially when the utility has been making 18

significant capital expenditures, as has ENSTAR. 19


Q. Are you familiar with the criteria used by this Commission to assess the 1

appropriateness of a test year-end rate base? 2

A. Yes. The RCA may consider all relevant factors in determining the appropriate rate 3

base treatment,11 and it has permitted the use of test year-end rate bases in the past, 4

including in two of ENSTAR’s prior rate cases.12 5

Q. Is the historical 13-month average method the predominant method accepted in 6

most US utility regulatory jurisdictions? 7

A. No, most jurisdictions use a method other than the historical 13-month average of 8

plant for rate base. In fact, the majority use either a test year-end rate base, or a 9

future or forecasted rate base. 10

Q. What are some of the factors the Commission has considered when it has 11

approved the use of a test year-end rate base? 12

A. In Order U-05-43(15), the RCA took note of Golden Heart Utilities’ (“GHU”) 13

argument that: 14

[R]ates should reflect the costs that will pertain when the rates 15 are in effect, and in this proceeding, year-end rate base will 16 better meet that objective…If average rate base is employed 17 when revenues do not keep pace with increases in plant and 18 depreciation, the utilities will not have a reasonable 19 opportunity to earn the allowed return. 20

In allowing the use of test year-end rate base in that case, the RCA reasoned: 21

[d]uring the test year, the utilities demonstrated growth in 22 combined rate base of almost 21 percent, reflecting the 23 continuation of the facilities improvement program. The capital 24 investment was to rebuild or replace worn out plant and did not 25

11 See Order U-75-30(4) and Order U-05-043(15) at 38 (“In reviewing the proposed use of a year-

end rate base, we consider all relevant factors.”).

12 A year end rate base was used in ENSTAR’s first rate case (Docket U-75-30 for the interim, Docket U-75-95 for the permanent increase) and in its 1984 test year rate case (Docket U-84-59).


result in nor was it intended to significantly increase customer 1 connections. No party suggested the rate base improvements 2 were not needed to provide safe reliable utility services. During 3 the test year the utilities did not experience increases in the 4 number of customers or in revenues that would offset the 5 dramatic increase in investment. Under all of the above 6 circumstances and for this rate case we find use of year-end 7 rate base is reasonable.13 8

Q. Does the Commission require utilities to synchronize revenues if they choose to 9

pursue a test year-end rate base? 10

A. While the Commission does not have a formal requirement, it has a definite 11

preference for utilities to synchronize year-end revenues if they pursue a rate base 12

measured at test year-end. This helps to ensure that the utility’s calculation takes into 13

account the customers and revenue generated contemporaneously with the valuation 14

of rate base.14 ENSTAR has addressed this preference in this filing. 15

Q. Is the use of test year-end rate base appropriate in ENSTAR’s current filing? 16

A. Yes. As I discussed above, ENSTAR had a significant level of capital expenditures 17

in 2015 ($40.7 million), which was more than 16% of its 2014 net plant. All of the 18

new plant was used and useful in providing natural gas utility service to the 19

ENSTAR’s customers in 2015. The majority of the capital expenditures, $34.6 20

million, were attributable to non-income producing plant. “Non-income producing 21

plant” is investment that does not result in nor is intended to significantly increase 22

customer connections. In 2015, ENSTAR performed a number of necessary updates 23

and repairs to existing infrastructure that consisted of non-income producing plant. 24

13 Order U-05-43(15) at 38.

14 Order U-81-32(3) at 4-5 and Order U-76-89(5) at 7.


For example, ENSTAR is required to comply with federally mandated 1

transmission pipeline integrity management, distribution pipeline integrity 2

management and pipeline maximum allowable operating pressure testing programs. 3

The Company spent $6.1 million on capital additions to help support these programs 4

in 2015. This includes $3.2 million spent to replace and upgrade ENSTAR’s circa 5

1961 Potter Gate Station and install the necessary facilities to permit ENSTAR to 6

inspect or “pig” its two Turnagain Arm crossings in the spring of 2016 ($2.3 million 7

at Potter and the remainder at Burnt Island). In addition to the $6.1 million spent to 8

comply with these programs, ENSTAR spent an additional $2.5 million on an 9

emergency replacement of a portion of ENSTAR’s 20-inch Beluga-to-Anchorage 10

pipeline at the Beluga River crossing after the river bank receded and exposed the 11

original line. 12

Q. Have regulators acknowledged the need to reduce regulatory lag and the utility’s 13

near-term financial impact on the utility of these safety-related expenditures? 14

A. Yes. The National Association of Regulatory Commissioners (“NARUC”) has long 15

focused on pipeline safety and supported utilities and pipelines in prioritizing safety 16

and asset replacement. In July 2013, the NARUC Board of Directors’ Committee on 17

Gas and Committee on Critical Infrastructure adopted the “Resolution Encouraging 18

Natural Gas Line Investment and the Expedited Replacement of High-Risk 19

Distribution Mains and Service Lines.” The resolution urges state commissions to 20

“explore, examine, and consider adopting alternative rate recovery mechanisms as 21

necessary to accelerate the modernization, replacement and expansion of the nation’s 22


natural gas pipeline systems….” A true and correct copy of the NARUC resolution is 1

attached to my testimony as Exhibit DMD-2. 2

Q. In addition to the $8.6 million spent to comply with federally mandated 3

programs and to make the emergency repair, what other major non-revenue 4

producing projects were included in the $34.6 million? 5

A. As discussed in the direct testimony of ENSTAR witness Mr. Green, and as discussed 6

extensively in Docket U-14-111, ENSTAR built the CINGSA lateral project in 2015, 7

at a cost of $11.7 million. The Commission approved the service area expansion for 8

the CINGSA lateral in Order U-15-87(2), finding on page 7: 9

that the Lateral will benefit the public by increasing the 10 efficiency and deliverability of gas to CINGSA’s customers by 11 improving system reliability, by providing a second access 12 pipeline to CINGSA, and by reducing transportation cost 13 incurred by CINGSA’s customers. We find the service area 14 expansion is required for the public convenience and necessity. 15

Q. Was the CINGSA Lateral in service in 2015? 16

A. Yes. The lateral was available for use in mid-summer 2015. CINGSA customers 17

began using the lateral for withdrawal in November 2015, following the RCA 18

decision to amend ENSTAR’s certificate of public convenience and necessity. 19

Q. Are all of CINGSA’s other firm storage service (“FSS”) customers using the 20

lateral? 21

A. Yes. Chugach Electric Association (“CEA”) and Municipal Light and Power 22

(“ML&P”) began using it in November 2015 and Alaska Electric and Energy 23

Cooperative/Homer Electric Association (“AEEC/HEA”) began using it in May 2016. 24


Q. What other major non-revenue producing capital projects did ENSTAR place in 1

service in 2015? 2

A. As discussed by Mr. Green in his direct testimony, ENSTAR spent $4.7 million 3

replacing over 50,000 Encoder Receiver Transmitters (“ERTs”), a packet radio 4

protocol used for automatic meter reading that had reached the end of their 15-year 5

battery design lives. ENSTAR has had ERTs on all but a few of its very largest 6

meters since the early 2000’s.15 The ERTs allow ENSTAR to use vehicle-mounted 7

equipment to read meters by driving through neighborhoods and receiving signals 8

from the meters, rather than physically visiting and visually reading each one, 9

ultimately resulting in lower costs. 10

The Company also made several other capital expenditures in 2015 necessary 11

for the utility’s ongoing delivery of safe, reliable service to its customers, and which 12

include: 13

computer network improvements ($233,000); 14

phone system improvements ($51,000); 15

replacement of a pipeline interconnection meter ($220,000); 16

an upgrade of ENSTAR’s customer information and billing system 17

($543,944); 18

a gate station replacement on the Kenai ($461,000); and 19

security cameras ($37,000). 20

These projects are necessary to ensure ENSTAR’s safe, efficient, and reliable service 21

to its customers. Because these projects updated and repaired existing infrastructure, 22

15 The largest meters have electronic totalizers and/or telemetry.


these costs, while absolutely critical for ENSTAR’s service, did not result in 1

additional demand or a growth in customer base. 2

Q. Were there plant additions in 2015 that did result in growth in ENSTAR’s 3

customer base and gas demand? 4

A. Yes. ENSTAR spent approximately $6.2 million in plant additions for gas 5

distribution mains, service lines, meters, and related items that serve new customers. 6

Q. Have you synchronized expenses and revenues to support your test year-end rate 7

base? 8

A. Yes. ENSTAR recognizes the value that the Commission places on the “matching 9

principle” in which expenses are synchronized with other revenue requirement 10

components, such as revenues. A filing party is not required to make this 11

synchronization in order to receive year-end rate base treatment. Out of an 12

abundance of caution, however, ENSTAR has synchronized expenses and revenues in 13

the present rate filing. 14

Q. Which adjustments synchronize revenues and expenses, and support ENSTAR’s 15

test year-end rate base request? 16

A. I will simply list the affected adjustments here. Dr. Fairchild will cover the details of 17

certain calculations in his direct testimony, and I will cover the remainder of the 18

details in my testimony below. Volumes and revenues for General Service customers 19

are synchronized with the test year-end rate base on page 1 of the 275(a) filing, with 20

the details contained in Schedule A in Attachment B. This adjustment reflects 21

increased revenues (resulting in a $610,319 increase in gross margin) to reflect the 22

test year-end General Service customer count and corresponding usage. On the 23


expense side, net credit card costs (up $15,146), postal expenses (up $465), 1

uncollectible accounts (up $1,139), depreciation and amortization expenses (up 2

$776,077), and property taxes (up $180,398) have also been synchronized to test 3

year-end rate base. 4

Q. Were there other rate base items synchronized for the test year-end plant? 5

A. Yes. They are shown on Adjustment N on the Rate Base Schedule, page 2 of 6

Attachment B. Most notably, Accumulated Depreciation, Construction Advances and 7

Deferred Income Taxes have all been adjusted (synchronized) to match year-end 8

plant. Where applicable, Deferred Income Taxes also include the effect of bonus tax 9

depreciation. 10

Q. Were there any components of rate base not adjusted to a test year-end basis? 11

A. Yes. ENSTAR did not adjust Materials and Supplies, Prepayments, and Gas Stored 12

Underground from the 13-month rate base treatment to a test year-end rate base 13

treatment, for reasons discussed in more detail below. Also, the U-14-111 Stipulation 14

required ENSTAR to perform a lead-lag study, which forms the basis for the 15

requested cash working capital allowance included in rate base. 16

VI. CAPITAL STRUCTURE 17

Q. What capital structure is ENSTAR using in the 275(a) filing? 18

A. ENSTAR is using its actual capital structure as of December 31, 2015, which is 19

48.32% long-term debt and 51.68% common equity. For comparison, the capital 20

structure that was proposed and accepted in ENSTAR’s last rate case (Docket U-14-21

111) was 47.75% debt and 52.25% equity. 22


VII. GAS SALES AND TRANSPORTATION REVENUE ADJUSTMENTS 1

Q. What are revenue adjustments and why are they important in setting revised 2

base rates? 3

A. As I discussed above, base rates should recover the utility’s expected costs of 4

providing service to customers in the “rate effective period” (i.e., when rates will be 5

in effect). An element of that process is using historical test year data to estimate the 6

amount of revenues a utility is likely to collect in the rate effective period. Revenue 7

adjustments are necessary to reflect known and measurable changes from the 8

unadjusted test year data. While some of these adjustments appear on different 9

schedules, I quantify the proposed adjustments as part of my discussion of each item 10

below. 11

Q. What adjustments to revenues included in ENSTAR’s 275(a) filing will you be 12

discussing? 13

A. First, I will discuss the adjustments made to all rate classes for the Docket U-14-111 14

rate changes, as well as the adjustment to the gas sales customers for the gas cost 15

adjustment change, which ENSTAR has filed with the Commission with a requested 16

effective date of July 1, 2016. Second, I will discuss the adjustments to the General 17

Service rate classes to synchronize revenues with the test year-end rate base and 18

customer count and usage. Finally, I will discuss the adjustments to the revenues 19

ENSTAR actually received from its power plant customers in 2015 to adjust for a 20

power plant that came on-line during the test year, and for a new power plant 21

scheduled to come on-line during the summer of 2016. 22


Q. Please discuss the adjustments made to the General Service rate classes for the 1

Docket U-14-111 rate changes. 2

A. The Docket U-14-111 Stipulation provided for a permanent rate increase effective 3

October 1, 2015, and an additional interim increase effective January 1, 2016. As 4

discussed in more detail in Dr. Fairchild’s direct testimony and shown on Schedule A 5

of Attachment B to the rate filing, ENSTAR has made annualizing adjustments to 6

revenues from the General Service classes to reflect the current level of revenues 7

attributable to the January 1, 2016 interim rate increase. 8

Q. Please discuss the adjustment made for the cost of gas. 9

A. The cost of gas in the test year was removed and replaced with the weighted average 10

cost of gas that will become effective July 1, 2016, which is $7.0577 per Mcf, as 11

proposed in ENSTAR’s annual gas cost adjustment revision filing, TA 284-4, filed on 12

May 16, 2016. The adjustment to remove the test year gas cost and to add the new 13

gas cost is also developed in Schedule A. 14

Q. What other adjustment to the General Service Revenues is shown on Schedule 15

A? 16

A. As Dr. Fairchild discusses in his direct testimony, ENSTAR has made an annualizing 17

adjustment to increase the General Service revenues to reflect the actual number of 18

ENSTAR customers during December 2015 and their corresponding usage. 19

Q. Why did ENSTAR make such an adjustment? 20

A. As I discussed earlier, ENSTAR is proposing to use a test year-end rate base, 21

including the test year-end level of plant. The adjustment to the General Service 22

revenues is what is termed as a “synchronization adjustment,” which is necessary to 23


match the income and expenses related to the test year-end balance of the rate base. 1

This adds revenue to match the income producing plant that has been added to serve 2

these new customers. In past cases, the Commission has required that revenues be 3

increased to reflect the test year-end customer count when a test year-end rate base is 4

used. Revenue adjustments for the number of customers at test year-end and their 5

corresponding usage to synchronize to a test year-end rate base was used to calculate 6

the revenue requirements for ENSTAR in Orders U-75-95(7) and U-84-59(15). 7

Q. Please discuss the adjustments shown on Schedule B. 8

A. As discussed in more detail by Dr. Fairchild, Schedule B shows the annualizing 9

adjustments to the large volume customer revenues (those of the power plants, 10

industrial customers, and the Titan liquefied natural gas facility) for the January 1, 11

2016 interim rate increase. 12

Q. Was an adjustment made to consider the effects of the Matanuska Electric 13

Association (“MEA”) power plant that began operating during the test year? 14

A. Yes. MEA’s Eklutna Generating Station (“EGS”) began operating during 2015. EGS 15

receives gas transportation service from ENSTAR, and ENSTAR began receiving 16

revenues from EGS transportation in December 2014. Prior to EGS becoming 17

operational, MEA received the bulk of its power needs from CEA. CEA continued to 18

partly supply MEA with power until May 1, 2015. After discussions with both CEA 19

and MEA, ENSTAR decided that the period of May 1, 2015, to April 30, 2016, would 20

be more representative of what to expect for EGS’s load and the load of the 21

SouthCentral Power Project (“SPP”), which is jointly owned by CEA and ML&P and 22

which was also partially used to supply MEA with power before May 1, 2015. The 23


adjustment for volumes and revenues for both plants is shown on Schedule C. Both 1

plants are currently served under ENSTAR’s Very Large Firm Transportation 2

(“VLFT”) rate schedule. 3

Q. Do these power plant customers oppose this adjustment? 4

A. Not to my knowledge. ENSTAR consulted with these customers on the 5

appropriateness of this adjustment, and none opposed it. 6

Q. What is the other adjustment shown on Schedule C? 7

A. Schedule C also shows a downward adjustment to ML&P’s volumes and revenues to 8

reflect the anticipated impact of its new generation Plant 2A currently under 9

construction and scheduled to come on-line in late Summer or Fall 2016. ML&P has 10

publicly stated that the new power plant will provide “significant natural gas 11

savings.” This affects ENSTAR because all of ML&P’s gas volumes are transported 12

on the ENSTAR system. 13

Q. Did ENSTAR discuss this adjustment with ML&P? 14

A. Yes. ML&P provided ENSTAR with its estimated annual gas requirement for its 15

entire native load after its new Plant 2A becomes operational, including its share of 16

SPP. ENSTAR took that estimate and reduced it by ML&P’s 30% share of the 17

adjusted SPP volumes, to arrive at the combined adjusted volumes for ML&P’s plants 18

1, 2 and 2A. ENSTAR provided these calculations and results to ML&P and CEA, 19

and neither objected to the adjustment. 20


Q. Are there other potential reductions in power plant usage that ENSTAR could 1

see during the period during the rate effective period? 2

A. Yes. As the Commission is aware from its investigation in Docket I-15-001, there 3

are ongoing efforts to achieve a more economic dispatch of the region’s electric 4

generation. On February 1, 2016, CEA and ML&P reported to the RCA about their 5

intent to develop a mutually-beneficial power pooling and joint dispatch arrangement 6

(“Anchorage Pool”). In their update, both utilities identified the benefits attainable 7

under economic dispatch, including estimated savings exceeding $10 million per 8

year. Since ENSTAR transports all of ML&P’s and SPP’s gas used for generation (as 9

well as MEA’s), any reduction in the combined usage resulting from economic 10

dispatch efforts will adversely affect ENSTAR if the reductions are not taken into 11

account during the course of this proceeding. 12

VIII. ADJUSTMENTS TO OPERATING EXPENSES 13

Q. Why you are proposing a series of expense adjustments for purposes of 14

determining ENSTAR’s revised base rates? 15

A. Base rates recover a utility’s non-gas costs of providing service to customers. Just as 16

test year revenue-related items often require adjustment to be representative of 17

expected rate-effective period conditions, test year expenses often must be adjusted 18

for the same reason. 19

Q. What adjustments to expenses are included in ENSTAR’s 275(a) filing? 20

A. Several adjustments to expenses are included in ENSTAR’s 275(a) filing. I will 21

discuss and sponsor the payroll expense adjustments (shown on Schedule D), the 22

credit card program adjustment (Schedule E), the outside professional services 23


adjustment (Schedule H), the insurance adjustment (Schedule I), and the regulatory 1

expense adjustment (Schedule J). 2

Q. Please discuss the Payroll Adjustment shown on Schedule D. 3

A. The purpose of the payroll adjustment shown on Schedule D is to account for changes 4

in the number, composition, and compensation of ENSTAR personnel compared to 5

the test year data. 6

Q. How did ENSTAR develop the Payroll Adjustments? 7

A. ENSTAR has broken the adjustment into three components. The first component 8

includes updating the test year level employee count, hours worked at current wage 9

levels, and other measurable compensation increases. The second component 10

includes normalizing the test year employee count and hours worked for vacancies 11

that occurred during the test year as well as positions that were eliminated or added 12

during the test year. The third component includes reflecting post-test-year known 13

and measurable changes for positions that have been eliminated or added. 14

Q. How was the first component of the Payroll Adjustment shown on Schedule D 15

developed? 16

A. ENSTAR’s test year pay and personnel rolls were reviewed on a position-by-position 17

and person-by-person basis. Wage rates were adjusted to reflect salary and wage 18

rates for each non-union position in effect at April 1, 2016. For union-represented 19

clerical and operations employees, wage rates were adjusted to reflect scheduled 20

grade changes through July 1, 2016, along with a 1.5% across-the-board wage 21


increase set out in the union contracts that becomes effective April 1, 2017.16 1

ENSTAR’s union contracts run to March 31, 2020, with scheduled increases effective 2

every April 1. ENSTAR did not include the increases scheduled to take effect in 3

April 2018 and April 2019 in this adjustment. If a position was vacated and refilled 4

during the test year, the wage rate of the most recent occupant of that position was 5

used. 6

After all of these adjustments were computed, the adjusted payroll was then 7

allocated to ENSTAR’s expense and capital accounts on the same basis as the 2015 8

payroll to determine the change in wages and salary costs for each expense account. 9

The summarized amounts for the expenses are shown in the column titled “Current 10

Salary Levels” on Schedule D. 11

Q. How was the second component of the Payroll Adjustment shown on Schedule D 12

developed? 13

A. As noted above, ENSTAR’s test year pay and personnel rolls were reviewed on a 14

position-by-position and person-by-person basis. For every position that was added 15

or partially vacant during the test year, ENSTAR adjusted the hours worked to reflect 16

what the normal annual number of hours would be for that position on an ongoing 17

basis. All of these positions were occupied for at least a portion of the test year. 18

Hours and amounts for positions that were eliminated during the year were removed. 19

For the added and vacated positions, the wage rate of the most recent occupant of that 20

position was used. After all of these adjustments were computed, the adjusted payroll 21

was then allocated to ENSTAR’s expense and capital accounts on the same basis as 22

16 The bargaining unit of the union representing the operations employees ratified the contract in

May 2016. Ratification of the contract by the bargaining unit of the union representing the clerical employees is pending.


the 2015 payroll to determine the change in wages and salary costs for each expense 1

account. The summarized amounts for the expenses are shown in the column titled 2

“Normalized Positions” on Schedule D. 3

Q. How was the third component of the Payroll Adjustment shown on Schedule D 4

developed? 5

A. The third component of the adjustment takes into account post-test year known and 6

measurable changes for positions that have been eliminated and positions that have 7

been added. Since December 31, 2015, ENSTAR has added one new position and 8

eliminated one position. For the added position, ENSTAR used a similar existing 9

position to allocate hours. The net effects of the added and eliminated positions are 10

shown in the column titled “Post-TY K & M Changes” on Schedule D. 11

Q. Are there other adjustments shown on Schedule D associated with the Payroll 12

Adjustment? 13

A. Yes. The three components described above were totaled (or netted as the case may 14

be) to arrive at a wage adjustment for each major expense category. Each wage 15

adjustment was then multiplied by an effective payroll loading rate (that includes 16

payroll tax rates and accruals for holidays and leave) to calculate the associated 17

payroll benefits and a total payroll expense adjustment amount for each major 18

expense category. The amount for administrative and general expenses (“A&G”) was 19

further reduced by 42.91% to reflect the amount of A&G that was capitalized or 20

charged to others (reimbursed) during the test year. The total adjustment to operating 21

expenses for all components of the payroll expense adjustment is $806,148. 22


Q. Are all components of the Payroll Adjustment reasonable? 1

A. Yes. As discussed above, it is a longstanding Commission policy that base rates 2

should recover the utility’s expected costs of providing service to customers in the 3

“rate effective period.” The adjustment of wages and salaries used in the first 4

component reflect the known changes in labor rates that ENSTAR will experience at 5

a minimum during the rate-effective period. The normalization of positions used in 6

the second and third components reflect the known changes to positions and hours 7

that ENSTAR has experienced and would expect to experience during the rate 8

effective period. Similar adjustments were made in previous ENSTAR rate cases, 9

Dockets U-84-59 and U-00-88, and were accepted by the Commission as part of the 10

revenue requirement in those dockets. Further, in Order U-88-18(14), the 11

Commission specifically approved the use of budgeted positions for the year after the 12

test year, rather than the actual employee counts and hours worked in the test year. 13

The Commission noted on page 35 of that Order that “it is desirable to use an 14

adjustment that does reflect, as closely as possible, the current operations.” 15

Q. Please discuss the Credit Card Expense Adjustment shown on Schedule E. 16

A. Prior to February 2016, ENSTAR did not accept credit card, debit card, or similar 17

payments directly from a customer. Historically, the Company arranged with a third 18

party to accept payments from customers by credit card, debit card and electronic 19

check for a fee ($4.50 per transaction) that was assessed by the third party directly to 20

the customer. ENSTAR did not receive any part of the fees charged for this service. 21

This method of collecting payments engendered many complaints from customers 22

who wanted to pay by credit and debit card without incurring a processing fee. 23


In its last rate case (Docket U-14-111), ENSTAR proposed an adjustment to 1

its operating expenses for the estimated net annual expense of accepting credit card 2

(and similar) payments without assessing a fee to the customer. The adjustment was 3

not opposed by RAPA or any other party to that case. After the Commission 4

accepted the stipulation that settled ENSTAR’s last rate case in October 2015, 5

ENSTAR moved forward with its proposal to modify its credit card payment 6

program. The Company selected a credit card processing vendor, modified its 7

customer information system, modified its tariff, and began directly accepting credit 8

card payments in February 2016. 9

The adjustment shown on Schedule E reflects the final negotiated transaction 10

fee of $1.39 per transaction, and ENSTAR’s expectation that approximately 84,000 11

credit card transactions per month will occur, which translates to an assumed use rate 12

of approximately 60%. ENSTAR’s projected use rate is based upon the experiences 13

of other utilities that currently accept credit cards without charging the customer a 14

related fee and the frequency of customer requests to use credit cards as a means of 15

payment. For example, approximately 42% of the customers of Anchorage Water 16

and Wastewater Utility pay with credit cards. In the first full month of the new credit 17

card payment program (March 2016), ENSTAR had almost 21,000 credit card 18

transactions, a four-fold increase from January 2016 when the old program was still 19

in effect. In May 2016, ENSTAR added more features to its program including the 20

ability for customers to enroll in recurring credit card payments and the ability for its 21

door taggers to accept credit card payments in the field. The net effect of the Credit 22


Card Expense adjustment is to increase test year expenses by $835,324, as shown on 1

Schedule E. 2

Q. Please describe the Outside Services Employed Adjustment included on 3

Schedule H. 4

A. Schedule H presents a five-year history of the level of ENSTAR’s outside 5

professional service expenses. Broken out by “Legal” and “Other Outside Services” 6

(consulting, audit, and other professional services), the schedule shows that the test 7

year costs in these categories are not representative of ENSTAR’s normal level of 8

these costs. In fact, the costs for the test year in these two categories were 9

significantly lower than any year over the past five years. Many of the costs in these 10

categories are incurred as a result of events that, if viewed in isolation, might be 11

considered extraordinary or nonrecurring, but when viewed from an overall operating 12

and historical perspective, are part of the routine cost of doing business that ebbs and 13

flows over time. Events, and the related costs, may be higher or lower in a specific 14

year depending on the occurrence of specific conditions, availability of resources, and 15

other unpredictable events. Looking at the level of these costs over time illustrates 16

why the utility would expect to incur a representative level of costs during the rate 17

effective period. 18

After reviewing the costs presented on Schedule H, ENSTAR came to the 19

conclusion that the four-year average of normalized legal and outside service costs is 20

representative of the level of such costs it will incur during the rate effective period. 21

That amount is further reduced by 42.91% to reflect the level of these costs that have 22


been capitalized or charged to others (reimbursed) during the test year. The total 1

adjustment to operating expenses adjustment is $147,516 as shown on Schedule H. 2

Q. Describe the Insurance Expense Adjustment shown on Schedule I. 3

A. Like any business, ENSTAR (together with SEMCO and SEMCO Energy Gas 4

Company) purchases property, liability, and various other insurance policies. Most of 5

those policies are purchased for twelve months of coverage, and many were renewed 6

during the latter portion of 2015 and early 2016. This adjustment calculates the 7

normalized annual expense for all the policies (including broker fees) purchased 8

and/or renewed during the past 12 months. The net effect of the Insurance Expense 9

Adjustment increases test year expenses by $33,239, as shown on Schedule I. 10

Q. Describe the Regulatory Commission Expenses Adjustment shown on Schedule 11

J. 12

A. Based on ENSTAR’s experience in Docket U-14-111, including the significant 13

number of parties and issues, excessive significant amount of discovery (including the 14

production of 28,000 pages of documents), as well as the Commission’s statement on 15

page 8 of Order U-14-111(18) that it expects a “robust record” to be developed and 16

plans to fully adjudicate this rate case, ENSTAR estimates that the Company will 17

incur $1,800,000 in associated out-of-pocket expenses. In keeping with the 18

Commission’s normal policy for rate case expenses, I propose that these costs be 19

amortized over a three-year period. At the conclusion of this case, ENSTAR will 20

true-up its rate case expenses with the estimate. 21

Because the settlement in Docket U-14-111 was not ordered by the 22

Commission until September 2015, the test year expenses included only three months 23


of amortization of the Docket U-14-111 rate case expenses. ENSTAR is normalizing 1

the test year rate case expenses to reflect a full year of amortization for that case. The 2

combined effect of these two items is to raise test year operating expenses by 3

$697,260 as shown on Schedule J. 4

IX. RATE BASE ADJUSTMENTS 5

Q. Please discuss the presentation of rate base on page 2 of Attachment B to 6

ENSTAR’s rate filing. 7

A. As I discussed above, the first column of the rate base schedule presents the 13-8

month average rate base amounts for each account. The details of the average 9

amounts are shown in Schedule N. The next column shows the pro forma 10

adjustments. With the exception of the elimination of the acquisition adjustment, all 11

of the pro forma adjustments that reference Schedule N adjust the respective accounts 12

to test year-end balances. 13

Q. Please discuss the adjustments to regulatory assets. 14

A. The stipulation that settled ENSTAR’s 2009 test year rate case (Dockets U-09-69/U-15

09-70) provided that ENSTAR could not include the costs it incurred on the proposed 16

Bullet Line pipeline from the North Slope in its rate base in future proceedings.17 The 17

U-14-111 Stipulation provided that while ENSTAR is permitted to amortize amounts 18

for litigation costs of the Anchor Point Pipeline and the Long Term Gas Supply 19

Study, it could not include the unamortized amounts in rate base.18 20

17 Order U-09-69(10)/U-09-70(10), Appendix at 8, n.13.

18 Docket U-14-111 Stipulation at 9.


Q. Has ENSTAR included any unamortized rate case expenses in its rate base 1

request? 2

A. Consistent with the treatment of other expenditures that are capitalized and recovered 3

through depreciation or amortization over their useful lives, ENSTAR believes that it 4

should be able to capitalize rate case expenses and include them as a regulatory asset 5

in rate base so that it may earn a carrying cost on its investment. A fundamental 6

principle of utility regulation is that a utility is entitled to earn a return on its 7

investment in both tangible and intangible assets. However, ENSTAR is also aware 8

of the Commission precedent on this matter and has thus not included capitalized rate 9

case expenses in rate base. 10

X. HOMER EXTENSION 11

Q. What is the Homer Extension? 12

A. The Homer Extension is a project originally proposed to the Commission by 13

ENSTAR in 1996, but which generated increasing support from the communities of 14

Kachemak City and Homer in 2010. Given the high cost of fuel oil and propane in 15

Homer, a large group of residents and business owners began lobbying ENSTAR and 16

the State of Alaska to revive efforts to bring natural gas to the Homer area and help 17

reduce the cost of space and water heating. This was made possible, in part, due to 18

the natural gas discoveries at the North Fork gas field and made commercially 19

available by Anchor Point Energy, LLC in 2009, and when ENSTAR extended its 20

system to Anchor Point to obtain access to the North Fork field. Ultimately, it 21

resulted in an approximately 22-mile distribution pipeline transporting natural gas 22

from ENSTAR’s transmission system at Anchor Point, through Homer, and 23


terminating at the eastern boundary of Kachemak City. Construction began in 2012 1

and was completed in the fall of 2013. 2

Since that time, ENSTAR has connected over 1,600 residential and 3

commercial customers to natural gas. Access to clean burning natural gas has helped 4

to reduce the annual utility costs for residential customers, and saved the City of 5

Homer 60-70% on annual energy costs for buildings it has converted. 6

Q. How was the Homer Extension expected to be funded? 7

A. As detailed in TA 226-4, the expected cost of the Homer Extension in July 2012 was 8

$10,700,000. In May 2012, Governor Parnell signed a capital budget bill that 9

included a state grant of $8,150,000 to the City of Homer for Homer’s South 10

Peninsula Natural Gas Pipeline project (the “Homer Grant”), with the understanding 11

that the remaining amount needed for the extension would be funded by the $1.00 per 12

Mcf “Homer Extension Surcharge” already in ENSTAR’s tariff.19 The City of 13

Homer committed the Homer Grant funds to ENSTAR in a contribution-in-aid of 14

construction (CIAC) for the Homer Extension (the “Homer CIAC”). In TA 226-4, 15

ENSTAR amended the “Homer Extension Surcharge” provision to reflect the Homer 16

CIAC.20 As approved, the provision provides for a $1.00 per Mcf surcharge to be 17

“applied to all Gas Sales and Transportation Service bills for Gas delivered in the 18

19 The original tariff provision had been approved by the Commission in Order U-03-84(7), dated

March 23, 2004. That Order noted that the $1.00 per Mcf surcharge “…permits a delayed recovery of the contribution customers must make for ENSTAR to build its line extension from Anchor Point to Homer, termed CIAC. This CIAC is normally required to be paid before a customer can receive service under ENSTAR’s current tariff….” The Order also notes that the surcharge was expected to be in place approximately ten years. p.7.

20 TA 226-4 was approved in Letter Order L1200583 dated August 17, 2012.


Homer Extension Surcharge Area until the Net Total Actual Costs associated with the 1

Anchor Point to Homer pipeline (the “Homer Extension”) are recovered.”21 2

Net Total Actual Costs include the total net construction costs less the Homer 3

CIAC, plus rate of return and income taxes. With final construction costs of 4

$11,780,072 and the $8,150,000 Homer CIAC, a Surcharge CIAC balance totaling 5

$3,630,072, plus return and taxes, was to be funded by the surcharge. 6

Q. Is the $1.00 per Mcf surcharge sufficient to collect this? 7

A. No. While ENSTAR has collected $308,190 in the surcharge between the time the 8

Homer Extension Surcharge Area began in October 2013 through December 31, 9

2015, it has not been sufficient to cover the carrying costs on ENSTAR’s net 10

investment in the Homer Extension. Further, it does not appear that the surcharge will 11

be sufficient to retire the entire amount of the Surcharge CIAC. 12

Q. What is ENSTAR’s proposal? 13

A. ENSTAR’s proposal is to remove the Surcharge CIAC and related amortization 14

recorded since October 2013 from ENSTAR’s books and include it in ENSTAR’s 15

general rate base. ENSTAR would then have a regulatory asset of $1,143,412 that 16

would be the net of (1) the surcharge collections; (2) CIAC amortization; (3) rate of 17

return; and (4) income taxes recorded from October 2013 through December 2015, 18

which it will amortize over 7.75 years, beginning December 31, 2015, which 19

represents the time remaining on the original ten-year period to collect the surcharge. 20

21 ENSTAR Tariff Section 2403, Second Revision of Sheet 228, effective August 16, 2012.


Q. Does ENSTAR propose to continue to collect the Homer Expansion Surcharge? 1

A. Yes. Because the existence of the surcharge was integral to securing the Homer 2

Grant, ENSTAR believes it should continue to be charged to Homer customers for the 3

next 7.75 years in order to further contribute to the return, taxes, and amortization of 4

the regulatory asset. 5

Q. How would the surcharge be treated? 6

A. ENSTAR proposes to treat the surcharge as additional Miscellaneous Income to help 7

offset the impact of moving the Surcharge CIAC amount and regulatory asset into 8

rate base and the amortization of the regulatory asset. As shown on Schedule N, 9

ENSTAR has made pro forma adjustments to the test year to reflect this proposed 10

treatment. 11

Q. What is the impact of this proposal on the average General Service G1 12

customer? 13

A. ENSTAR’s proposed treatment of the Homer Extension has the effect of increasing 14

the bill of the average General Service G1 customer approximately $0.22 per month. 15

XI. COST-OF-SERVICE STUDY AND RATE DESIGN 16

Q. How does the structure and composition of ENSTAR’s system impact its COS 17

study and rate design? 18

A. ENSTAR’s system has been, and continues to be, functionally designed and operated 19

as an integrated delivery network. As such, a customer need not be directly or 20

physically connected to a specific item of plant in order to benefit from its existence. 21

The Commission adopted this approach in prior dockets (i.e., Dockets U-83-38 and 22

U-87-2), and nothing has changed. 23


For example, ENSTAR’s Kenai to Anchorage pipeline can reach capacity 1

during high flow periods. Improvements to increase supply access and capacity on 2

the Kenai to Anchorage pipeline not only benefit those who receive the gas molecules 3

from that line, but it reduces the likelihood that volumes flowing on the Beluga to 4

Anchorage pipeline will have to be diverted to higher priority use. 5

Q. Do customers not served directly from ENSTAR’s Kenai to Anchorage pipeline 6

receive benefits from the entire system? 7

A. Yes. In addition to the simple example that I presented above, there are the obvious 8

benefits of economies of scale, diversity of supply, system support, and gas 9

balancing, to name a few. Further, ENSTAR’s system interconnects with the Hilcorp 10

(“Harvest Alaska”) Kenai Beluga Pipeline (“KBPL”) at several points, forming a 11

complete loop around Cook Inlet. As a result, gas molecules can find their way from 12

Anchor Point to Anchorage and Beluga, along both sides of Cook Inlet. I note that 13

Hilcorp generally apportions its individual field production among all of its gas 14

contracts, which means that its customers on ENSTAR’s Beluga to Anchorage 15

pipeline on the west side of Cook Inlet are likely receiving allocations of production 16

from Hilcorp fields that are connected to ENSTAR’s Kenai Peninsula system on the 17

east side. In other words, ENSTAR’s and KBPL’s systems are integrated and benefit 18

customers located along the pipelines, all the way around Cook Inlet. 19

Q. Historically, why has ENSTAR extended its transmission system? 20

A. The primary driver for ENSTAR’s largest transmission system extensions has been 21

access to gas supply. That was true for the construction of the 100-mile Beluga to 22

Anchorage pipeline in the 1980s, and it was true for the construction of the Anchor 23


Point Pipeline (“APPL”, also referred to as the South Peninsula Pipeline). Capacity is 1

obviously a consideration, but the largest single cost of a pipeline is getting a trench 2

dug to install a pipe of any size. Sizing of pipe is incremental, meaning that the costs 3

are driven less by peak capacity needs than by the need to extend pipelines to the 4

sources of gas that all of our customers, including the transportation customers, 5

demand. 6

Q. Does ENSTAR build pipelines exclusively for use in serving its gas supply 7

customers? 8

A. While ENSTAR’s original pipelines (and even its Beluga to Anchorage pipeline) 9

were constructed in an era when ENSTAR supplied the gas to every customer it 10

served, including the power plants, ENSTAR has had transportation-only customers 11

on its system since 1989. Virtually every pipeline and gas field it is connected to can 12

(and often does) provide gas for ENSTAR’s gas sales customers, as well as gas that 13

ENSTAR transports for others. 14

Q. Does that include the APPL? 15

A. Yes. Transportation customers are using APPL, and gas transported on it has been 16

delivered to ENSTAR’s power customers. Cook Inlet Energy (“CIE”), as an 17

ENSTAR transportation customer, has shipped gas on APPL. This gas was sold to 18

AEEC/HEA and CEA, as well as industrial customers since early 2014. In May 2016, 19

AEEC/HEA added an APPL receipt point to its transportation service agreement with 20

ENSTAR and became a shipper on APPL itself. APPL is used by transportation 21

customers, and it is not unreasonable to allocate a share of the costs to them. 22


Q. Are there others besides CIE with production on APPL? 1

A. Yes. Hilcorp, which generally allocates its individual field production among all of its 2

contracts, has current production on APPL and is planning more. In 2015, BlueCrest 3

Energy funded ENSTAR’s construction of a lateral to bring production from the 4

Cosmopolitan field into APPL, as detailed in Docket U-15-118. 5

Q. Does the first time use of a pipeline to deliver gas for sales customers dictate its 6

future use and cost allocation? 7

A. No. As I discussed above, while a good portion of ENSTAR’s transmission system 8

predates transportation service, it is now all available and used to provide 9

transportation service. 10

Q. In past rate cases, some of ENSTAR’s customers have argued for a rate design 11

that excludes significant portions of ENSTAR’s plant for them. What is 12

ENSTAR’s view on that sort of cost allocation and rate design? 13

A. ENSTAR continues to believe that a “postage stamp” rate principle is appropriate and 14

reflects its integrated system. ENSTAR notes that this is the type of cost allocation 15

and rate design that the Commission has traditionally approved and encouraged, not 16

just for ENSTAR, but for most utilities in Alaska. As an example, every one of the 17

power customers ENSTAR serves has postage stamp rates for its utility operations, as 18

does Fairbanks Natural Gas, which also receives its gas for its LNG plant from 19

ENSTAR’s system. The Commission also accepted a postage stamp rate settlement 20

in the 2014 KBPL Docket. As explained above, all customers receive a benefit from 21

the entire system. 22


Q. Did ENSTAR prepare a COS study to support its requested rates? 1

A. Yes. ENSTAR witness Dr. Fairchild was asked to prepare a fully-allocated COS 2

study for ENSTAR using the revenue requirement developed in the year-end rate base 3

275(a) filing (Attachment B-2). The COS is attached to his testimony as Exhibit 4

BHF-2. He has followed the COS methodology established by the RCA (including 5

its predecessor agency, the Alaska Public Utilities Commission) in ENSTAR’s earlier 6

rate design proceedings (Dockets U-87-2 and U-87-42), including using the method 7

to allocate transmission-related costs among customer classes approved in those 8

cases. He has also used the General Service customer classes, as well as the large 9

firm and interruptible transportation classes agreed to in Dockets U-09-69/U-09-70, 10

and the mid-sized firm transportation class agreed to in Docket U-14-111 in his study. 11

Based upon the discussions ENSTAR has recently had with its power plant 12

customers, Dr. Fairchild also included ML&P with SPP and MEA in the VLFT class. 13

Q. What allocation method was used to apportion transmission-related costs among 14

customer classes? 15

A. An allocation factor based on an equal weighting of each customer class contribution 16

to coincident system peak demand and average day demand (sometimes referred to as 17

the “Seaboard” method) was used to allocate transmission-related costs among 18

ENSTAR’s various customer classes. Because ENSTAR’s pipeline system is an 19

integrated system, designed to access gas supplies and meet peak loads, the 20

Commission determined in Order U-87-2(4)/U-87-42(2) that this was the appropriate 21

allocation method for ENSTAR’s transmission system. 22


Q. What is rate design? 1

A. Rate design is the way in which base rates are calculated to collect the revenue 2

requirement assigned to a utility’s various customer classes. 3

Q. Are you proposing rates based on each customer class full cost of service? 4

A. No. Because the impact of moving to the full cost of service would be especially 5

burdensome on the VLFT (i.e., power) and interruptible transportation service 6

customer classes, ENSTAR is proposing to continue the “gradualism” concept that 7

was agreed to in arriving at the U-14-111 Stipulation. In the Docket U-14-111 8

Stipulation, the increase in rates for any customer class was limited to 150% of the 9

overall percentage increase in base rates for the system as a whole, with the 10

difference being proportionally reallocated to the other customer classes. ENSTAR 11

used this same 150% cap to arrive at its proposed rates here. 12

Q. What is the maximum amount of rate increase? 13

A. As shown on page one of Dr. Fairchild’s COS study (Exhibit BHF-2), the maximum 14

increase in base rates for any rate class is 21.52%, which is 150% of the total system 15

increase in base rates of 14.35%. 16

Q. What factors, other than cost of service, did you consider in designing rates? 17

A. The other factors considered in designing rates were: 18

value of service; 19

promoting the wise use of energy; 20

matching costs and revenues; 21

lessening the impact of high winter bills; and 22

public acceptability and understandability. 23


Q. Why should value of service be considered? 1

A. Conceptually, utility base rates should not be set higher than the value of service to a 2

particular group of customers, unless the cost of providing service exceeds the value 3

by a significant amount. If the base rate charged to a class of customers is higher than 4

the value of service to that class, those customers may seek alternative supplies. As a 5

result, the fixed costs of operating the utility would be spread over a smaller base and 6

increased costs would be borne by other future customers. ENSTAR aims to ensure 7

that its rates reflect the value of its service to its customers. If base rates are set 8

significantly below the value of service, wasteful use of a premium fuel will be 9

encouraged. 10

Q. Why should conservation be encouraged? 11

A. As a matter of State policy, waste of any natural resource is discouraged. 12

Furthermore, the wise use of natural gas results in more gas availability for future 13

consumption. The Company has always encouraged the use of natural gas, but has no 14

interest in seeing this premium fuel wasted. 15

Q. Why is the matching of costs and revenues important in the rate design? 16

A. Except for the cost of gas, the vast majority of the costs incurred to provide service to 17

customers are essentially fixed. Capital-related costs (i.e., depreciation, return, and 18

income taxes) do not vary with usage, nor do most operating expenses. For efficient 19

use of resources and capital, a utility needs a revenue stream that matches its expense 20

outflow as closely as possible. Base rates should be designed to match cost 21

incurrence. 22


Q. Why should the effect of high winter bills on customers be considered in 1

designing rates? 2

A. There are a number of reasons. ENSTAR’s customers use more energy to heat their 3

homes in the winter than they do in the summer, by a factor of at least five. The 4

difference between winter and summer bills can be significant, especially for 5

customers on limited or fixed incomes. Most people do not see seasonal increases in 6

their income. In fact, those who do have seasonal jobs tend to enjoy seasonal income 7

in the summer, not in the winter when they have to face the higher bills for home 8

heating. For these reasons, the effect of rate design on winter bills should be taken in 9

account. 10

Q. Is ENSTAR proposing a change in the way its General Service rate classes are 11

defined? 12

A. No. 13

Q. What is the rate design ENSTAR is proposing for the General Service G1-G4 14

rate classes? 15

A. In Dockets U-09-69 and U-14-111, the parties agreed to a rate design that allocated 16

about 50% of the revenue requirement for each customer class to the fixed monthly 17

customer charge and 50% to a distribution (volumetric) charge. ENSTAR is aware 18

that fixed monthly customer charges can be complicated, and some may cause 19

confusion through repeated increases to that portion of the bill. As a result, ENSTAR 20

is proposing to limit the increase in the fixed monthly charges for all four General 21

Service classes to the requested 5.82% across-the-board interim increase. Any 22

difference between the interim and final increases in the class revenue requirements 23


for the four General Service customer cases would be allocated to the volumetric 1

portion of the rate. 2

Q. What rates is ENSTAR proposing for the General Service classes? 3

A. The tables below sets out ENSTAR’s proposed interim and permanent rates its four 4

General Service customer classes. 5

Proposed Rates-General Gas Sales Service G1-G4

Rate Class

Interim Monthly

Customer Charge

Interim Distr. (Volumetric)

Rate (Per Mcf)

Perm. Monthly

Customer Charge

Perm. Distr. (Volumetric)

Rate (Per Mcf)

G1 $17.00 1.3420 $17.00 $1.6280

G2 $37.00 $1.1742 $37.00 $1.2131

G3 $120.00 $1.1814 $120.00 $1.2319

G4 $570.00 $0.8939 $570.00 $0.9360

Q. What other rates is ENSTAR proposing to change? 6

A. ENSTAR is proposing to change its rate schedules for the mid-sized firm 7

transportation and large transportation customers, including the power plant and 8

interruptible customers. While all of these rate categories continue from the rate 9

classes that were agreed to in the last case, ENSTAR has made some changes to the 10

design and offerings based upon discussions with its customers. 11

Q. Please discuss the rate design for the mid-size firm transportation (“MSFT”) 12

class. 13

A. First, ENSTAR is not proposing any change to the structure of the MSFT rate 14

schedule, which will continue to apply to both Titan Alaska LNG, LLC and 15

AEEC/HEA’s Soldotna Combustion Turbine power plant. Test year data for both 16


customers in the MSFT class was used in developing the cost allocation and rate 1

design found in Dr. Fairchild’s Exhibit BHF-2. 2

Q. Please discuss the rates for other power plant customers. 3

A. In our discussions with power customers, ENSTAR was asked to propose a rate 4

structure that had the same marginal transportation rate to all of the power plants in 5

the Anchorage area. To that end, ENSTAR is proposing to move ML&P from its 6

own individual rate to the VLFT rate schedule. In addition, ENSTAR is proposing to 7

eliminate the declining block structure in the existing VLFT tariff, and replace it with 8

a flat, or uniform, volumetric rate. This rate structure results in every Mcf moved 9

under the VLFT rate schedule having the same marginal volumetric rate. 10

Q. Have you discussed this with ML&P? 11

A. Yes. ML&P provided ENSTAR with data to allow it to be included in the VLFT rate 12

schedule and advised ENSTAR to use a contract demand of 16,000 Mcf in the 13

calculation of the rates. 14

Q. Is ENSTAR proposing anything else in response to discussions with the 15

Anchorage power customers? 16

A. Yes. Earlier in my testimony, I discussed CEA’s and ML&P’s intent to develop the 17

Anchorage Pool, a mutually-beneficial power pooling and joint dispatch arrangement. 18

In conjunction with that effort, ENSTAR was asked to develop a rate classification 19

for members of the Anchorage Pool that would allow them to: (1) move gas to the 20

major Anchorage Pool power plants for the same marginal transportation rate, and 21

(2) effectively share the contract demand between the members of the pool so that 22

they could move loads among the most efficient units available without incurring 23


penalties for exceeding contract demands. During May 2016, ENSTAR worked with 1

both CEA and ML&P to arrive at a proposed rate structure that would accommodate 2

their request and encourage the efficient use of natural gas and power generation 3

resources. 4

Q. Please describe the proposed rate schedule. 5

A. ENSTAR is proposing a new Anchorage Pool Firm Transportation Service rate 6

schedule (Schedule APFT). The schedule is identical to ENSTAR’s VLFT rate 7

schedule with the following exceptions: (1) it is only available to locations that are 8

part of the yet to be formed mutually-beneficial power pooling and joint dispatch 9

arrangement for the Anchorage area (in whatever form that takes); (2) locations that 10

elect to take service must enter into a new transportation service agreement that 11

specifically references the APFT rate schedule; (3) an APFT customer will not be 12

subject to excess demand penalty on a given day so long as the combined volumes for 13

all APFT customers on that given day do not exceed the combined contract peak 14

demand for all APFT customers; and (4) as with ENSTAR’s other rate schedules, 15

service to a APFT location is exclusive (it cannot also be served at the same time 16

under a different rate schedule). 17

Q. Was this specific proposal discussed with CEA and ML&P? 18

A. Yes. It was developed at a meeting with representatives of both of the companies on 19

May 19, 2016. 20

Q. Would it be only available to CEA and ML&P? 21

A. No. It would be available to any member of the yet to be formed mutually-beneficial 22

power pooling and joint dispatch arrangement for the Anchorage area. 23


Q. Is ENSTAR making any changes to its other large transportation rate structure? 1

A. Yes. In response to requests to simplify its rate schedules, ENSTAR is also 2

eliminating the declining block rate design for its Interruptible Industrial 3

Transportation Service (Schedule IIT) and Interruptible Transportation Service to 4

Storage (Schedule ITS). Schedule IIT will retain a minimum bill for the first 100,000 5

Mcf delivered each month, but all volumes above 100,000 Mcf per month will be at 6

the same volumetric rate. For Schedule ITS, there will be a single volumetric rate for 7

all volumes moved under the rate schedule, and a minimum annual charge is retained. 8

Q. Is ENSTAR proposing any other changes in what it charges transportation 9

customers? 10

A. Yes. Also in response to requests to simplify its fee schedules, ENSTAR is proposing 11

to eliminate the $240 monthly administrative fee that is assessed to each shipper as 12

set forth in Section 2561b of ENSTAR’s Tariff. 13

Q. Are you filing tariff sheets showing the rate structures you are proposing? 14

A. Yes. The revised tariff sheets for the interim rates are included as Attachment E to 15

TA 285-4 and the revised tariff sheets for the permanent rates are included as 16

Attachment F to TA 285-4. 17

XII. REQUEST FOR INTERIM RATE RELIEF 18

Q. Is ENSTAR requesting an interim rate increase? 19

A. Yes. ENSTAR’s TA 285-4 filing includes a request for an additional interim base 20

rate increase (i.e., above the interim that went into effect January 1, 2016 pursuant to 21

the Docket U-14-111 stipulation) of 5.82% (approximately 1.6% on total revenues 22

including gas cost), which is expected to generate about $4.8 million more in annual 23


base rate revenues. ENSTAR is not seeking interim recovery of the full revenue 1

deficiency that the test year-end rate base 275(a) filing in Attachment B demonstrates. 2

Without Commission approval of interim and refundable rates, the current 3

inadequate rates would remain in effect until the conclusion of these proceedings and 4

the issuance of a final order, because rates cannot be collected retroactively; this 5

process could take up to 15 months. Assuming the Commission will later approve 6

some or all of ENSTAR’s proposed permanent increase, interim rates protect 7

ENSTAR from irreparable harm. Historically, the Commission has preferred that rate 8

increases be implemented incrementally to mitigate the impact on customers. 9

Therefore, it is desirable to have ENSTAR’s proposed base rate increase implemented 10

in two smaller steps (interim and permanent) rather than one larger increase. Finally, 11

if the Commission grants interim rate relief, ENSTAR’s customers will be adequately 12

protected because ENSTAR will refund any excess amounts to its customers, with the 13

statutory simple interest rate of 10.5% per annum, commencing on the effective date 14

of the interim increase. 15

Q. Has ENSTAR prepared a refund plan in the event that the final approved rate 16

increase is less than the interim? 17

A. Yes. The refund plan is included as Attachment D to TA 285-4 and is based upon the 18

plan ENSTAR filed with the Commission in its last two rate cases. 19


Q. Are you providing a schedule showing how the interim rates were calculated and 1

tariff sheets for the interim rates? 2

A. Yes. Exhibit DMD-3 is a schedule showing the across-the-board application of the 3

requested interim rate increase. As I noted earlier, the tariff sheets for the interim rate 4

increase are included as Attachment E to TA 285-4. 5

Q. How were the interim rates calculated? 6

A. In keeping with Commission policy on interim increases, the additional interim base 7

rate increase of 5.82% was developed using the 13-month average rate base revenue 8

requirement shown in Attachment C rather than the test year-end rate base revenue 9

requirement shown in Attachment B. For the additional interim increase, ENSTAR is 10

requesting rates sufficient to recover only one-half of the deficiency shown on page 4 11

of Attachment C. The interim increase is applied on an across-the-board basis to 12

ENSTAR’s current base rates (i.e., the Step 2 (interim) rates in the U-14-111 13

Stipulation that became effective January 1, 2016). 14

Q. When is ENSTAR requesting this additional interim increase be effective? 15

A. As set out in TA 285-4, ENSTAR is requesting that the additional interim increase be 16

effective as of August 1, 2016, which is the beginning of the first month following the 17

statutory 45-day review period. 18

XIII. MOVING STORAGE FEES FROM COST OF GAS STORED 19

Q. What kind of direct storage fees does ENSTAR incur? 20

A. ENSTAR has a FSS agreement with CINGSA and incurs reservation fees, capacity 21

fees, injection fees and withdrawal fees under CINGSA’s tariff. 22


Q. Is ENSTAR proposing a change to the way reservation and capacity fees related 1

to stored gas are treated? 2

A. Yes. Currently, ENSTAR’s GCA provision (Tariff Section 708) provides that the 3

reservation and capacity fees incurred to store gas in CINGSA are components of the 4

average cost of stored gas and are directly booked into the Gas Stored account – 5

FERC Account 164.1. The provision currently only allows recovery of stored gas 6

costs when, and to the extent that, gas is withdrawn from storage. ENSTAR is 7

proposing to make the reservation and capacity fees related to stored gas a specific 8

component and cost element of the GCA and the weighted average unit cost of gas 9

(“WACOG”) calculation. ENSTAR is also asking that the Commission approve this 10

change to be effective at the beginning of the third month following the end of the 11

statutory 45-day review period (October 1, 2016), and not wait until this case is fully 12

resolved. 13

Q. Please explain in more detail how the recovery of these storage fees is currently 14

working. 15

A. As I noted above, the reservation and capacity fees related to stored gas are 16

components of the average cost of stored gas and thus, are only recovered as gas is 17

withdrawn from storage. Stored gas costs pass through the gas cost balance account 18

(“GCBA”) when gas is withdrawn from CINGSA by multiplying the withdrawn 19

volumes by the average unit cost of gas stored, which is calculated as of the end of 20

the month prior to the month the gas is withdrawn. The average unit cost of gas 21

stored is calculated as of the end of the month prior to the month the gas is 22

withdrawn. In calculating the GCA each year, ENSTAR estimates the amount and 23


cost of gas to be withdrawn from storage for the prospective 12-month period (July 1-1

June 30). 2

Q. Why are you proposing this change? 3

A. ENSTAR uses its storage for both peak management and gas supply management, 4

and consistent with industry norm, it does not fully cycle its gas in storage every year. 5

This means that a portion of each year’s storage reservation and capacity fees has 6

remained in the Gas Stored account, which has resulted in the cost of stored gas 7

increasing beyond the level of the average cost of gas purchased and injected into 8

storage. Effectively, customers are paying a portion of previous years’ reservation 9

and capacity fees when gas is withdrawn. 10

The Company’s proposal provides that each year’s reservation and capacity 11

fees are recovered in that year’s GCA calculation. The proposed methodology better 12

matches the annual benefit of having the storage available to manage gas supply and 13

winter demands with the annual cost of having storage available. Furthermore, this 14

new methodology eliminates an inter-generational gap that currently exists, ensuring 15

that current customers pay fees related to the availability of storage to them. 16

Q. If approved, how will this proposal affect the cost of stored gas? 17

A. This proposed change will allow the average cost of gas stored to decrease over time 18

from what it would have been as it becomes more aligned with the costs of gas 19

purchased and injected into CINGSA. If the Commission does not approve the 20

proposed change, the average cost of gas stored will steadily increase over time. 21

ENSTAR has modeled the effect of the change using forecasted weather and 22

consumption. The table below shows the effect of moving the reservation and 23


capacity fees effective October 1, 2016, on ENSTAR’s average cost of gas sold and 1

average cost of stored gas. As demonstrated below, the average cost of gas sold 2

increases as the reservation and capacity fees are fully recovered on an annual basis, 3

while the average cost of stored gas decreases over time. 4

With Reservation and Capacity Fees

Average Cost of Gas Supply /

Mcf Average Cost of Gas Sold

Average Cost of Stored Gas / Mcf

2016 6.41 6.80 12.86 2017 6.68 7.35 13.71 2018 7.13 7.70 14.38 2019 7.52 8.17 14.59 2020 7.67 8.24 14.80

Without Reservation and Capacity Fees effective October 1, 2016

Average Cost of Gas Supply /

Mcf Average Cost of Gas Sold

Average Cost of Stored Gas / Mcf

2016 6.41 6.93 12.75 2017 6.68 7.74 11.62 2018 7.13 7.96 10.06 2019 7.52 8.24 9.01 2020 7.67 8.32 8.36

Q. Does this change have any direct effect on the revenue requirement being 5

proposed? 6

A. No. It only relates to costs that are recovered via the GCA. Over time, it should 7

result in the average cost of stored gas (and thus, the total cost of stored gas) being 8

lower than it otherwise would have been. 9

Q. How do the other CINGSA utility customers treat the reservation and capacity 10

fees related to stored gas? 11

A. ML&P, HEA and CEA all recover the CINGSA reservation and capacity charges in 12

the same way as ENSTAR is proposing to do in this filing. The costs are specifically 13


set out in each electric company’s fuel and purchase power adjustments. CEA’s 1

provision also provides for the recovery of interruptible storage service (ISS) fees. 2

Q. Is ENSTAR’s proposed treatment of the storage reservation and capacity 3

charges consistent with the way many utilities treat similar storage fees in the 4

Lower 48? 5

A. Yes. In footnote 7 on page 7 of TA 262-4 transmitted with ENSTAR’s last rate case 6

filing (Docket U-14-111), ENSTAR provided the following case cites to several 7

Lower 48 utilities that included stored gas in rate base: Re Peoples Gas Light Coke 8

Company, Illinois Commerce Commission, 63 P.U.R.4th 304, 310 (August 30, 1984); 9

Re Indiana Gas Company, Inc., Indiana Public Service Commission, 57 P.U.R.4th 10

464, 472, 474 (January 18, 1984) (includes discussion of the appropriateness of using 11

a 13-month average balance); Re Northern Illinois Gas Company dba Nicor Gas 12

Company, Illinois Commerce Commission, 272 P.U.R.4th 161, 180 (March 25, 13

2009); Re Piedmont Natural Gas Company, Inc., North Carolina Utilities 14

Commission, 50 P.U.R.4th 132, 136 (November 30, 1982); and, Re Minnegasco, Inc., 15

Minnesota Public Utilities Commission, 143 P.U.R.4th 416, 428 (May 1993). 16

ENSTAR has reviewed the GCA provisions and/or filings for each of the 17

utilities listed (or their successor utilities) to determine how such costs are treated. 18

Each of these utilities that incurred a fixed fee for storage costs included those fees in 19

its gas cost adjustment charge in a manner similar to ENSTAR’s proposal. 20


Q. Why didn’t ENSTAR propose to handle the fees in this way when it originally 1

modified its GCA tariff provision to include storage fees? 2

A. At the time ENSTAR modified its GCA tariff provision to incorporate storage fees, it 3

was revising its GCA on a quarterly, not annual, basis. The storage reservation and 4

capacity fees are charged monthly. Directly recovering them through each quarter’s 5

GCA would have resulted in summer rates that would have been significantly higher 6

than the rates during winter months, due to the difference in gas volumes caused by 7

seasonal fluctuations. Now that the GCA is filed on an annual basis, the seasonal 8

fluctuations of gas volumes will not affect the averaging of the reservation and 9

capacity fees for the year. 10

Q. If this change has no direct effect on the rates being proposed in this rate case 11

filing, why is ENSTAR proposing the change in this filing? 12

A. In Order U-14-111(18), the Commission said that it expected a record in this filing 13

concerning “the appropriate revenue requirement treatment for reservation and 14

capacity fees related to stored gas.” Therefore, ENSTAR is proposing this change in 15

response to the Commission’s directive. 16

Q. Should these fees be recovered in ENSTAR’s revenue requirement rather than 17

its GCA? 18

A. No. Recovery in its GCA, as proposed, is the most appropriate method to recover 19

these costs. These costs are gas supply-related costs and are currently being 20

recovered via the GCA as the gas is being withdrawn out of storage. Prior to the 21

development of CINGSA, storage costs were bundled services embedded in the price 22

contained in ENSTAR’s gas supply contracts which were and are recovered via the 23


GCA. In fact, some of ENSTAR’s current contracts still have service elements that 1

are equivalent to and complement ENSTAR’s contracted storage. Finally, as noted 2

above, CEA, HEA and ML&P recover their storage reservation and capacity fees via 3

their cost of power adjustments, not via their revenue requirements. ENSTAR’s 4

proposal is consistent with how these costs have been treated by the Commission and 5

by regulatory authorities in other jurisdictions. 6

Q. Why is ENSTAR seeking approval of this change to be effective on October 1, 7

2016? 8

A. ENSTAR is seeking approval of the change to be effective at the beginning of the 9

third month following the forty-five day review period in order to change to the new 10

methodology of recovering the storage reservation and capacity fees as soon as 11

possible, but give the Commission sufficient time to review the request. The earlier 12

ENSTAR is able to recover these charges through the GCA calculation, the sooner 13

the average cost of gas stored will decrease and the sooner ENSTAR’s customers will 14

benefit from the elimination of the intergenerational allocation of benefits and costs 15

of CINGSA. 16

Q. Has ENSTAR prepared the revisions to its GCA provision necessary to reflect 17

this change? 18

A. Yes. The tariff sheets with revisions to Section 708 are included as Attachment G to 19

TA 285-4. Also included is a revised determination of the gas cost adjustment (Tariff 20

Section 2301, Sheet 221), using the numbers, volumes, and amounts filed in 21

ENSTAR’s annual GCA revision (TA 284-4), except that the storage reservation and 22

capacity fees are listed as part of the GCA calculation (line (4)) and the cost and 23


average cost of Gas Withdrawn from Storage (line (3), columns (B) and (C)) have 1

been reduced to reflect removal of the costs for the next year. The amounts for cost 2

of Gas Withdrawn from storage (line 3) and the storage and capacity fees (line 4) 3

reflect the change being effective September 1, 2016. 4

Q. What is the impact on ENSTAR’s current GCA? 5

A. As shown on the revised Sheet 221 in Attachment G, the revised cost of gas 6

withdrawn from storage is $12.4139/Mcf, down $0.5839/Mcf from the amount shown 7

on the 42nd Sheet 221 filed in TA 284-4, while the revised GCA is $7.3811/Mcf, up 8

$0.3234/Mcf from the GCA shown on the Sheet 221 filed in TA 284-4. 9

XIV. CONCLUSION 10

Q. Does this conclude your direct testimony? 11

A. Yes it does. 12

Docket U-16-___ Exhibit DMD-1 Page 1 of 1

Daniel M. Dieckgraeff

EMPLOYMENT

ENSTAR Natural Gas Company/Alaska Pipeline Company, Anchorage, Alaska: 1982 – Present.

Director of Rates and Regulatory Affairs: 2012 – Present

Manager, Rates and Regulatory Affairs: 2008 – 2012

Manager, Regulatory and Gas Supply 2006 – 2008

Manager, Finance and Rates: 2000 – 2006

Manager, Rates and Planning: 1989 – 2000

Rates and Planning Supervisor: 1982 – 1988 Price Waterhouse, Anchorage, Alaska: 1979 – 1982

Staff Accountant: 1979 – 1981

Senior Accountant: 1981 – 1982

EDUCATION

Gonzaga University, Spokane, Washington: Bachelor Business Administration, Major in Public Accounting. 1979

Alaska Pacific University, Anchorage, Alaska: Master of Business Administration, Concentration in Global Finance. 2007

OTHER

Certified Public Accountant (AK), 1982 – present

American Institute of Certified Public Accountants, Member

Alaska Society of Certified Public Accountants, Member

Institute of Management Accountants, Member

Commonwealth North, Member

Spirit of Youth, Board Member

American Gas Association, State Affairs Committee

Resolution Encouraging Natural Gas Line Investment and the Expedited Replacement of

High-Risk Distribution Mains and Service Lines

WHEREAS, NARUC and its members have long focused on pipeline safety, led by the

Committee on Gas, established in 1964, the Staff Subcommittee on Pipeline Safety, the Task

Force on Pipeline Safety, and the newly created Subcommittee on Pipeline Safety; and

WHEREAS, NARUC enjoys a close working relationship with the National Association of

Pipeline Safety Representatives (NAPSR), a national organization representing the State pipeline

inspection workforce throughout the country; and

WHEREAS, NAPSR in November 2011 released an exhaustive compendium of State pipeline

safety programs which exceed the minimum federal standards States must meet in order to

receive funding from the U.S. Pipeline and Hazardous Materials Safety Administration

(PHMSA); and

WHEREAS, NARUC and the Committee on Gas maintain a strong cooperative partnership with

PHMSA, which is essential to ensure State and federal safety regulators work closely on pipeline

safety; and

WHEREAS, More than two million miles of natural gas distribution pipelines crisscross the

United States, connecting homes and businesses with one of America’s most important energy

resources. These pipelines are the safest, most reliable and cost-effective way to transport this

essential fuel across the country; and

WHEREAS, The safe and reliable delivery of natural gas to homes and businesses and its use in

providing new products and services is vital to the U.S. and of paramount importance to

members of NARUC; and

WHEREAS, By law, the utilities are charged with knowing the location, material, age and

condition of their systems. Developing essential data to evaluate the integrity of the systems is

the foundation for any determination over what regulators need to fund in rates, as well as what

rate recovery methodology best suits a particular case; and

WHEREAS, Many States and distribution utilities are undergoing significant pipeline

replacement programs to replace aging pipe; and

WHEREAS, Many distribution companies are being proactive about replacing their aging

pipelines through a risk-based approach focusing on prioritizing safety, asset replacement, and

rate impact; and

WHEREAS, Alternative rate-recovery mechanisms may help expedite the replacement and

expansion of the pipeline systems by promoting more timely rate recovery for investments in

infrastructure, safety and reliability; and


WHEREAS, Alternative rate recovery mechanisms may help eliminate near-term financial

barriers of traditional ratemaking policies such as “regulatory lag” and promote access to lower-

cost capital; and

WHEREAS, The adoption of alternative rate policies may be very effective for advancing

critical safety and reliability infrastructure upgrades, and

WHEREAS, Notwithstanding the positive advances in innovative ratemaking and proactive

remediation by many distribution companies, utility management bears ultimate responsibility

for their respective systems and should seek to work, in ways permissible under their respective

State rules and law, collaboratively with Commissioners and/or Commission staff to prioritize

asset replacement based upon asset risk, available technology, public safety risk, rate impact, and

WHEREAS, Ensuring pipeline safety is about more than just replacement and cost recovery. It

is also about effective communication, enforcement, risk sharing, and establishing a long range

strategic plan that ensures a safe and reliable gas pipeline system; and

WHEREAS, As evidenced in the NAPSR 2011 Compendium, State commissions and inspectors

are best suited to determine how best to finance system improvements because each State is

different and the needs and financial circumstances of each utility system are unique; now,

therefore be it

RESOLVED, That the Board of Directors of the National Association of Regulatory Utility

Commissioners, convened at the 2013 Summer Committee Meetings, in Denver, Colorado,

encourages regulators and industry to consider sensible programs aimed at replacing the most

vulnerable pipelines as quickly as possible along with the adoption of rate recovery mechanisms

that reflect the financial realities of the particular utility in question; and be it further

RESOLVED, That State commissions should explore, examine, and consider adopting

alternative rate recovery mechanisms as necessary to accelerate the modernization, replacement

and expansion of the nation’s natural gas pipeline systems, and be it further

RESOLVED, That NARUC encourages its members to reach out to PHMSA, NAPSR, industry,

State and local officials, and the general public about pipeline safety and replacement programs.

_______________________________________________________________

Sponsored by the Committee on Gas and the Committee on Critical Infrastructure

Adopted by the NARUC Board of Directors July24, 2013


Current Interim Increase at Rates 5.82%

General ServiceG1Monthly Customer Charge 16.00$ 17.00$ Base Rate (per Ccf) 0.12682$ 0.13420$

G2Monthly Customer Charge 35.00$ 37.00$ Base Rate (per Ccf) 0.11096$ 0.11742$



Large Transportation FirmsCEA InternationalMonthly Customer Charge 2,900$ 3,100$ Base Rate (per Mcf) 0.7427$ 0.7859$

ML&P*Monthly Customer Charge 97,000$ 103,000$ Base Rate (per Mcf) 0.2250$ 0.2381$

Mid-Sized Firm TransportationMonthly Customer Charge 13,500$ 14,300$ Base Rate (per Mcf) 0.1730$ 0.1831$

Very Large Firm TransportationMcf/Mo.

< 100,000 20,680$ 21,880$ Next 100,000 0.1861$ 0.1969$ Next 150,000 0.1675$ 0.1772$ Next 200,000 0.1507$ 0.1595$ Next 250,000 0.1357$ 0.1436$ Next 300,000 0.1221$ 0.1292$ Next 350,000 0.1099$ 0.1163$ Next 400,000 0.0989$ 0.1047$

All Additional 0.0890$ 0.0942$ Base Rate (per Mcf)

Customer Charge per Delivery Point 1,500$ 1,600$

3.50$ 3.70$

Calculation of Interim Increase

Demand Charge per Mcf of Contracted Peak Demand per Month


Exhibit DMD-3

Current Interim Increase at Rates 5.82%

Calculation of Interim Increase

Interruptible Industrial TransportationMcf/Mo.

< 100,000 20,680$ 21,880$ Next 100,000 0.1861$ 0.1969$ Next 150,000 0.1675$ 0.1772$ Next 200,000 0.1507$ 0.1595$ Next 250,000 0.1357$ 0.1436$ Next 300,000 0.1221$ 0.1292$ Next 350,000 0.1099$ 0.1163$ Next 400,000 0.0989$ 0.1047$

All Additional 0.0890$ 0.0942$

There is no charge for any months which volumes are not transported.

Interruptible Storage TransportationMcf/Mo.

< 450,000 0.20680$ 0.21884$ Next 100,000 0.15970$ 0.16899$ Next 100,000 0.13390$ 0.14169$ Next 100,000 0.12030$ 0.12730$

Remaining Volumes 0.07040$ 0.07450$

18,800$ 19,900$

There is no charge for any months which volumes are not transported

Minimum charge for each Year in which gas is transported under this rate schedule.

*ML&P rates are discontinued and they will be included in the VLFT category


Documents

STATE OF ALASKA BEFORE THE REGULATORY COMMISSION OF …€¦ · Before Commissioners: Robert M. Pickett, Chairman Stephen McAlpine Rebecca L. Pauli Norman Rokeberg Janis W. Wilson