20161216Gorman Direct with Exhibits 300-318.pdf

CABLE HUSTON LP
CHAD M. STOKES
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington Street
Boise, ID 83 702
December 16, 2016
Re: Northwest Industrial Gas Users' Testimony and Exhibits
Case No. INT-G-16-02
Dear Ms. Jewell,
RECE IVED
201&0EC 16 AM\I : 3l+
[e-mail]
Enclosed for filing with the Commission please find ten copies of the Direct Testimony
and Exhibits on behalf of Northwest Industrial Gas Users. Please note that one copy of the
Direct Testimony and Exhibits has been designated as a Reporter's Copy.
Please let me know if you have any questions. Thank you.
CMS/sk
Enclosures
cc: Service List via E-Mail
26678.885\4822-6527-9294. v2
Very truly yours,
Chad M. Stokes
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
RECE IVED
20150,_C 16 A·11f :34
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO
CHANGE ITS RATES AND
CHARGES FOR NATURAL GAS
SERVICE TO NATURAL GAS
CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
CERTIFICATE OF SERVICE
NORTHWEST INDUSTRIAL GAS USERS' CERTIFICATE OF SERVICE -1
26678.885\4848-2065-9006.v2
I CERTIFY that on this December 16, 2016, I served the foregoing Direct Testimony and
Exhibits of Michael Gorman on behalf of Northwest Industrial Gas Users upon all parties of
record in this proceeding via electronic mail pursuant to the Amended Notice of Parties.
Peter J. Richardson
Gregory M. Adams
Richardson Adams, PLLC
515 N 27th Street
Boise, ID 83 702
[e-mail]
[e-mail]
Ronald L. Williams
Williams Bradbury, P.C.
1015 W. Hays Street
Boise, ID 83 702
[e-mail]
Benjamin Otto
Idaho Conservation League
710 N 6th Street
Boise, ID 83 702
[e-mail]
Brad M. Purdy
2019 N 17th Street
Boise, ID 93 702
[e-mail]
Michael C. Creamer
Givens Pursley
[e-mail]
Michael P. McGrath
Director, Regulatory Affairs
lntermountain Gas Company
PO Box 7608
Boise, ID 83 707
[e-mail]
Scott Dale Blickenstaff
Amalgamated Sugar Co LLC
1951 S Saturn Way Ste 100
Boise, ID 83702
[e-mail]
F. Diego Rivas
NW Energy Coalition
1101 8th Avenue
Helena, MT 59601
[e-mail]
Andrew J. Unsicker
Lanny L. Zieman
Natalie A. Cepak
Thomas A. Jernigan
Ebony M. Payton
AFLOA/JA-ULFSC
139 Barnes Drive, Suite 1
Tyndall, AFB FL 32403
Andrew. [e-mail]
Lanny.zieman. [e-mail]
[e-mail]
[e-mail]
[e-mail]
NORTHWEST INDUSTRIAL GAS USERS' CERTIFICATE OF SERVICE - 2
26678.885\4848-2065-9006. v2
Ken Miller
Snake River Alliance
P.O. Box 1731
Boise, ID 83701
[e-mail]
Karl Klein
Sean Costello
Idaho Public Utilities Commission
PO Box 83720
Boise, ID 83720-0074
[e-mail]
[e-mail] .gov
Dated in Portland, Oregon, this 161h day of December 2016.
Chad M. Stokes, OSB No. 004007
Tommy A. Brooks, OSB No. 076071
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
E-Mail: [e-mail]
[e-mail]
Of Attorneys for the
Northwest Industrial Gas Users
NORTHWEST INDUSTRIAL GAS USERS' CERTIFICATE OF SERVICE-3
26678.885\4848-2065-9006. v2
BEFORE THE
RECE IVE D
20l&nt 16 AM ll :34
1i · ·.· ·; f·U ,'.JC
IDAHO PUBLIC UTILITIES COMMISSION ··1 i; __ ,_, CO~H,i lSS!ON
)
IN THE MATTER OF THE )
APPLICATION OF )
INTERMOUNTAIN GAS COMPANY )
FOR THE AUTHORITY TO ) Case No. INT-G-16-02
CHANGE ITS RATES AND )
CHARGES FOR NATURAL GAS )
SERVICE TO NATURAL GAS )
CUSTOMERS IN THE STATE OF )
IDAHO )
-------------)
Direct Testimony and Exhibits of
Michael P. Gorman
On behalf of
Northwest Industrial Gas Users
December 16, 2016
~
BRUBAKER &ASSOCIATES, INC.
Project 10309
Table of Contents to the
Direct Testimony of Michael P. Gorman
I. OVERVIEW AND TESTIMONY SUMMARY ................................................................ 1
II. RATE OF RETURN SUMMARY ................................................................................. 3
Ill. OTHER REVENUES ................................................................................................. 5
IV. AFFILIATE COST ..................................................................................................... 7
V. INCENTIVE COMPENSATION .................................................................................. 9
V.A. Incentive Metrics ..................................................................................................... 9
VI . BONUS DEPRECIATION ........................................................................................ 11
VI I. CLASS REVENUE SPREAD .................................................................................. 13
VIII. CLASS COST OF SERVICE STUDY .................................................................... 14
IX. RATE DESIGN ........................................................................................................ 19
X. RATE OF RETURN ................................................................................................... 20
X.A. Industry Authorized Returns on Equity, Access to Capital, and ............................. 22
Credit Strength .............................................................................................................. 22
X.B. Regulated Utility Industry Market Outlook ............................................................. 28
X.C. IGC Investment Risk ............................................................................................. 33
XI. IGC'S PROPOSED CAPITAL STRUCTURE ........................................................... 34
XI .A Embedded Cost of Debt. ...................................................................................... 36
XII. RETURN ON EQUITY ............................................................................................ 36
XII.A. Risk Proxy Group ................................................................................................ 37
XII.B. Discounted Cash Flow Model ............................................................................ .40
XII.C. Sustainable Growth DCF ................................................................................... .44
XII.D. Multi-Stage Growth DCF Model .......................................................................... 45
XII.E. Risk Premium Model ........................................................................................... 52
XII.F. Capital Asset Pricing Model ("CAPM") ................................................................. 59
XII.G. Return on Equity Summary ................................................................................. 64
XII.H. Financial Integrity ............................................................................................... 65
XIII. RESPONSE TO IGC WITNESS DR. J . STEPHEN GASKE .................................. 67
XIII.A. Summary of Rebuttal ......................................................................................... 67
QUALIFICATIONS OF MICHAEL P. GORMAN ............................................... Appendix A
Exhibit No. 301 through Exhibit No. 318
Gorman, Di TOC
Northwest Industrial Gas Users
1 Q PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A Michael P. Gorman. My business address is 16690 Swingley Ridge Road,
3 Suite 140, Chesterfield, MO 63017.
4 Q
5 A
WHAT IS YOUR OCCUPATION?
I am a consultant in the field of public utility regulation and Managing Principal of
6 Brubaker & Associates, Inc., energy, economic and regulatory consultants.
7 Q PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND
8 EXPERIENCE.
9 A
10 Q
11 A
12
13 Q
14 A
This information is included in Appendix A to my testimony.
ON WHOSE BEHALF ARE YOU APPEARING IN THIS PROCEEDING?
I am appearing on behalf of Northwest Industrial Gas Users ("NWIGU").
I. OVERVIEW AND TESTIMONY SUMMARY
WHAT INCREASE HAS IGC REQUESTED IN THIS RATE CASE?
The overall increase sought by lntermountain Gas Company ("IGC") in this
15 proceeding is $10,166,000.1
16 Q WHAT TEST YEAR HAS IGC PROPOSED FOR THIS CASE?
17 A IGC is proposing a test year reflecting six months actual (January-June 2016) and
18 six months projected data (July-December 2016) for the twelve months ending
19 December 31 , 2016. The Company states that it will provide the Idaho Public
20 Utilities Commission ("Commission") with monthly updates to the six months of
21 projections through December 31 , 2016, to reflect actual data. 2
22
23
1 IGC Exhibit No. 16, page 1 (Darrington Direct).
2Direct testimony of Ted Dedden, page 2.
Gorman, Di 1
Northwest Industrial Gas Users
1 Q
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3 A
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11 Q
12
13 A
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15
16
DO YOU BELIEVE IGC HAS JUSTIFIED ITS PROPOSED OVERALL INCREASE
OF $10,166,000?
No. I believe IGC's claimed revenue deficiency is overstated. Based on my
detailed analysis of several aspects of the operations of IGC, I have determined
that the Company's revenue requirement is overstated by at least $4,208,000.
This revenue requirement does not incorporate other parties' adjustments, which
could lower the revenue requirement even further.
It should be noted that if my testimony does not address a specific cost of
service issue, this should not be interpreted as NWIGU accepting IGC's position.
NWIGU reserves the right to accept and adopt other parties' adjustments.
PLEASE SUMMARIZE THE REVENUE REQUIREMENT ADJUSTMENTS THAT
NWIGU IS PROPOSING.
I am proposing a reduction to IGC's revenue requirement as a result of
adjustments to the return on equity and capital structure (collectively, rate of
return), other revenues, affiliate costs, incentive compensation and income taxes.
This information is outlined below in Table 1.
Gorman, Di 2
Northwest Industrial Gas Users
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3 Q
4 A
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8 Q
9 A
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13
TABLE 1
NWIGU's Adjustments to IGC's
Proposed Revenue Requirement
Category of Adjustment
Requested Increase
Adjustments:
1. Rate of Return
2. Other Revenues
3 Affiliate Costs
4. Incentive Compensation
5. Bonus Depreciation
6. Total Reduction
7. Adjusted Increase
Amount of Reduction
(000)
$10,166
($1,689)
(206)
(1 ,381)
(704)
(228)
($4,208)
$5.958
II. RATE OF RETURN SUMMARY
WHAT RATE OF RETURN IS IGC REQUESTING IN THIS PROCEEDING?
IGC is requesting an overall rate of return of 7.42%. This rate of return is based
on a requested return on equity of 9.9%, and a capital structure composed of 50%
long-term debt and common equity. IGC's overall rate of return includes an
estimate of embedded cost of debt of 4.94%.3
IS IGC'S REQUESTED OVERALL RATE OF RETURN REASONABLE?
No. IGC's requested return on common equity of 9.9% is significantly in excess of
its current market cost of equity. Setting a return on equity in excess of IGC's
current market cost of equity is imbalanced because it results in unjustified rate
increases to retail customers to support an above-market rate of return on equity
investments in its utility plant and equipment.
3Chiles Direct at 2.
Gorman, Di 3
Northwest Industrial Gas Users
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2
3
4
5
6 Q
7
8 A
Further, IGC's proposed capital structure of 50.0% common equity and
50.0% long-term debt is not reasonable. Based on its most recent financial
statements, IGC's common equity ratio, including short-term debt is approximately
47.95%. Based on its most recent actual capital structure, I recommend IGC's
common equity ratio be set at 48.0% and its debt ratio be set at 52.0%.
DO YOU PROPOSE A MORE REASONABLE RETURN ON EQUITY FOR RATE­
SETTING PURPOSES FOR IGC IN THIS CASE?
Yes. I performed a detailed investigation of the current capital market for regulated
9 utility companies, including gas utility companies, and performed several market
10 analyses to estimate IGC's current market cost of equity that fairly compensates
11 its investors for the investment risk of a gas distribution company operating with
12 IGC's current financial and business risks. Based on this study, as detailed later
13 in this testimony, I find a fair return on equity to fall within the range of 9.2% up to
14 9.4%. I recommend IGC's return on equity be set at 9.3%. However, I believe it
15 would be inappropriate to award IGC a return on equity greater than the high-end
16 of my estimated range of 9.4%.
17 Q
18
19
20
21 A
22
23
24
25
26
WHAT WOULD BE THE IMPACT OF THE CLAIMED REVENUE DEFICIENCY
IF THE RETURN ON COMMON EQUITY REQUESTED BY IGC OF 9.9% WERE
REDUCED DOWN TO 9.3% AND ITS CAPITAL STRUCTURE BE BASED ON A
48.0% COMMON EQUITY RATIO?
Reducing IGC's return on equity used to develop its revenue requirement would
reduce its claimed revenue deficiency by $1,187,000. This reduction in the overall
rate of return and resulting revenue requirement reflects only an adjustment to the
requested return on equity from 9.9% down to 9.3%.
Reducing IGC's common equity ratio from 50.0% to 48.0% would have an
additional reduction in IGC's claimed revenue deficiency of $502,000.
Gorman, Di 4
Northwest Industrial Gas Users
1 Q
2
3 A
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6
7
8
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11 Q
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13 A
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16 Q
17 A
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WILL A 9.3% RETURN REPRESENT FAIR COMPENSATION FOR IGC IN THIS
PROCEEDING?
Yes. As outlined later in this testimony, a 9.3% return on equity represents fair
compensation in the current low capital cost market environment where IGC and
all utilities currently operate within , will maintain a strong investment grade bond
rating, and support its access to external capital. Therefore, for these reasons, I
believe that a 9.3% return on equity represents a fair and balanced overall rate of
return that fairly compensates investors, and minimizes unnecessary rate
increases on retail customers.
Ill. OTHER REVENUES
WHAT LEVEL OF OTHER REVENUES HAS IGC INCLUDED IN THE COST OF
SERVICE IN THIS CASE?
IGC has included actual other revenues for the six months ending June 30, 2016
plus a forecast for July 31 through December 31 of 2016. The forecast is based
on the calendar year amounts for 2015.4
DO YOU AGREE WITH THIS AMOUNT?
No. For the other revenue items shown in the table below, the amount realized
during the first six months of 2016 have increased approximately 6.4% over the
first six months of 2015.
4Direct testimony of Ted Dedden, pages 5 and 6.
Gorman, Di 5
Northwest Industrial Gas Users
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TABLE 2
Other Revenues Year To Year Comparison
January-January-
Other Revenues June 2016 5 June 2015 6
Miscellaneous Service $606,844 $576,543
Field Collection Charge 15 8,160
Return Check Charge 58,720 38,940
Account Initiation Charge 481 ,284 429,446
Reconnection Charge 25,894 45,056
Interest on Past Due Accounts 367,312 349,405
Other Miscellaneous 7,917 8,353
Cash Discounts 3,834 2,423
Total $1 ,551 ,820 $1,458,327
Percentage Increase
Year over
Year Increase
$30,300
(8,145)
19,780
51 ,838
(19,162)
17,906
(436)
1,411
$93,493
6.4%
Rather than using 2015 data as the forecast for July through December of
2016, the first six months of 2016 better represents the ongoing level of other
revenue for the items shown above. Therefore, I recommend using the first six
months of 2016 as the forecasted amount for July 31 through December 31 of
2016 for other revenue items listed above. This calculation will annualize the year
over year increase in other revenue actually experienced during the first six months
of 2016.
8 Q
9
HOW DOES THIS ANNUALIZED LEVEL, BASED ON THE FIRST SIX MONTHS
OF 2016, COMPARE TO THE OTHER REVENUE AMOUNT FOR THESE ITEMS
INCLUDED IN THE COST OF SERVICE BY IGC? 10
11 A My recommendation results in a $206,000 increase in other revenues and a
$206,000 reduction to the revenue requirement in this case. 12
51GC Exhibit No. 9 (Dedden Direct).
62015 other revenues (NWIGU DR No. 1-31 ), less July through December forecast, IGC
Exhibit No. 9 (Dedden).
Gorman, Di 6
Northwest Industrial Gas Users
1 IV. AFFILIATE COST
2 Q HAS IGC INCLUDED CHARGES FROM AFFILIATE COMPANIES IN ITS
3 DETERMINATION OF THE REVENUE REQUIREMENT?
4 A Yes. IGC has included $15,828,000 of affiliated charges in the test year in this
5 case.7
6 Q HOW DOES THIS LEVEL COMPARE TO PRIOR YEARS AFFILIATE
7 CHARGES?
8 A For 2011 through 2015 affiliate charges have ranged from $13,995,000 to
9 $14,870,000, averaging $14,447,000 during the five-year period. The test year
10 amount included in the cost of service represents a 9% increase above the five-
11 year average and a 10% increase above 2015, the most recent actual calendar
12 year level of affiliate costs.8 The table below shows the total affiliate cost for 2011
13 through 2015 and the test year amount.
Year
2011
2012
2013
2014
2015
Average
2016
TABLE 3
Affiliate Cost
Actual
(1)
$14,869,658
$14,306,186
$13,995,404
$14,618,315
i14,444,524
$14,446,817
71GC Exhibit No. 11 (Dedden Direct).
Test Year
Forecast
(2)
$15,827,869
asased on data provided in response to NWIGU DR No. 1-33.
Gorman, Di 7
Northwest Industrial Gas Users
1
2
3 Q
4
5 A
6
7
8 Q
9
10 A
11
12
13
14
15
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19 Q
20
21 A
22
23
As shown in Table 3, actual affiliate cost (Column 1) has varied up and down with
no specific trend.
HAS IGC PROVIDED ANY EXPLANATION FOR THIS INCREASE IN COST
FROM AFFILIATE COMPANIES?
No. IGC witness Dedden discusses affiliate charges in his direct testimony, but
provides no explanation or justification for the increased level sought by the
Company.9
WHAT AFFILIATE COST AREAS HAVE EXHIBITED SIGNIFICANT
INCREASES?
The increase in affiliate costs generally occurs in three areas:
1. Customer support, which includes billing and collection, customer service and
customer development;
2. Information services, which include information technology risk management,
information technology, communications and information systems; and
3. Charges from MDU Resources Group, Inc. ("MDUR"), which include payroll ,
procurement, enterprise technology and general and administrative services.
Together the increase in these areas comprise 96% of the total increase in
affiliate costs.
ARE YOU RECOMMENDING AN ADJUSTMENT TO THE LEVEL OF
AFFILIATED COSTS IGC HAS INCLUDED IN THE REVENUE REQUIREMENT?
Yes. I recommend reducing the test year affiliate cost to the five-year average
level experienced during 2011 through 2015, or $14,447,000. This adjustment
reduces the affiliate charges by $1 ,381,000 in the test year.
9Direct testimony of Ted Dedden, pages 8 through 12.
Gorman, Di 8
Northwest Industrial Gas Users
1
2 Q
3
4 A
V. INCENTIVE COMPENSATION
HAS IGC INCLUDED INCENTIVE COMPENSATION IN THE DETERMINATION
OF REVENUE REQUIREMENT?
Yes. IGC is including $704,000 of incentive compensation and related payroll
5 taxes in the revenue requirement in this case.10 This amount reflects a reduction
6 for the incentive compensation that IGC specifically attributes to meeting the net
7 income financial metric. However, IGC continues to seek recovery of incentive
8 compensation it attributes to meeting metrics for cost control and customer
9 satisfaction.
10 Q ARE YOU OPPOSED TO INCENTIVE COMPENSATION COSTS?
11 A No. However, I believe a properly developed incentive plan should reward
12 employees for their specific performance, which can be demonstrated to result in
13 customer benefits or employee safety for IGC gas delivery operations.
14 V.A Incentive Metrics
15 Q
16
17 A
18
19
20
21
22
ARE IGC INCENTIVE METRICS BASED ON MEETING METRICS FOR ITS
RETAIL CUSTOMERS AND EMPLOYEES?
No. As a result, an IGC employee's performance is measured against the
combined results achieved by IGC, Cascade Natural Gas Company, Great Plains
Natural Gas and Montana-Dakota Utilities operating across eight states. This is a
valid concern if IGC employee performance is based on the achievement of
metrics that consider the combined results of the MDU electric and gas utility
segment.
101GC Exhibit No. 15, page 17 (Darrington Direct).
Gorman, Di 9
Northwest Industrial Gas Users
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Even if cost control and customer satisfaction were determined to be
appropriate metrics for incentive compensation that is reflected in customer rates,
these metrics reflect the results of operations, which are not specifically based on
the performance of IGC service quality or IGC employee safety. Therefore, there
is no proof that IGC ratepayers receive any benefit from the MDU incentive
program.
DO YOU BELIEVE SHAREHOLDERS REAP SUBSTANTIAL BENEFITS FROM
INCENTIVIZING MDU-WIDE COST CONTROL AND CUSTOMER
SATISFACTION?
Yes. Incentives based on measureable achievement for cost control and customer
satisfaction can benefit ratepayers through lower costs and improved service
reliability. However, MDU's metrics do not identify which customers get the
benefits. Further, and importantly, these MDU incentives benefit shareholders.
Controlling costs will clearly improve earnings and provide cash flow. Improving
customer satisfaction may reduce uncollectible expense and collection costs and
could also result in customers and regulators being more receptive to rate
increases.
Performance metrics that achieve these results can lead to increased
earnings and cash flows, which will support enhanced stock valuation, growth in
earnings/dividends, and reduced investment risk. These are undeniably benefits
to MDU shareholders.
Therefore, shareholders should bear the cost of incentive programs that
achieve such benefits. Also, to the extent the incentivized performance increases
earnings and cash flows, the cost of the incentive programs can be paid from these
increased earnings and still provide benefits to shareholders without increasing the
utility's cost of service.
Gorman, Di 10
Northwest Industrial Gas Users
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Q
3 A
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11 Q
12 A
13
14
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16
17
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ARE YOU PROPOSING AN ADJUSTMENT TO THE LEVEL OF INCENTIVE
COMPENSATION INCLUDED IN IGC'S REVENUE REQUIREMENT?
Yes. For the reasons discussed above, I recommend eliminating the incentive
compensation cost included in IGC's revenue requirement. IGC has not proven
that this program produces benefits to its IGC customers. However, shareholders
benefit from these programs due to improved operating performance and
enhanced and stable returns. Therefore, shareholders receive the benefits and
should bear the cost of the incentive program. My recommendation reduces
revenue requirement by $704,000.
VI. BONUS DEPRECIATION
PLEASE EXPLAIN THIS ISSUE.
IGC has elected not to take bonus depreciation for the calculation of federal
income tax in 2016.11 Bonus depreciation allows a company to write-off 50% of
the cost of certain plant additions in the first year of operation for the determination
of federal income tax. The recognition of bonus depreciation results in a more
rapid build-up of the accumulated deferred federal income tax balance. This would
reduce revenue requirement, since accumulated deferred income taxes are a
reduction to rate base. By not electing to take bonus depreciation, IGC is inflating
its rate base and increasing the revenue requirement. I am recommending an
adjustment to the rate base and revenue requirement to recognize the additional
accumulated deferred federal income tax associated with bonus depreciation.
11 Response to NWIGU DR No. 1-34.
Gorman, Di 11
Northwest Industrial Gas Users
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2
Q
3 A
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13 Q
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16 A
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DO CUSTOMERS PROVIDE THE CASH ASSOCIATED WITH FEDERAL
DEFERRED INCOME TAXES?
Yes. The federal income tax expense included in rates does not reflect the savings
enjoyed by the utility, as a result of bonus and other accelerated depreciation
options allowed by the Internal Revenue Code. The reduction in current federal
income tax expense, due to bonus depreciation, is offset by an increase in deferred
income tax expense in the establishment of customer rates. As a result of
customers paying federal income tax expense in rates that is not currently paid to
the federal government, customers are providing a source of cost free capital to
the utility. In recognition of this provision of cost free capital, deferred federal
income taxes are recognized as a reduction to rate base, revenue requirement and
in the determination of tariff rate charges.
HAVE YOU CALCULATED AN ESTIMATE OF THE REVENUE REQUIREMENT
ASSOCIATED WITH THE COMPANY'S DECISION TO NOT ELECT BONUS
DEPRECIATION?
Yes. The estimated average growth in plant during 2016 is approximately
$12,700 ,000.12 Assuming all of this plant is eligible, bonus depreciation would
allow a 50% write-off in the current year equal to $6,350,000. Recognizing this
bonus depreciation would generate an additional $2,223,000 of accumulated
deferred federal income taxes at a 35% federal income tax rate. Based on my
recommended pre-tax rate of return, the revenue requirement associated with this
additional deferred tax rate base reduction amount is $228,000. I recommend that
121GC Exhibit No. 7, page 1 (Dedden Direct).
Gorman, Di 12
Northwest Industrial Gas Users
1
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4 Q
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6 A
7 Q
8 A
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12
the Commission reduce IGC's revenue requirement by $228,000 to recognize this
bonus depreciation option available to IGC.
VII. CLASS REVENUE SPREAD
PLEASE DESCRIBE THE COMPANY'S PROPOSED SPREAD OF ITS
CLAIMED REVENUE DEFICIENCY ACROSS RATE CLASSES IN THIS CASE.
The Company's proposed revenue spread is shown in Table 4 below.
TABLE 4
Company Proposed Non-Gas Revenue Spread
($ Millions)
Rate Class
Residential: RS
General Service: GS-1
Large Volume: LV-1
Transport -Interruptible: T-3
Transport -Firm: T-4
Total
Current
Revenues
$53.23
19.53
0.40
0.73
~
$83.08
Source: Blattner, Exhibit No. 20.
Increase/
(Decrease)
Needed to Reach
Cost of Service
Amount Percent
$7.76 14.6%
4.47 22.9%
(0.14) -35.5%
(0.53) -72.3%
ildfil -15.1%
$10.17 12.2%
Proposed
Increase/ (Decrease}
Amount Percent
$7.76 14.6%
4.47 22.9%
(0.14) -35.5%
(0.53) -72.3%
ildfil -15.1%
$10 .17 12.2%
IS THE COMPANY'S PROPOSED REVENUE SPREAD REASONABLE?
Yes. The proposed spread moves all rate classes to cost of service based on
results of the Company's class cost of service study, and at the Company's
claimed revenue deficiency. Classes that are currently earning above system
average rates of return will receive rate decreases, while classes providing below
system average rates of return will receive rate increases.
Gorman, Di 13
Northwest Industrial Gas Users
1
2
3
Q
4 A
DO YOU SUPPORT THE COMPANY'S PROPOSED CLASS REVENUE
ALLOCATION BASED ON THE RESULTS OF ITS CLASS COST OF SERVICE
STUDY?
Yes. The Company's proposed class revenue allocation is based on the results of
5 its class cost of service study. Since the cost of service study moves rates towards
6 cost of service, I agree with the Company's proposal to base its class revenue
7 allocation on the results of its class cost of service study.
8 However, I do take certain issues with some aspects of the Company's
9 class cost of service study. More specifically, certain aspects of the cost of service
1 O study I believe over-allocate costs to the Large Volume LV1 , Transportation
11 Interruptible T-3 and Transportation Firm T-4 rate classes. I will comment on those
12 cost of service aspects later. However, these adjustments to the Company's class
13 cost of service study I recommend be implemented in the Company's next rate
14 case. I believe the Company's proposed spread of its revenue deficiency in this
15 case is reasonable, but a more accurate cost of service study and further
16 movement to cost of service should be considered in subsequent rate cases.
17 VIII. CLASS COST OF SERVICE STUDY
18 Q
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20 A
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22 Q
23 A
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25
26
HAVE YOU REVIEWED THE COMPANY'S CLASS COST OF SERVICE
STUDY?
Yes. The class cost of service study is discussed in the direct testimony and
exhibits of Lori A. Blattner.
PLEASE DESCRIBE THE COMPANY'S CLASS COST OF SERVICE STUDY.
In its class cost of service study, the Company has classified and allocated
transmission mains and storage plant assets on a demand basis. Distribution
mains in Account 376 have been separated into two categories and classified as
either customer related or demand related. Using the zero-intercept method, the
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Company determined that about 47.2% of Account 376 distribution mains should
be classified as customer related and allocated to each rate class based on the
number of customers. Demand related costs have been allocated primarily on the
basis of a single coincident peak demand.
IS THE COMPANY'S CLASS COST OF SERVICE STUDY REASONABLE?
Yes. I generally support the Company's class cost of service study, but with one
exception. That is, I disagree with the Company's use of a peak and average
allocator for Account 375 (Distribution Structures and Improvements), and Account
378 (Distribution Measuring and Regulation Equipment).
HOW SHOULD THE COSTS IN ACCOUNT 375 AND ACCOUNT 378 BE
ALLOCATED?
The peak and average allocation methodology provides a significant allocation
based on annual throughput of the customer classes. Therefore, the peak and
average allocator for these accounts would be inappropriate because these
accounts do not reflect costs that vary with the level of throughput. Rather, these
costs are largely fixed in nature and relate to either of the customer's peak day
demand, in setting this equipment based on the largest delivery day within the
year, or are more customer related in that they reflect the Company's cost for
connecting customers to the system as much as they do for ensuring that they
have adequate capacity to meet the customers' demands on the system.
The demand allocation of Accounts 375 and 378 should be allocated on
design day demand along with other distribution capacity-related costs.
Alternatively, they should be allocated on the basis of design day demand and a
customer component as these investments relate to both maximum design day
demand, and cost of connecting to the system. However, the peak and average
method is simply not a factor that accurately reflects cost-causation in assigning
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costs for these accounts between rate classes. Therefore, the Company's
proposal for peak and average allocation of these costs across rate classes should
be rejected. I recommend the Commission direct IGC to modify its cost of service
study in its next rate case and allocate Accounts 375 and 378 on a combination of
design day demand, and a customer component along with other distribution­
related capacity costs.
DOES NARUC RECOGNIZE THAT DEMAND COSTS CAN BE ALLOCATED
BASED ON PEAK DAY DEMANDS AND THE NUMBER OF CUSTOMERS?
Yes. In its 1989 manual, NARUC recognizes that demand or capacity related costs
can be allocated to classes based on two factors: ( 1) peak day demands, and (2)
the number of customers. The NARUC Gas Distribution Rate Design Manual
states the following:
Demand or capacity costs vary with the size of plant and
equipment. They are related to maximum system requirements
which the system is designed to serve during short intervals and do
not directly vary with the number of customers or their annual
usage. Included in these costs are: the capital costs associated
with production , transmission and storage plant and their related
expenses; the demand cost of gas; and most of the capital costs
and expenses associated with that part of the distribution plant
not allocated to customer costs, such as the costs associated
with distribution mains in excess of the minimum size (pages
23-24, emphasis added).
DOES THE COMPANY DESIGN ITS DISTRIBUTION SYSTEM TO MEET
THE PEAK-DAY DEMAND OF ITS CUSTOMERS?
In part, yes. As described in the direct testimony of Company witness Hart
Gilchrist at page 4, the Company has to design and build the distribution system
with enough capacity to meet the system peak day demand, regardless of what
the demand is on non-peak days.
Gorman, Di 16
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1 Q
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3 A
IS ANNUAL VOLUME, OR AVERAGE DEMAND, A DESIGN CRITERION
FOR A TYPICAL LDC FACILITY?
No. Annual volume, or average demand, is certainly a factor considered in
4 identifying the variable cost of operating the system. However, the actual physical
5 size of the distribution mains, compressors, and related equipment is based on
6 customers' contributions to the system peak day demand. Annual volumes or
7 average demands do not describe the main size or system capacity that is
8 necessary to provide firm uninterruptible supply of service to all customers every
9 day of the year. Rather, the system's capacity must be sized for peak day demand ,
10 so that all customers can utilize their entitlement to that capacity to receive a firm ,
11 uninterrupted, supply of gas every day of the year, including the day of the peak
12 demand.
13 Q
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DOES THE COMPANY ALSO DESIGN ITS DISTRIBUTION SYSTEM IN
ORDER TO CONNECT CUSTOMERS TO THE SYSTEM?
Yes. As described in the direct testimony of Company witness Lori A. Blattner at
page 9, the Company's distribution mains (FERC Account No. 376) are installed
to meet both system peak load requirements and to connect customers to the
utility's gas system. As a result, it is appropriate to recognize a customer
component of distribution main costs when allocating those costs to customer
classes.
IS THE RECOGNITION OF A CUSTOMER COMPONENT OF
DISTRIBUTION MAIN COSTS AN ACCEPTED PRINCIPLE IN THE GAS
INDUSTRY?
Yes. As noted above, NARUC recognizes both a demand and customer allocation
of distribution mains. Company witness Lori A Blattner also agrees, stating in her
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direct testimony at page 9 that identifying a portion of mains investment as
customer related is an accepted principle throughout the gas industry.
WHY IS IT APPROPRIATE TO ALLOCATE THE COSTS OF DISTRIBUTION
MAINS ON A CUSTOMER COMPONENT?
While it is true that a gas distribution system has to be sized to accommodate the
design for peak day demands, it must also be designed to physically connect each
customer's service with the city gate gas receipt points. Consequently, while peak
requirements will influence the diameter of mains, the linear feet of mains (and
total actual cost) will depend upon the location of customers on the system. As an
illustration, more investment is needed to serve 10,000 customers at various
different geographical locations each with a peak demand of 1 Mcf than one
customer with a peak demand of 10,000 Mcf at a single location.
WHY IS THE COMPANY'S PROPOSED ALLOCATION OF DISTRIBUTION
MAIN COSTS USING THE COINCIDENT DEMAND METHOD WITH A
CUSTOMER COMPONENT MORE ACCURATE THAN OTHER COST
ALLOCATION APPROACHES SUCH AS THE PEAK & AVERAGE METHOD?
The Company's proposed allocation of distribution main costs using both a
customer and a demand component best reflects cost causation principles. The
Company designs its distribution mains and regulator station equipment to meet
the firm coincident demands of the Company's rate classes on the system peak
day. The Company also designs its system of distribution mains so that all
customers are connected to the system. The Company does not design its system
to meet the total annual volumes, or average demands, of its rate classes. Only
when the distribution main system is designed to meet the peak day demand of its
classes is the Company able to deliver gas each and every day of the year to meet
its customers' demands. Thus, the Company incurs the costs of these facilities to
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both meet class coincident demands and to connect all customers to the
distribution main system. Allocating the costs of these facilities on a coincident
demand basis and on a customer basis reflects how these costs are incurred and
as a result, more accurately reflects cost causation than the Peak and Average
method, which partially allocates these costs on a volumetric, or average demand,
basis.
IX. RATE DESIGN
PLEASE DESCRIBE THE COMPANY'S PROPOSED RATE DESIGN FOR THE
LARGE VOLUME AND TRANSPORTATION RATE CLASSES.
The Company's proposed rate design is also addressed by witness Lori Blattner.
In her direct testimony, she indicates that the Company proposes to add a demand
charge to the Large Volume LV-1 rate schedule, and to combine the Transportation
T-4 and T-5 rate schedules to create a single rate. Combining rate schedules T-4
and T-5 would result in the implementation of a demand charge for T-4 customers.
IS THE COMPANY'S PROPOSED RATE DESIGN FOR THE LARGE VOLUME
AND TRANSPORTATION RATES CLASSES REASONABLE?
Yes. In general, customers' demands are a primary driver of the required capacity
of the distribution system, and the necessary distribution capital investment. The
cost of the distribution system equipment required to meet peak demand is fixed ,
and does not vary with the amount of gas throughput. Therefore, the
21 implementation of a demand charge for these large industrial customers aligns
22 with sound cost of service principles. Recovering fixed costs through demand
23 charges rather than volumetric charges will help stabilize the revenues collected
24 from these classes, and provide effective price signals to these customers.
Gorman, Di 19
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DO YOU HAVE ANY RECOMMENDATIONS FOR THE COMPANY'S RATE
DESIGN PROPOSAL?
Yes, as explained in the Direct Testimony of David Swenson, lntermountain has
proposed to implement a demand charge on the redesigned rate schedule TF-
4. The demand charge, if approved, would be the product of the demand rate
times the effective Maximum Daily Firm Quantity (MDFQ) contained in a written
service contract between the customer and lntermountain. Because a demand
charge has never been used on TF-4 customers, I recommend that lntermountain
conduct an open season to allow TF-4 customers, and all other industrial
customers who contract with the Company for an MDFQ, the ability to reset their
MDFQs in the event the rate redesign of rate schedule TF-4 is approved.
X. RATE OF RETURN
WHAT DOES YOUR RATE OF RETURN TESTIMONY ADDRESS?
My testimony will address the current market cost of equity, and resulting overall
rate of return, for IGC. In my analyses, I consider the results of several market
models and the current economic environment and outlook for the utility industry
as well as the financial integrity of IGC given my recommended return on equity
and overall rate of return .
I will also respond to IGC witness Dr. J. Stephen Gaske's recommended
return on equity, and IGC's requested return on equity, of 9.90%.
My silence in regard to any issue should not be construed as an
endorsement of IGC's position.
PLEASE SUMMARIZE YOUR RECOMMENDATIONS AND CONCLUSIONS ON
RATE OF RETURN.
As discussed above, I recommend the Commission award a return on common
equity of 9.30%, which is the midpoint of my recommended range of 9.20% to
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9.40%. My recommended return on equity will fairly compensate IGC for its current
market cost of common equity, and it will mitigate the claimed revenue deficiency
in this proceeding by fairly balancing the interests of all stakeholders.
I also take issue with the Company's proposed capital structure. The
Company is requesting a capital structure composed of 50% equity and 50% debt.
While the Company's common equity ratio has varied over time, the most recent
capital structure for IGC appears to be based on an approximately 48% equity and
52% debt mix. I would also note that another MDU gas subsidiary, Cascade
Natural Gas Company recently settled on a rate case in Oregon and agreed for an
overall rate of return based on a 49% equity and 51 % debt capital structure, and a
9.4% return on equity.13 With this as a background, I believe a reasonable capital
structure would be composed of 48% common equity and 52% debt. This
reasonably reflects IGC's most recent actual capital structure and is line with the
capital structure that MDU affiliates have found reasonable for smaller gas
distribution companies.
WHAT IS YOUR RECOMMENDED OVERALL RATE OF RETURN?
Based on my recommended return on equity of 9.30%, my proposed capital
structure, and the Company's embedded cost of debt, I recommend an overall
rate of return of 7.03% as developed on my Exhibit No. 301.
PLEASE DESCRIBE THIS SECTION OF YOUR TESTIMONY.
In this section of my testimony, I will explain the analysis I performed to determine
the reasonable rate of return in this proceeding and present the results of my
analysis. I begin my estimate of a fair return on equity by reviewing the authorized
returns approved by the regulatory commissions in various jurisdictions, the market
13Public Utility Commission of Oregon vs. Cascade Natural Gas Corporation, Docket UG
305, Order No. 16-477 at p. 3 (Dec. 12, 2016).
Gorman, Di 21
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1 assessment of the regulated utility industry investment risk, credit standing, and
2 stock price performance. I used this information to get a sense of the market's
3 perception of the risk characteristics of regulated utility investments in general,
4 which is then used to produce a refined estimate of the market's return requirement
5 for assuming investment risk similar to IGC's utility operations.
6 As described below, I find the credit rating outlook of the industry to be
7 strong, supportive of the industry's financial integrity, and access to capital.
8 Further, regulated utilities' stocks have exhibited strong price performance over
9 the last several years, which is evidence of utility access to capital.
10 Based on this review of utility credit outlooks and stock price performance,
11 I conclude that the market continues to embrace the regulated utility industry as a
12 safe-haven investment option and views utility equity and debt investments as
13 low-risk investments.
14 X.A. Industry Authorized Returns on Equity. Access to Capital. and
15 Credit Strength
16 Q
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PLEASE DESCRIBE THE OBSERVABLE EVIDENCE ON TRENDS IN
AUTHORIZED RETURNS ON EQUITY FOR ELECTRIC AND GAS UTILITIES,
UTILITIES' CREDIT STANDING, AND UTILITIES' ACCESS TO CAPITAL TO
FUNDINFRASTRUCTUREINVESTMEN~
Authorized returns on equity for both electric and gas utilities have been steadily
declining over the last 10 years as illustrated in the graph below. More recent
authorized returns on equity for electric utilities have declined down to about 9.6%,
and local gas delivery utilities' returns on equity have declined to 9.45%.
Gorman, Di 22
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11.00%
10.50% 10. 4%
10.00%
9.50%
9.00%
Figure 1
Authorized Returns on Equity
(Excludes Limited Issue Riders)
10.52%
9.64%
9.60°z--...
9.45%
8.50% +---,-----,----,------r---,-.--~--~--.-----,~---,---~
2006 2007 2008 2009 201 0 2011 2012 2013 2014 2015 2016*
Source and Note:
Regulatory Research Associates, Inc., Regulatory Focus, Major Rate Case Decisions --January-September 2016,
October 14, 2016 at page 7.
Note: Limited issue rider cases are not excluded for gas;
the use of limited issue rider cases in which an ROE is determined is extremely limited in the gas industry.
* The data includes the period Jan -Sep 2016.
While the declines in authorized returns on equity are public knowledge,
and align with declining capital market costs, utilities are maintaining strong
investment grade credit standing, and have been able to attract large amounts of
capital at low costs to fund very large capital programs.
HAVE UTILITIES BEEN ABLE TO ACCESS EXTERNAL CAPITAL TO
SUPPORT INFRASTRUCTURE CAPITAL PROGRAMS?
Yes. In its October 27, 2016 Capital Expenditure Update report, S&P Global
Market Intelligence Financial Focus, a division of SNL, made several relevant
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comments about utility investments generally and gas delivery investments
specifically:
Capital expenditures throughout the U.S. power and gas sectors in
calendar-2016 are projected to be at an all-time high. The nation's
largest electric and gas utilities are investing in infrastructure to
comply with sweeping environmental regulations, implement new
technologies, build new natural gas, solar and wind generation and
upgrade aging transmission and distribution systems. Moreover,
their near-term capital spending forecasts continue to escalate.
Since our previous review of industry CapEx estimates, the utilities
in the RRA Index have added about $11 billion of projects to their
to-do lists for 2016-2018, according to our review of spending plans
detailed in investor presentations. While most companies raised
their forecasts or left them unchanged, a handful did reduce CapEx
plans through 2018 (see below for individual examples.) Total
CapEx in 2016 for the companies in the RRA Index is projected to
be almost $117 billion.
* * *
From a natural gas perspective, many utilities are participating in
the sizable and ongoing expansion of the nation's gas midstream
network. In addition, replacement of mature gas distribution
infrastructure has gained widespread momentum and is likely to
continue at material levels for many years, considering state and
federal mandates to address safety.
* * *
Conversely, the ratio of gas utility CapEx to depreciation and
amortization was largely flat from 2000 through 2010, ranging from
1.6x to 2.0x. However, after 2010, the ratio grew fairly steadily to
reach 2.6x, on average, in 2015, likely as accelerated infrastructure
replacement programs were implemented across the country. A
series of high-profile gas leaks have spurred public and regulatory
support for programs that incentivize pipeline replacement, such as
riders that allow utilities to recover their investment without having
to wait for a general rate case.
For gas utilities, the CapEx-to-operating cash flow ratio has
fluctuated far more substantially than for electric utilities. Gas
utilities saw large swings in the ratio from 2000 through 2012, with
a peak of 1.6x in 2000 and a low of 0. 7 in 2009. Since reaching
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1.2x in 2012, the ratio appears to have stabilized somewhat,
although 2015 was slightly lower at 1.0x.14
Indeed, historical versus projected outlooks for the gas industry's capital
investments are shown below in Figure 2 below. As shown in this graph, gas
industry investment outlooks are expected to be considerably higher in the forecast
(2016-2018), relative to the last 10-year historical period. As noted by S&P Global
Market Intelligence, this capital investment is exceeding internal sources of funds
to the gas utilities, requiring them to seek external capital to fund capital
investments.
Figure 2
Natural Gas Utility Industry Capital Expenditures
16,000 -------------------------~-------
Forecast
14,000 +--------------------------~-------
4,000 +--------------------------~-------
2,000 +----------------------------------
O+--~-~------~--------------+------~
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Year
Source: SNL Financials, Capital Expenditure Update, October 27, 2016, Page 7
As shown in Figure 2 above, capital expenditures have been increasing for the
natural gas utility industry. At the same time, however, SNL Financial reports that
14S&P Global Market Intelligence Financial Focus: "Capital Expenditure Update," October
27, 2016 at 1 and 5.
Gorman, Di 25
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over the period 2010 through 2016 S&P the bond ratings for the natural gas utility
industry have been generally improving.15
3 Q
4
HAVE CREDIT RATING AGENCIES COMMENTED ON DECLINING
AUTHORIZED RETURNS ON EQUITY?
5 A Yes. Credit rating agencies recognize the declining trend in authorized returns
and the expectation that regulators will continue lowering the returns for U.S.
utilities while maintaining a stable credit profile. Specifically, Moody's states:
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Lower Authorized Equity Returns Will Not Hurt Near-Term
Credit Profiles
The credit profiles of US regulated utilities will remain intact over
the next few years despite our expectation that regulators will
continue to trim the sector's profitability by lowering its authorized
returns on equity (ROE).16
Further, in a recent report, S&P states:
2. Earned returns will remain in line with authorized returns
Authorized returns on equity granted by U.S. utility regulators in rate
cases this year have been steady at about 9.5%. Utilities have been
adept at earning at or very near those authorized returns in today's
economic and fiscal environment. A slowly recovering economy,
natural gas and electric prices coming down and then stabilizing at
fairly low levels, and the same experience with interest rates have
led to a perfect "non-storm" for utility ratepayers and regulators, with
utilities benefitting alongside those important constituencies.
Utilities have largely used this protracted period of favorable
circumstances to consolidate and institutionalize the regulatory
practices that support earnings and cash flow stability. We have
observed and we project continued use of credit-supportive policies
such as short lags between rate filings and final decisions, up-to­
date test years, flexible and dynamic tariff clauses for major
expense items, and alternative ratemaking approaches that allow
faster rate recognition for some new investments.17
15Ratings reported by S&P.
16Moody's Investors Service, "US Regulated Utilities: Lower Authorized Equity Returns Will
Not Hurt Near-Term Credit Profiles," March 10, 2015.
11standard & Poor's Ratings Services: "Corporate Industry Credit Research : Industry Top
Trends 2016, Utilities," December 9, 2015, at 23, emphasis added.
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HAVE UTILITIES BEEN ABLE TO ACCESS EXTERNAL CAPITAL TO
SUPPORT INFRASTRUCTURE CAPITAL PROGRAMS?
Yes. While cost of capital and authorized returns on equity were declining, the
utility industry has been able to fund substantial increases in capital investments
needed for infrastructure modernization and expansion. The Edison Electric
Institute ("EEi") reported in a 2015 financial review of the electric industry financial
performance that in 2011 electric "industry-wide capex has more than doubled
since 2005."18
EEi also observed that, despite this nearly tripling of capital expenditures
during the period 2005-2015, a majority of the funding for utilities' capital
expenditures has been provided by internal funds. EEi reports approximately 25%
of funding needed to meet these increasing capital expenditures has been derived
from external sources and 75% of these capital expenditures have been funded by
internal cash. Further, despite nearly tripling capital expenditures, the electric
utility industry debt interest expense has declined by approximately 1.9% despite
increases in the amount of outstanding debt.19 This is clear proof that capital
market costs have declined.
IS THERE EVIDENCE OF ROBUST VALUATIONS OF GAS UTILITY
SECURITIES?
Yes. These robust valuations are an indication that utilities can sell securities at
high prices, which is a strong indication that they can access capital under
reasonable terms and conditions , and at relatively low cost. As shown on my
Exhibit No. 302, the historical valuation of the gas utilities included in Dr. Gaske's
proxy group based on a price-to-earnings ratio, price-to-cash flow ratio and market
18Edison Electric Institute, 2015 Financial Review, Annual Report of the U.S. Investor­
Owned Electric Utility Industry, page 17.
19ld., pages 8 and 11 .
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price-to-book value ratio, indicates utility security valuations today are very strong
and robust relative to the last 10 to 15 years. These strong valuations of utility
stocks indicate that utilities have access to equity capital under reasonable terms
and costs.
HOW SHOULD THE COMMISSION USE THIS MARKET INFORMATION IN
ASSESSING A FAIR RETURN FOR IGC?
Market evidence is quite clear that capital market costs are near historically low
8 levels. Authorized returns on equity have fallen to the low to mid 9.0% area; utilities
9 continue to have access to large amounts of external capital to fund large capital
10 programs; and utilities' investment grade credit standings are stable to improving.
11 The Commission should carefully weigh all this important observable market
12 evidence in assessing a fair return on equity for IGC.
13 X.B. Regulated Utility Industry Market Outlook
14 Q
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PLEASE DESCRIBE THE CREDIT RATING OUTLOOK FOR REGULATED
UTILITIES.
Regulated utilities' credit ratings have improved over the last few years and the
outlook has been labeled "Stable" by credit rating agencies. Credit analysts have
also observed that utilities have strong access to capital at attractive pricing (i.e.,
low capital costs), which has supported very large capital programs.
Standard & Poor's ("S&P") recently published a report titled "Corporate
Industry Credit Research: Industry Top Trends 2016, Utilities." In that report, S&P
noted the following:
Ratings Outlook. Stable with a slight bias toward the negative.
Utilities in the U.S. continue to enjoy a confluence of financial,
economic, and regulatory environments that are tailor-made for
supporting credit quality. Low interest rates, modest economic
growth, and relatively stable commodity costs make for little
pressure on rates and therefore on the sunny disposition of
regulators.
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• Credit Metrics. We see credit metrics remaining within historic
norms for the industry as a whole and do not project overall financial
performance that would affect the industry's creditworthiness.
• Industry Trends. Taking advantage of the favorable market
conditions, utilities have been maintaining aggressive capital
spending programs to bolster system safety and reliability, as well
as technological advances to make the systems "smarter." The
elevated spending has not led to large rate increases, but if macro
conditions reverse and lead to rising costs that command higher
rates, we would expect utilities to throttle back on spending to
manage regulatory risk.20
Similarly, Fitch states:
Stable Financial Performance: The stable financial performance
of Utilities, Power & Gas (UPG) issuers continues to support a
sound credit profile for the sector, with 93% of the UPG portfolio
carrying investment-grade ratings as of June 30, 2015, including
65% in the 'BBB' rating category. Second-quarter 2015 LTM [Long­
Term Maturity] leverage metrics remained relatively unchanged
year over year (YOY) while interest coverage metrics modestly
improved. Fitch Ratings expects this trend to broadly sustain for the
remainder of 2015, driven by positive recurring factors.
Low Debt-Funded Costs: The sustained low interest rate
environment has allowed UPG companies to refinance high-coupon
legacy debt with lower coupon new debt. Gross interest expense
on an absolute value represented approximately 4.6% of total
adjusted debt as of June 30, 2015, a decline of about 150 bps from
the 6.1 % recorded in the midst of the recession. Fitch believes a
rise in interest rates would largely be neutral to credit quality, as
issuers have generally built enough headroom in coverage metrics
to withstand higher financing costs.
Capex Moderately Declining: Fitch expects the
capex/depreciation ratio to be at the lower end of its five-ye'ar
historical range of 2.0x-2.5x in the near term , reflecting a moderate
decline in projected capex from the 2011-2014 highs. The capex
depreciation ratio was relatively flat YOY at about 2.4x. Capex
targets investments toward base infrastructure upgrades, utility­
scale renewables and transmission investments.
* * *
Key credit metrics for IUCs [investor-owned utility companies]
remained relatively stable YOY and continue to support the sound
credit profiles and Stable Outlooks characteristic of the sector.
EBITDAR [Earnings Before Interest, Taxes, Depreciation,
2ostandard & Poor's Ratings Services: "Corporate Industry Credit Research : Industry Top
Trends 2016, Utilities," December 9, 2015, at 22, emphasis added.
Gorman, Di 29
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Amortization and Rent] and FFO [Funds From Operations]
coverage ratios were 5.6x and 5.9x, respectively, for the L TM ended
second-quarter 2015, while adjusted debt/EDITDAR and FFO­
adjusted leverage were 3.5x and 3.4x, respectively.21
Moody's recent comments on the U.S. Utility Sector state as follows:
Our outlook for the US regulated utilities industry is stable. This
outlook reflects our expectations for fundamental business
conditions in the industry over the next 12 to 18 months.
» The credit-supportive regulatory environment is the main
reason for our stable outlook. We expect that the relationship
between regulators and utilities in 2016 will remain credit­
supportive, enabling utilities to recover costs in a timely manner and
maintain stable cash flows.
» We estimate that the ratio of cash flow from operations (CFO)
to debt will hold steady at about 21 %, on average for the
industry, over the next 12 to 18 months. The use of timely cost­
recovery mechanisms and continued expense management will
help utilities offset a lack of growth in electricity demand and lower
allowed returns on equity, enabling financial metrics to remain
stable. Tax benefits tied to the expected extension of bonus
depreciation will also support CFO-to-debt ratios.
* * *
» Utilities are increasingly using holding company leverage to
drive returns, a credit negative. Although not a driver of our
outlook, utilities are using leverage at the holding company level to
invest in other businesses, make acquisitions and earn higher
returns on equity, which could have negative implications across
the whole family.22
29 Q PLEASE DESCRIBE UTILITY STOCK PRICE PERFORMANCE OVER THE
LAST SEVERAL YEARS. 30
31
32
33
34
A As shown in the graph below, SNL Financial has recorded utility stock price
performance compared to the market. The industry's stock performance data from
2004 through September 2016 shows that the SNL Electric and Gas Company
Indexes have outperformed the market in downturns and trailed the market during
21 Fitch Ratings: "U.S. Utilities, Power & Gas Data comparator," September 21 , 2015, at 1
and 7, emphasis added.
22Moody's Investors Service: "2016 Outlook -US Regulated Utilities: Credit-Supportive
Regulatory Environment Drives Stable Outlook," November 6, 2015, at 1, emphasis added.
Gorman, Di 30
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recovery. This relatively stable price performance for utilities supports my
conclusion that utility stock investments are regarded by market participants as a
moderate-to low-risk investment.
FIGURE 3
Index Comparison
40.0% ~------------------------
30.0% t---,1..-:,-----------,------------y'=,,_--=------
E 10.0% r-'"""""-'-<"=-:-?""~-._-,--------i,-..-.~-,-,-..._
::,
--+--SNL Electric
: 0.0% 1-------------1~--.t,-----"'---A-------"--..-"J&----Ir · SNLGas ! -10.0% ,__ ______ ___,.,.._...,_._ ______________ _
~
:_ -20.0% f-------------\-';--;>1-----------------S&P500
-40.0% ,__ _______________________ _
-50.0% ,__ _______________________ _
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Source: SNL Financial, data through September 30, 2016.
HAVE ELECTRIC UTILITY INDUSTRY TRADE ORGANIZATIONS
COMMENTED ON ELECTRIC UTILITY STOCK PRICE PERFORMANCE?
Yes. In its 4th Quarter 2015 Financial Update, the EEi stated the following
concerning the EEi Electric Utility Stock Index ("EEi Index"):
EEi Index returns during 2015 embodied the larger pattern seen in
Table I since the 2008/2009 financial crisis, as industry business
models have migrated to an increasingly regulated emphasis. The
industry has generated consistent positive returns but has lagged
the broader markets when markets post strong gains, which in turn
have been sparked both by slow but steady U.S. economic growth
and corporate profit gains and by the willingness of the Federal
Reserve to bolster markets with historically unprecedented
monetary support in the form of three rounds of quantitative easing
and near-zero short-term interest rates. While the Fed did raise
short-term rates in December 2015 for the first time since 2006
(from zero to a range of 0.25% to 0.50%), this hardly effects [sic]
longer-term yields, which remain at historically low levels and are
influenced more by the level of inflation and economic strength than
by the Fed's short-term rate policy.
Gorman, Di 31
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* * *
Regulated Fundamentals Remain Stable
The rate stability offered by state regulation and the ability to
recover rising capital spending in rate base shield regulated utilities
from the volatility in the competitive power arena and turn the
growth of renewable generation (and the resulting need for new and
upgraded transmission lines) into a rate base growth opportunity for
many industry players.
* * *
In the shorter-term, analysts continue to see opportunity for 4-6%
earnings growth for regulated utilities in general along with
prospects for slightly rising dividends (with a dividend yield now at
about 4% for the industry overall). That formula has served utility
investors quite well in recent years, delivering long-term returns
equivalent to those of the broad markets but with much lower
volatility. Provided state regulation remains fair and constructive in
an effort to address the interests of ratepayers and investors, it
would appear that the industry can continue to deliver success for
all stakeholders, even in an environment of flat demand and
considerable technological change.23
WHAT ARE THE IMPORTANT TAKEAWAY POINTS FROM THIS
ASSESSMENT OF UTILITY INDUSTRY CREDIT AND INVESTMENT RISK
OUTLOOKS?
Credit rating agencies consider the regulated utility industry to be "Stable" and
believe investors will continue to provide an abundance of low-cost capital to
support utilities' large capital programs at attractive costs and terms. All of this
reinforces my belief that utility investments are generally regarded as safe-haven
or low-risk investments and the market continues to demand low-risk investments
such as utility securities. The ongoing demand for low-risk investments can
reasonably be expected to continue to provide attractive low-cost capital for
regulated utilities.
23EEI Q4 2015 Financial Update: "Stock Performance" at 4 and 6, emphasis added.
Gorman, Di 32
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1 X.C. IGC Investment Risk
2 Q
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4 A
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40
PLEASE DESCRIBE THE MARKET'S ASSESSMENT OF THE INVESTMENT
RISK OF IGC.
The market's assessment of IGC's investment risk is described by credit rating
analysts' reports. IGC does not have a stand-alone credit rating from S&P; rather,
it is a wholly-owned subsidiary of MDU Resources. MDU Resources' current
corporate bond rating from S&P is BBB+ with a Stable outlook. MDU Resources
is not rated by Moody's. Specifically, S&P states:
Rationale
The stable outlook reflects MDU's announced sale of its
unregulated natural gas processing facility, which is consistent with
the company's longer-term strategy of selling its higher risk assets
and focusing its growth on its lower-risk regulated businesses. The
company's recent sale of its exploration and production businesses
and its oil refinery increases our confidence that the company will
continue to successfully execute on this strategy. On a forward­
looking basis, we expect that the lower-risk regulated utility and
pipeline businesses will account for more than 50% of the
consolidated company. Based on the lower-risk strategy, MDU's
financial measures will be better positioned in the future to support
our current view of the company's financial risk.
MDU's business risk profile incorporates our combined view of its
various diverse businesses, which include lower-risk regulated
utilities, partially offset by relatively higher-risk construction
services. On a forward-looking basis we view MDU as consisting of
four primary business segments: regulated utilities (44%), regulated
pipelines (8%), construction materials (37%), and construction
services (11%). MDU's regulated utility businesses serve
approximately 1 million customers in Idaho, Minnesota , Montana,
North Dakota, Oregon, South Dakota, Washington , and Wyoming .
Overall, MDU has been able to successfully work with regulators
and effectively manage regulatory risk. Following the sale of MDU's
unregulated natural gas processing assets, the gas midstream
operation assets will consist almost entirely of lower-risk regulated
pipeline operations and will make-up about 8% of consolidated
MDU.
* * *
We assess MDU's financial risk based on our projections that FFO
to debt will approximate 17%-20%. We expect the company's
financial measures to gradually improve and stabilize following the
Gorman, Di 33
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sale of its higher risk assets and the use of proceeds to reduce debt.
Under our base-case scenario of continued rate case increases,
capital spending at about $350 million, modest utility customer
growth, and continued EBITDA growth at the construction materials
business, we expect 2017 FFO to debt of about 18%, placing the
company solidly in its financial risk profile category.24
XI. IGC'S PROPOSED CAPITAL STRUCTURE
WHAT IS IGC'S PROPOSED CAPITAL STRUCTURE?
IGC's proposed capital structure is shown below in Table 5. This is IGC's targeted
10 capital structure and consistent with IGC's actual capital structure over the previous
11 three years. IGC's proposed capital structure is sponsored by IGC witness Mr.
12 Mark Chiles.
TABLE 5
IGC's Proposed Capital Structure
Description
Long-Term Debt
Common Equity
Total
Source: Chiles Direct at 2.
Weight
50.00%
50.00%
100.00%
13 Q PLEASE COMMENT ON IGC'S PROPOSED CAPITAL STRUCTURE.
14 A IGC's proposed capital structure is not reasonable. The Company's most recent
capital structure as shown on its FERC Form 2 for the period ending December 31 ,
2015, is composed of approximately 48% common equity and 52% long-term debt.
This capital structure as of December 31, 2015 is developed in Table 6 below.
15
16
17
24S&P Global Ratings: "Research Update: MDU Resources Group Inc. Outlook Revised
To Stable From Negative On Planned Sale Of Unregulated Assets; Ratings Affirmed," November
21 , 2016 at 2-3.
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TABLE 6
IGC Actual Capital Structure
(Year-end 2015)
Description
Long-Term Debt
Common Equity
Total
Weight
52%
48%
100%
Source: FERC Form 2 for the period
ending December 31 , 2015.
I recommend using IGC's actual capital structure at this date as a reasonable
ratemaking capital structure for setting rates.
WHY DO YOU BELIEVE THAT A CAPITAL STRUCTURE COMPOSED OF 48%
COMMON EQUITY WOULD BE REASONABLE FOR SETTING RATES?
This capital structure is reasonably consistent with IGC's parent company's use of
a capital structure for setting rates for its operating utility subsidiaries. For
example, in a recent case in Oregon, Cascade Natural Gas Company settled for a
ratemaking overall rate of return based on a 9.4% return on equity and a capital
structure composed of 49% common equity. My recommended capital structure
is reasonably consistent with that rating.
Further, credit rating agencies are aware of MDU's ratemaking settlements
in proceedings, and have concluded that MDU's credit rating outlook is "Stable,"
at a strong investment grade rating of BBB+ from S&P. A second consideration is
a capital structure that contains more common equity than necessary to support
an investment grade bond rating at IGC and its parent company will unnecessarily
increase costs to retail customers. Increasing the common equity ratio of total
capital will increase the overall rate of return and related income tax expense.
Gorman, Di 35
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1 Hence, a capital structure with a more reasonable balance of common equity and
2 debt will lower the overall rate of return, income tax expense and revenue
3 requirement, while preserving IGC's strong investment grade bond rating as
4 proxied through that of its parent company, MDU Resources, and reflects a better
5 balance of the interests of MDU's shareholders and retail customers in its Idaho
6 service territory.
7 XI.A. Embedded Cost of Debt
8 Q
9 A
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13 Q
14
15 A
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18 Q
19
20 A
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WHAT IS THE COMPANY'S EMBEDDED COST OF DEBT?
Mr. Chiles is proposing an embedded cost of debt of 4.94% as developed on page
1 of his Exhibit No. 03.
I will not take issue with IGC's embedded debt cost.
XII. RETURN ON EQUITY
PLEASE DESCRIBE WHAT IS MEANT BY A "UTILITY'S COST OF COMMON
EQUITY."
A utility's cost of common equity is the expected return that investors require on
an investment in the utility. Investors expect to earn their required return from
receiving dividends and through stock price appreciation.
PLEASE DESCRIBE THE FRAMEWORK FOR DETERMINING A REGULATED
UTILITY'S COST OF COMMON EQUITY.
In general, determining a fair cost of common equity for a regulated utility has been
framed by two hallmark decisions of the U.S. Supreme Court: Bluefield Water
Works & Improvement Co. v. Pub. Serv. Comm'n of W. Va., 262 U.S. 679 (1923)
and Fed. Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591 (1944).
These decisions identify the general financial and economic standards to
be considered in establishing the cost of common equity for a public utility. Those
general standards provide that the authorized return should: (1) be sufficient to
Gorman, Di 36
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maintain financial integrity; (2) attract capital under reasonable terms; and (3) be
commensurate with returns investors could earn by investing in other enterprises
of comparable risk.
PLEASE DESCRIBE THE METHODS YOU HAVE USED TO ESTIMATE IGC'S
COST OF COMMON EQUITY.
I have used several models based on financial theory to estimate IGC's cost of
7 common equity. These models are: (1) a constant growth Discounted Cash Flow
8 ("DCF") model using consensus analysts' growth rate projections; (2) a constant
9 growth DCF using sustainable growth rate estimates; (3) a multi-stage growth DCF
10 model; (4) a Risk Premium model; and (5) a Capital Asset Pricing Model ("CAPM").
11 I have applied these models to a group of publicly traded utilities with investment
12 risk similar to IGC.
13 XII.A. Risk Proxy Group
14 Q
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PLEASE DESCRIBE HOW YOU IDENTIFIED A GAS PROXY UTILITY GROUP
THAT COULD BE USED TO REASONABLY REFLECT THE INVESTMENT
RISK OF IGC AND USED TO ESTIMATE ITS CURRENT MARKET COST OF
EQUITY.
I used the same gas utility proxy group as IGC witness Dr. Gaske. Dr. Gaske
started with companies included in the Natural Gas Utility Industry as followed by
The Value Line Investment Survey ("Value Line"). He then excluded from the
Value Line Natural Gas Utility Industry companies with available retention growth
rates that: (1) did not have an investment grade credit rating from S&P and
Moody's, (2) companies that did not pay dividends, (3) did not have growth rate
projections from Zack's or Thomson First Call; and (4) companies that were
involved in significant merger or acquisition activity. Additionally, Dr. Gaske
removed any proxy company that did not derive at least 70% of its operating
Gorman, Di 37
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A
income from regulated natural gas distribution operations, or did not have at least
70% of its assets devoted to regulated natural gas distribution operations.25
Based on these selection criteria, it appears that Dr. Gaske excluded
NiSource because it cut its dividend in the third quarter of 2015 and restructured
its company by spinning off its midstream gas assets. It appears that Dr. Gaske
excluded UGI because it was involved in M&A activity in 2015. The term and scale
of the M&A activity were not fully disclosed in public reports.
WHY IS IT APPROPRIATE TO EXCLUDE COMPANIES WHICH ARE
INVOLVED IN MERGER AND ACQUISITION ("M&A") ACTIVITY FROM THE
PROXY GROUP?
M&A activity can distort the market factors used in DCF and risk premium studies.
M&A activity can have impacts on stock prices, growth outlooks, and relative
volatility in historical stock prices if the market was anticipating or expecting the
M&A activity prior to it actually being announced. This distortion in the market data
thus impacts the reliability of the DCF and risk premium estimates for a company
involved in M&A.
Moreover, companies generally enter into M&A in order to produce greater
shareholder value by combining companies. The enhanced shareholder value
normally could not be realized had the two companies not combined.
When companies announce an M&A, the public assesses the proposed
merger and develops outlooks on the value of the two companies after the
combination based on expected synergies or other value adds created by the
M&A.
As a result, the stock value before the merger is completed may not reflect
the forward-looking earnings and dividend payments for the company absent the
25Gaske Direct at 18-19.
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merger or on a stand-alone basis. Therefore, an accurate DCF return estimate on
companies involved in M&A activities cannot be produced because their stock
prices do not reflect the stand-alone investment characteristics of the companies.
Rather, the stock price more likely reflects the shareholder enhancement produced
by the proposed transaction. For these reasons, it is appropriate to remove
companies involved in M&A activity from a proxy group used to estimate a fair
return on equity for a utility.
PLEASE DESCRIBE WHY YOU BELIEVE YOUR PROXY GROUP IS
REASONABLY COMPARABLE IN INVESTMENT RISK TO IGC.
The proxy group is shown in my Exhibit No. 303. The proxy group has an average
corporate credit rating from S&P of A, which is higher than S&P's corporate credit
rating for MDU Resources of BBB+. The proxy group has an average corporate
credit rating from Moody's of A2. MDU Resources is not rated by Moody's. Based
on this information, I believe the proxy group is less risky, but reasonably
comparable in investment risk to IGC.
The proxy group has an average common equity ratio of 48.0% (including
short-term debt) from SNL Financial ("SNL") and 53.6% (excluding short-term
debt) from The Value Line Investment SuNey ("Value Line") in 2015.
My proposed common equity ratio of 48.0% is identical to the proxy group
common equity ratio including short-term debt. Based on these risk factors,
conclude the proxy group reasonably approximates the investment risk of IGC.
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1 XII.B. Discounted Cash Flow Model
2 Q
3 A
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7
PLEASE DESCRIBE THE DCF MODEL.
The DCF model posits that a stock price is valued by summing the present value
of expected future cash flows discounted at the investor's required rate of return
or cost of capital. This model is expressed mathematically as follows:
D~
(1+Kt
(Equation 1)
8 Po = Current stock price
9 D = Dividends in periods 1 -00
10 K = Investor's required return
11 This model can be rearranged in order to estimate the discount rate or
12 investor-required return otherwise known as "K." If it is reasonable to assume that
13 earnings and dividends will grow at a constant rate, then Equation 1 can be
14 rearranged as follows:
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(Equation 2)
K = Investor's required return
01 = Dividend in first year
Po = Current stock price
G = Expected constant dividend growth rate
Equation 2 is referred to as the annual "constant growth" DCF model.
PLEASE DESCRIBE THE INPUTS TO YOUR CONSTANT GROWTH DCF
MODEL.
As shown in Equation 2 above, the DCF model requires a current stock price,
expected dividend, and expected growth rate in dividends.
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WHAT STOCK PRICE HAVE YOU RELIED ON IN YOUR CONSTANT GROWTH
DCF MODEL?
I relied on the average of the weekly high and low stock prices of the utilities in the
proxy group over a 13-week period ending on November 10, 2016 for the proxy
group. An average stock price is less susceptible to market price variations than
a price at a single point in time. Therefore, an average stock price is less
susceptible to aberrant market price movements, which may not reflect the stock's
long-term value.
A 13-week average stock price reflects a period that is still short enough to
contain data that reasonably reflects current market expectations but the period is
not so short as to be susceptible to market price variations that may not reflect the
stock's long-term value. In my judgment, a 13-week average stock price is a
reasonable balance between the need to reflect current market expectations and
the need to capture sufficient data to smooth out aberrant market movements.
WHAT DIVIDEND DID YOU USE IN YOUR CONSTANT GROWTH DCF
MODEL?
I used the most recently paid quarterly dividend as reported in Value Line.26 This
dividend was annualized (multiplied by 4) and adjusted for next year's growth to
produce the D1 factor for use in Equation 2 above.
WHAT DIVIDEND GROWTH RATES HAVE YOU USED IN YOUR CONSTANT
GROWTH DCF MODEL?
There are several methods that can be used to estimate the expected growth in
dividends. However, regardless of the method , for purposes of determining the
market-required return on common equity, one must attempt to estimate investors'
26The Value Line Investment Survey, September 2, 2016.
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consensus about what the dividend, or earnings growth rate , will be, and not what
an individual investor or analyst may use to make individual investment decisions.
As predictors of future returns, security analysts' growth estimates have
been shown to be more accurate than growth rates derived from historical data.27
That is, assuming the market generally makes rational investment decisions,
analysts' growth projections are more likely to influence investors' decisions which
are captured in observable stock prices than growth rates derived only from
historical data.
For my constant growth DCF analysis, I have relied on a consensus, or
mean, of professional security analysts' earnings growth estimates as a proxy for
investor consensus dividend growth rate expectations. I used the average of
analysts' growth rate estimates from three sources: Zacks, SNL, and Reuters. All
such projections were available on November 11, 2016, and all were reported
online.
Each consensus growth rate projection is based on a survey of security
analysts. There is no clear evidence whether a particular analyst is most influential
on general market investors. Therefore, a single analyst's projection does not as
reliably predict consensus investor outlooks as does a consensus of market
analysts' projections. The consensus estimate is a simple arithmetic average, or
mean, of surveyed analysts' earnings growth forecasts. A simple average of the
growth forecasts gives equal weight to all surveyed analysts' projections.
Therefore, a simple average, or arithmetic mean, of analyst forecasts is a good
proxy for market consensus expectations.
27See, e.g., David Gordon, Myron Gordon, and Lawrence Gould, "Choice Among Methods
of Estimating Share Yield," The Journal of Portfolio Management, Spring 1989.
Gorman, Di 42
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1 Q
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3 A
4
5 Q
6 A
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11
12 A
WHAT ARE THE GROWTH RATES YOU USED IN YOUR CONSTANT
GROWTH DCF MODEL?
The growth rates I used in my DCF analysis are shown in my Exhibit No. 304. The
average growth rate for the proxy group is 6.24%.
WHAT ARE THE RESULTS OF YOUR CONSTANT GROWTH DCF MODEL?
As shown in my Exhibit No. 305, the average and median constant growth DCF
returns for the proxy group are 9.38% and 8.99%, respectively. The proxy group
median better describes the central tendency of the proxy group results because
the group average is skewed by high-end outliers.
DO YOU HAVE ANY COMMENTS ON THE RESULTS OF YOUR CONSTANT
GROWTH DCF ANALYSIS?
Yes. The constant growth DCF analysis for the proxy group is based on a group
13 average long-term sustainable growth rates of 6.24%. The three-to five-year
14 growth rates are higher than my estimate of a maximum long-term sustainable
15 growth rate of 4.25%, which I discuss later in this testimony. Further, the DCF
16 result based on the proxy group is subject to an outlier. Mainly, the DCF return for
17 South Jersey Industries is almost 14% and is based on a growth rate estimate of
18 10.00%. Therefore, the median DCF result for the proxy group more accurately
19 reflects the central tendency of the group. Hence, for all these reasons I believe
20 the constant growth DCF analysis produces a reasonable high-end return
21 estimate.
22 Q
23
24 A
25
26
HOW DID YOU ESTIMATE A MAXIMUM LONG-TERM SUSTAINABLE
GROWTH RATE?
A long-term sustainable growth rate for a utility stock cannot exceed the growth
rate of the economy in which it sells its goods and services. Hence, the long-term
maximum sustainable growth rate for a utility investment is best proxied by the
Gorman, Di 43
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1 projected long-term Gross Domestic Product ("GDP"). Blue Chip Financial
2 Forecasts projects that over the next 5 and 10 years, the U.S. nominal GDP will
3 grow approximately 4.25%. These GDP growth projections reflect a real growth
4 outlook of around 2.2% and an inflation outlook of around 2.1 % going forward . As
5 such, the average growth rate over the next 10 years is around 4.25%, which I
6 believe is a reasonable proxy of long-term sustainable growth.28
7 In my multi-stage growth DCF analysis, I discuss academic and investment
8 practitioner support for using the projected long-term GDP growth outlook as a
9 maximum sustainable growth rate projection. Hence, recognizing the long-term
10 GDP growth rate as a maximum sustainable growth is logical, and is generally
11 consistent with academic and economic practitioner accepted practices.
12 XII.C. Sustainable Growth DCF
13 Q
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PLEASE DESCRIBE HOW YOU ESTIMATED A SUSTAINABLE LONG-TERM
GROWTH RATE FOR YOUR SUSTAINABLE GROWTH DCF MODEL.
A sustainable growth rate is based on the percentage of the utility's earnings that
is retained and reinvested in utility plant and equipment. These reinvested
earnings increase the earnings base (rate base). Earnings grow when plant
funded by reinvested earnings is put into service, and the utility is allowed to earn
its authorized return on such additional rate base investment.
The internal growth methodology is tied to the percentage of earnings
retained in the company and not paid out as dividends. The earnings retention
ratio is 1 minus the dividend payout ratio . As the payout ratio declines, the
earnings retention ratio increases. An increased earnings retention ratio will fuel
stronger growth because the business funds more investments with retained
earnings.
268/ue Chip Financial Forecasts, December 1, 2016, at 14.
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The payout ratios of the proxy groups are shown in my Exhibit No. 306.
These dividend payout ratios and earnings retention ratios then can be used to
develop a sustainable long-term earnings retention growth rate. A sustainable
long-term earnings retention ratio will help gauge whether analysts' current three­
to five-year growth rate projections can be sustained over an indefinite period of
time.
The data used to estimate the long-term sustainable growth rate is based
on the Company's current market-to-book ratio and on Value Line's three-to five­
year projections of earnings, dividends, earned returns on book equity, and stock
issuances.
As shown in my Exhibit No. 307, the average sustainable growth rate for
the proxy group using this internal growth rate model is 6.55%.
WHAT IS THE DCF ESTIMATE USING THESE SUSTAINABLE LONG-TERM
GROWTH RATES?
A DCF estimate based on these sustainable growth rates is developed in my
16 Exhibit No. 308. The sustainable growth DCF analysis for the proxy group
17 produces an average and median result of 9.69%.
18 XII.D. Multi-Stage Growth DCF Model
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HAVE YOU CONDUCTED ANY OTHER DCF STUDIES?
Yes. My first constant growth DCF is based on consensus analysts' growth rate
projections so it is a reasonable reflection of rational investment expectations over
the next three to five years. The limitation on this constant growth DCF model is
that it cannot reflect a rational expectation that a period of high or low short-term
growth can be followed by a change in growth to a rate that is more reflective of
long-term sustainable growth. Hence, I performed a multi-stage growth DCF
analysis to reflect this outlook of changing growth expectations.
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WHY DO YOU BELIEVE GROWTH RATES CAN CHANGE OVER TIME?
Analyst-projected growth rates over the next three to five years will change as
utility earnings growth outlooks change. Utility companies go through cycles in
making investments in their systems. When utility companies are making large
investments, their rate base grows rapidly, which in turn accelerates earnings
growth. Once a major construction cycle is completed or levels off, growth in the
utility rate base slows and its earnings growth slows from an abnormally high three­
to five-year rate to a lower sustainable growth rate.
As major construction cycles extend over longer periods of time, even with
an accelerated construction program, the growth rate of the utility will slow simply
because rate base growth will slow and the utility has limited human and capital
resources available to expand its construction program. Therefore, the three-to
five-year growth rate projection should be used as a long-term sustainable growth
rate, but not without making a reasonable informed judgment to determine whether
it considers the current market environment, the industry, and whether the three­
to five-year growth outlook is sustainable.
PLEASE DESCRIBE YOUR MULTI-STAGE GROWTH DCF MODEL.
The multi-stage growth DCF model reflects the possibility of non-constant growth
for a company over time. The multi-stage growth DCF model reflects three growth
periods: ( 1) a short-term growth period consisting of the first five years; (2) a
transition period, consisting of the next five years (6 through 1 O); and (3) a
long-term growth period starting in year 11 through perpetuity.
For the short-term growth period, I relied on the consensus analysts' growth
projections described above in relationship to my constant growth DCF model. For
the transition period, the growth rates were reduced or increased by an equal factor
reflecting the difference between the analysts' growth rates and the long-term
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sustainable growth rate. For the long-term growth period, I assumed each
company's growth would converge to the maximum sustainable long-term growth
rate.
WHY IS THE GDP GROWTH PROJECTION A REASONABLE PROXY FOR THE
MAXIMUM SUSTAINABLE LONG-TERM GROWTH RATE?
Utilities cannot indefinitely sustain a growth rate that exceeds the growth rate of
7 the economy in which they sell services. Utilities' earnings/dividend growth is
8 created by increased utility investment or rate base. Such investment, in turn, is
9 driven by service area economic growth and demand for utility service. In other
10 words, utilities invest in plant to meet sales demand growth. Sales growth, in turn,
11 is tied to economic growth in their service areas.
12 The U.S. Department of Energy, Energy Information Administration ("EIA")
13 has observed utility sales growth tracks the U.S. GDP growth, albeit at a lower
14 level, as shown in my Exhibit No. 309. Utility sales growth has lagged behind GDP
15 growth for more than a decade. As a result, nominal GDP growth is a very
16 conservative proxy for utility sales growth, rate base growth , and earnings growth.
17 Therefore, the U.S. GDP nominal growth rate is a conservative proxy for the
18 highest sustainable long-term growth rate of a utility.
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IS THERE RESEARCH THAT SUPPORTS YOUR POSITION THAT, OVER THE
LONG TERM, A COMPANY'S EARNINGS AND DIVIDENDS CANNOT GROW
AT A RATE GREATER THAN THE GROWTH OF THE U.S. GDP?
Yes. This concept is supported in published analyst literature and academic work.
Specifically, in a textbook titled "Fundamentals of Financial Management,"
published by Eugene Brigham and Joel F. Houston , the authors state as follows:
The constant growth model is most appropriate for mature
companies with a stable history of growth and stable future
expectations. Expected growth rates vary somewhat among
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companies, but dividends for mature firms are often expected to
grow in the future at about the same rate as nominal gross domestic
product (real GDP plus inflation).29
The use of the economic growth rate is also supported by investment
practitioners:
Estimating Growth Rates
One of the advantages of a three-stage discounted cash flow model
is that it fits with life cycle theories in regards to company growth.
In these theories, companies are assumed to have a life cycle with
varying growth characteristics. Typically, the potential for
extraordinary growth in the near term eases over time and
eventually growth slows to a more stable level.
* * *
Another approach to estimating long-term growth rates is to focus
on estimating the overall economic growth rate. Again, this is the
approach used in the Ibbotson Cost of Capital Yearbook. To obtain
the economic growth rate , a forecast is made of the growth rate's
component parts. Expected growth can be broken into two main
parts: expected inflation and expected real growth. By analyzing
these components separately, it is easier to see the factors that
drive growth. 30
IS THERE ANY ACTUAL INVESTMENT HISTORY THAT SUPPORTS THE
NOTION THAT THE CAPITAL APPRECIATION FOR STOCK INVESTMENTS
WILL NOT EXCEED THE NOMINAL GROWTH OF THE U.S. GDP?
Yes. This is evident by a comparison of the compound annual growth of the U.S.
GDP compared to the geometric growth of the U.S. stock market. Morningstar
measures the historical geometric growth of the U.S. stock market over the period
1926-2015 to be approximately 5.8%. During this same time period, the U.S.
nominal compound annual growth of the U.S. GDP was approximately 6.2%.31
29"Fundamentals of Financial Management," Eugene F. Brigham and Joel F. Houston,
Eleventh Edition 2007, Thomson South-Western, a Division of Thomson Corporation at 298 ,
emphasis added.
30Morningstar, Inc., Ibbotson SBBI 2013 Valuation Yearbook at 51 and 52.
31LJ .S. Bureau of Economic Analysis, January 29 , 2016.
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As such, the compound geometric growth of the U.S. nominal GDP has
been higher but comparable to the nominal growth of the U.S. stock market capital
appreciation. This historical relationship indicates that the U.S. GDP growth
outlook is a conservative estimate of the long-term sustainable growth of U.S.
stock investments.
HOW DID YOU DETERMINE A SUSTAINABLE LONG-TERM GROWTH RATE
THAT REFLECTS THE CURRENT CONSENSUS OUTLOOK OF THE
MARKET?
I relied on the consensus analysts' projections of long-term GDP growth. Blue
Chip Economic Indicators publishes consensus economists' GDP growth
projections twice a year. These consensus analysts' GDP growth outlooks are the
best available measure of the market's assessment of long-term GDP growth.
These analyst projections reflect all current outlooks for GDP and are likely the
most influential on investors' expectations of future growth outlooks. The
consensus economists' published GDP growth rate outlook is 4.10% over the next
10 years.32
Therefore, I propose to use the consensus economists' projected 5-and
10-year average GDP consensus growth rates of 4.25%, as published by Blue
Chip Financial Forecasts, as an estimate of long-term sustainable growth. Blue
Chip Financial Forecasts projections provide real GDP growth projections of 2.2%
and 2.1 % and GDP inflation of 2.1 % and 2.0%33 over the 5-year and 10-year
projection periods, respectively. These consensus GDP growth forecasts
represent the most likely views of market participants because they are based on
published consensus economist projections.
328/ue Chip Financial Forecasts, December 1, 2016, at 14.
33/d.
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DO YOU CONSIDER OTHER SOURCES OF PROJECTED LONG-TERM GDP
GROWTH?
Yes, and these sources corroborate my consensus analysts' projections, as shown
below in Table 74.
TABLE 7
GDP Forecasts
Real Nominal
Source Term GDP Inflation GDP
Blue Chip Financial Forecasts 5-10 Yrs 2.2% 2.1% 4.3%
EIA -Annual Earnings Outlook 25 Yrs 2.2% 2.1% 4.4%
Congressional Budget Office 10 Yrs 2.0% 2.0% 4.0%
Moody's Analytics 30 Yrs 2.0% 2.0% 4.1%
Social Security Administration 50 Yrs 4.4%
The Economist Intelligence Unit 35 Yrs 1.9% 2.0% 3.9%
5 The EIA in its Annual Energy Outlook projects real GDP out until 2040. In
6 its 2016 Annual Report, the EIA projects real GDP through 2040 to be 2.2% and a
7 long-term GDP price inflation projection of 2.1 %. The EIA data supports a long-
8 term nominal GDP growth outlook of 4.4%.34
9 Also, the Congressional Budget Office ("CBO") makes long-term economic
1 O projections. The CBO is projecting real GDP growth to be 2.0% during the next
11 1 O years with a GDP price inflation outlook of 2.0%. 35 The CBO 10-year outlook
12 for nominal GDP based on this projection is 4.0%.
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Moody's Analytics also makes long-term economic projections. In its
recent 30-year outlook to 2045, Moody's Analytics is projecting real GDP growth
34DOE/EIA Annual Energy Outlook 2016 With Projections to 2040, May 2016, Table 20.
35CBO: The Budget and Economic Outlook: 2016 to 2026, January 2016, at 140.
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of 2.0% with GDP inflation of 2.0%.36 Based on these projections, Moody's is
projecting nominal GDP growth of 4.1 % over the next 30 years.
The Social Security Administration ("SSA") makes long-term economic
projections out to 2090. The SSA's nominal GDP projection, under its intermediate
cost scenario of 50 years, is 4.4%.37 The Economist Intelligence Unit, a division
of The Economist and a third-party data provider to SNL Financial, makes a long­
term economic projection out to 2050.38 The Economist Intelligence Unit is
projecting real GDP growth of 1.9% with an inflation rate of 2.0% out to 2050. The
real GDP growth projection is in line with the consensus economists. The long­
term nominal GDP projection based on these outlooks is approximately 3.9%.
The real GDP and nominal GDP growth projections made by these
independent sources support the use of the consensus economist 5-year and 10-
year projected GDP growth outlooks as a reasonable estimate of market
participants' long-term GDP growth outlooks.
WHAT STOCK PRICE, DIVIDEND, AND GROWTH RATES DID YOU USE IN
YOUR MULTI-STAGE GROWTH DCF ANALYSIS?
I relied on the same 13-week average stock prices and the most recent quarterly
dividend payment data discussed above. For stage one growth, I used the
consensus analysts' growth rate projections discussed above in my constant
growth DCF model. The first stage growth covers the first five years, consistent
with the term of the analyst growth rate projections. The second stage, or transition
stage, begins in year 6 and extends through year 10. The second stage growth
transitions the growth rate from the first stage to the third stage using a linear trend.
For the third stage, or long-term sustainable growth stage, starting in year 11 , I
3flwww.economy.com , Moody's Analytics Forecast, January 6, 2016.
37www.ssa.gov, "2016 OASDI Trustees Report," Table VI.G4.
38SNL Financial, Economist Intelligence Unit, downloaded on January 13, 2016.
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used a 4.25% long-term sustainable growth rate based on the consensus
economists' long-term projected nominal GDP growth rate.
WHAT ARE THE RESULTS OF YOUR MULTI-STAGE GROWTH DCF MODEL?
As shown in my Exhibit No. 310, the average and median DCF returns on equity
for the proxy group are 7.79% and 7.57%, respectively.
PLEASE SUMMARIZE THE RESULTS FROM YOUR DCF ANALYSES.
The results from my DCF analyses are summarized in Table 8 below:
TABLE 8
Summary of DCF Results
Description
Constant Growth DCF Model
(Analysts' Growth)
Constant Growth DCF Model
(Sustainable Growth)
Multi-Sta e Growth DCF Model
Proxy Group
Average Median
9.38% 8.99%
9.69% 9.69%
7.79% 7.57%
8 I conclude that my DCF studies support a return on equity of 9.40% for the
9 proxy group. I gave primary weight to based on my median constant growth DCF
1 O (analysts' growth) result and the results of my constant growth DCF (sustainable
11 growth), which I find as a reasonable estimate of the proxy group's central
12 tendency and a reasonable high-end DCF return estimate.
13 XII.E. Risk Premium Model
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PLEASE DESCRIBE YOUR BOND YIELD PLUS RISK PREMIUM MODEL.
This model is based on the principle investors require a higher return to assume
greater risk. Common equity investments have greater risk than bonds because
bonds have more security of payment in bankruptcy proceedings than common
equity and the coupon payments on bonds represent contractual obligations. In
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contrast, companies are not required to pay dividends or guarantee returns on
common equity investments. Therefore, common equity securities are considered
to be riskier than bond securities.
This risk premium model is based on two estimates of an equity risk
premium. First, I estimated the difference between the required return on utility
common equity investments and U.S. Treasury bonds. The difference between
the required return on common equity and the Treasury bond yield is the risk
premium. I estimated the risk premium on an annual basis for each year over the
period January 1986 through September 2016. The common equity required
returns were based on regulatory commission-authorized returns for electric utility
companies. Authorized returns are typically based on expert witnesses' estimates
of the contemporary investor-required return.
The second equity risk premium estimate is based on the difference
between regulatory commission-authorized returns on common equity and
contemporary "A" rated utility bond yields by Moody's. I selected the period
January 1986 through September 2016 because public utility stocks consistently
traded at a premium to book value during that period . This is illustrated in my
Exhibit No. 311 , which shows the market-to-book ratio since 1986 for the electric
utility industry was consistently above a multiple of 1.0x. Over this period ,
regulatory authorized returns were sufficient to support market prices that at least
exceeded book value. This is an indication that regulatory authorized returns on
common equity supported a utility's ability to issue additional common stock
without diluting existing shares. It further demonstrates utilities were able to
access equity markets without a detrimental impact on current shareholders.
Based on this analysis, as shown in my Exhibit No. 312, the average
indicated equity risk premium over U.S. Treasury bond yields has been 5.36% for
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gas utilities. Since the risk premium can vary depending upon market conditions
and changing investor risk perceptions, I believe using an estimated range of risk
premiums provides the best method to measure the current return on common
equity for a risk premium methodology.
I incorporated five-year and 10-year rolling average risk premiums over the
study period to gauge the variability over time of risk premiums. These rolling
average risk premiums mitigate the impact of anomalous market conditions and
skewed risk premiums over an entire business cycle. As shown on my Exhibit No.
312, the five-year rolling average gas risk premium over Treasury bonds ranged
from 4.17% to 6.68%, while the 10-year rolling average risk premium ranged from
4.30% to 6.29%.
As shown on my Exhibit No. 313, the average indicated equity risk premium
over contemporary Moody's utility bond yields was 3.98% for gas utilities. The
five-year and 10-year rolling gas average risk premiums ranged from 2.80% to
5.51 % and 3.11 % to 4.93%, respectively.
DO YOU BELIEVE THAT THE TIME PERIOD USED TO DERIVE THESE
EQUITY RISK PREMIUM ESTIMATES IS APPROPRIATE TO FORM
ACCURATE CONCLUSIONS ABOUT CONTEMPORARY MARKET
CONDITIONS?
Yes. The time period I use in this risk premium study is a generally accepted
period to develop a risk premium study using "expectational" data.
Contemporary market conditions can change dramatically during the
period that rates determined in this proceeding will be in effect. A relatively long
period of time where stock valuations reflect premiums to book value is an
indication the authorized returns on equity and the corresponding equity risk
premiums were supportive of investors' return expectations and provided utilities
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access to the equity markets under reasonable terms and conditions. Further, this
time period is long enough to smooth abnormal market movement that might distort
equity risk premiums. While market conditions and risk premiums do vary over
time, this historical time period is a reasonable period to estimate contemporary
risk premiums.
Alternatively, some studies, such as Duff & Phelps referred to later in this
testimony, have recommended that use of "actual achieved investment return
data" in a risk premium study should be based on long historical time periods. The
studies find that achieved returns over short time periods may not reflect investors'
expected returns due to unexpected and abnormal stock price performance.
Short-term, abnormal actual returns would be smoothed over time and the
achieved actual investment returns over long time periods would approximate
investors' expected returns. Therefore, it is reasonable to assume that averages
of annual achieved returns over long time periods will generally converge on the
investors' expected returns.
My risk premium study is based on expectational data, not actual
investment returns, and , thus, need not encompass a very long historical time
period.
BASED ON HISTORICAL DATA, WHAT RISK PREMIUM HAVE YOU USED TO
ESTIMATE IGC'S COST OF COMMON EQUITY IN THIS PROCEEDING?
The equity risk premium should reflect the relative market perception of risk in the
utility industry today. I have gauged investor perceptions in utility risk today in my
Exhibit No. 314, where I show the yield spread between utility bonds and Treasury
bonds over the last 36 years. As shown in this schedule, the average utility bond
yield spreads over Treasury bonds for "A" and "Baa" rated utility bonds for this
historical period are 1.52% and 1.96%, respectively. The utility bond yield spreads
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1 over Treasury bonds for "A" and "Baa" rated utilities for 2016 were 1.37% and
2 2.18%, respectively. The current average "A" rated utility bond yield spread over
3 Treasury bond yields is now lower than the 36-year average spread. The current
4 "Baa" rated utility bond yield spread over Treasury bond yields is higher than the
5 36-year average spread.
6 A current 13-week average "A" rated utility bond yield of 3. 7 4% when
7 compared to the current Treasury bond yield of 2.46% as shown in my Exhibit No.
8 315, page 1, implies a yield spread of around 130 basis points. This current utility
9 bond yield spread is lower than the 36-year average spread for "A" rated utility
1 O bonds of 1.52%. The current spread for the "Baa" rated utility bond yield of 1.87%
11 is also lower than the 36-year average spread of 1.96%. Further, when compared
12 to the projected Treasury bond yield of 3.40%, the current "Baa" utility spread is
13 around 0.93%, lower than the 36-year average of 1.96%.
14 These utility bond yield spreads are evidence that the market perception of
15 utility risk is about average relative to this historical time period and demonstrate
16 that utilities continue to have strong access to capital in the current market.
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HOW DO YOU DETERMINE WHERE A REASONABLE RISK PREMIUM IS IN
THE CURRENT MARKET?
I observed the spread of Treasury securities relative to public utility bonds and
corporate bonds in gauging whether or not the risk premium in current market
prices is relatively stable relative to the past. What this observation of market
evidence clearly provides is that the valuations in the current market place an
above average risk premium on securities that have greater risk.
This market evidence is summarized below in Table 9, which shows the
utility bond yield spreads over Treasury bond yields on average for the period 1980
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through 2016 and the spreads for the first three quarters of 2016. I also show the
corporate bond yield spreads for Aaa corporates and Baa corporates.
TABLE 9
Comparison of Yield Spreads Over Treasury Bonds
Description
Average Historical Spread
03, 2016 Spread
Source: Exhibit No. 314.
Utility Corporate
_A_ Baa Aaa Baa
1.52% 1.96% 0.84% 1.94%
1.37% 2.18% 1.10% 2.22%
The observable yield spreads shown in the table above illustrate that
securities of greater risk have above average risk premiums relative to the long­
term historical average risk premium. Specifically, A-rated utility bonds to
Treasuries, a relatively low-risk investment, have a yield spread in 2016 that has
been very comparable to that of its long-term historical yield spread. The A utility
bond yield spread is actually below the yield spread over the last 36 years. This
is an indication that low risk investments like Aaa corporate bond yield and A-rated
utility bond yield have premium values relative to minimal risk Treasury securities.
In contrast, the higher risk Baa utility and corporate bond yields currently
have an above-average yield spread of approximately 20 basis points (2.18% vs.
1.96%). The higher risk Baa utility bond yields do not have the same premium
valuations as their lower risk A-rated utility bond yields, and thus the yield spread
for greater risk investments is wider than lower risk investments.
This illustrates that securities with greater risk such as Baa yields versus
A yields are commanding above average risk premium spreads in the current
marketplace. Utility equity securities are greater risk than Baa utility bonds.
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Because greater risk securities appear to support an above-average risk premium
relative to historical averages, this would support an above-average risk premium
in measuring a fair return on equity for a utility stock or equity security.
WHAT IS YOUR RECOMMENDED RETURN FOR IGC BASED ON YOUR RISK
PREMIUM STUDY?
To be conservative, I am recommending more weight to the high-end risk premium
estimates than the low-end. I state this because of the relatively low level of
interest rates now but relative upward movements of utility yields more recently.
Hence, I propose to provide 75% weight to my high-end risk premium estimates
and 25% to the low-end. Applying these weights, the risk premium for Treasury
bond yields would be approximately 6.1 %,39 which is considerably higher than the
31 -year average risk premium of 5.36% for gas utilities and reasonably reflective
of the 3.4% projected Treasury bond yield . A Treasury bond risk premium of 6.1 %
and projected Treasury bond yield of 3.4% produce a risk premium estimate of
9.50%. Similarly, applying these weights to the utility risk premium indicates a risk
premium of 4.8%.40 This risk premium is above the 31-year historical average risk
premium of 3.98% for gas utilities. This risk premium in connection with the current
Baa observable utility bond yield of 4.33% produces an estimated return on equity
of approximately 9.10%.
Based on this methodology, both my Treasury bond risk premium and my
utility bond risk premium indicate a return of 9.30%.
39(4.17% * 25%) + (6.68% * 75%) = 6.05%., rounded to 6.1%
40 (2.80% * 25%) + (5.51% * 75%) = 4.83%, rounded to 4.8%.
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1 XII.F. Capital Asset Pricing Model ("CAPM")
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PLEASE DESCRIBE THE CAPM.
The CAPM method of analysis is based upon the theory that the market-required
rate of return for a security is equal to the risk-free rate, plus a risk premium
associated with the specific security. This relationship between risk and return can
be expressed mathematically as follows:
R; = Rt + 8; x (Rm -Rr) where:
R; = Required return for stock i
Rt = Risk-free rate
Rm = Expected return for the market portfolio
8; = Beta -Measure of the risk for stock
The stock-specific risk term in the above equation is beta. Beta represents
the investment risk that cannot be diversified away when the security is held in a
diversified portfolio. When stocks are held in a diversified portfolio, firm-specific
risks can be eliminated by balancing the portfolio with securities that react in the
opposite direction to firm-specific risk factors (e.g., business cycle, competition,
product mix, and production limitations).
The risks that cannot be eliminated when held in a diversified portfolio are
non-diversifiable risks. Non-diversifiable risks are related to the market in general
and referred to as systematic risks. Risks that can be eliminated by diversification
are non-systematic risks. In a broad sense, systematic risks are market risks and
non-systematic risks are business risks. The CAPM theory suggests the market
will not compensate investors for assuming risks that can be diversified away.
Therefore, the only risk investors will be compensated for are systematic or
non-diversifiable risks.
non-diversifiable risks.
The beta is a measure of the systematic or
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PLEASE DESCRIBE THE INPUTS TO YOUR CAPM.
The CAPM requires an estimate of the market risk-free rate, the Company's beta,
and the market risk premium.
WHAT DID YOU USE AS AN ESTIMATE OF THE MARKET RISK-FREE RATE?
As previously noted, Blue Chip Financial Forecasts' projected 30-year Treasury
bond yield is 3.40%.41 The current 30-year Treasury bond yield is 2.46%, as shown
in my Exhibit No. 315. I used Blue Chip Financial Forecasts' projected 30-year
Treasury bond yield of 3.40% for my CAPM analysis.
WHY DID YOU USE LONG-TERM TREASURY BOND YIELDS AS AN
ESTIMATE OF THE RISK-FREE RATE?
Treasury securities are backed by the full faith and credit of the United States
government so long-term Treasury bonds are considered to have negligible credit
risk. Also, long-term Treasury bonds have an investment horizon similar to that of
common stock. As a result, investor-anticipated long-run inflation expectations are
reflected in both common stock required returns and long-term bond yields.
Therefore, the nominal risk-free rate (or expected inflation rate and real risk-free
rate) included in a long-term bond yield is a reasonable estimate of the nominal
risk-free rate included in common stock returns.
Treasury bond yields, however, do include risk premiums related to
unanticipated future inflation and interest rates. A Treasury bond yield is not a
risk-free rate. Risk premiums related to unanticipated inflation and interest rates
are systematic of market risks. Consequently, for companies with betas less than
1.0, using the Treasury bond yield as a proxy for the risk-free rate in the CAPM
analysis can produce an overstated estimate of the CAPM return.
418/ue Chip Financial Forecasts, December 1, 2016 at 2.
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WHAT BETA DID YOU USE IN YOUR ANALYSIS?
As shown in my Exhibit No. 316, the proxy group average Value Line beta estimate
is 0.74.
HOW DID YOU DERIVE YOUR MARKET RISK PREMIUM ESTIMATE?
I derived two market risk premium estimates: a forward-looking estimate and one
based on a long-term historical average.
The forward-looking estimate was derived by estimating the expected
return on the market (as represented by the S&P 500) and subtracting the risk-free
rate from this estimate. I estimated the expected return on the S&P 500 by adding
an expected inflation rate to the long-term historical arithmetic average real return
on the market. The real return on the market represents the achieved return above
the rate of inflation.
Duff & Phelps' 2016 Valuation Handbook estimates the historical arithmetic
average real market return over the period 1926 to 2015 as 8. 7%. 42 A current
consensus analysts' inflation projection, as measured by the Consumer Price
Index, is 2.3%.43 Using these estimates, the expected market return is 11.20%.44
The market risk premium then is the difference between the 11.20% expected
market return and my 3.40% risk-free rate estimate, or approximately 7.80%.
My historical estimate of the market risk premium was also calculated by
using data provided by Duff & Phelps in its 2016 Valuation Handbook. Over the
period 1926 through 2015, the Duff & Phelps study estimated that the arithmetic
average of the achieved total return on the S&P 500 was 12.0%45 and the total
42Duff & Phelps, 2016 Valuation Handbook: Guide to Cost of Capital at 2-4. Calculated as
[(1 +0.12) / (1 +0.03)] -1.
43Blue Chip Financial Forecasts, December 1, 2016 at 2.
44{ [ (1 + 0.087) * (1 + 0.023) ]-1} * 100.
45Duff & Phelps, 2016 Valuation Handbook: Guide to Cost of Capital at 2-4.
Gorman, Di 61
Northwest Industrial Gas Users
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2
3 Q
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5 A
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9 Q
10 A
11
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return on long-term Treasury bonds was 6.00%.46 The indicated market risk
premium is 6.0% (12.0% -6.0% = 6.0%).
HOW DOES YOUR ESTIMATED MARKET RISK PREMIUM RANGE COMPARE
TO THAT ESTIMATED BY DUFF & PHELPS?
The Duff & Phelps analysis indicates a market risk premium falls somewhere in
the range of 5.5% to 6.9%. My market risk premium falls in the range of 6.0% to
7.8%. My average market risk premium of 6.9% is consistent with the high-end of
the Duff & Phelps range.
HOW DOES DUFF & PHELPS MEASURE A MARKET RISK PREMIUM?
Duff & Phelps makes several estimates of a forward-looking market risk premium
based on actual achieved data from the historical period of 1926 through 2015 as
well as normalized data. Using this data, Duff & Phelps estimates a market risk
premium derived from the total return on large company stocks (S&P 500), less
the income return on Treasury bonds. The total return includes capital
appreciation, dividend or coupon reinvestment returns, and annual yields received
from coupons and/or dividend payments. The income return, in contrast, only
reflects the income return received from dividend payments or coupon yields. Duff
& Phelps claims the income return is the only true risk-free rate associated with
Treasury bonds and is the best approximation of a truly risk-free rate.47 I disagree
with this assessment from Duff & Phelps because it does not reflect a true
investment option available to the marketplace and therefore does not produce a
legitimate estimate of the expected premium of investing in the stock market
versus that of Treasury bonds. Nevertheless, I will use Duff & Phelps' conclusion
to show the reasonableness of my market risk premium estimates.
46/d.
47/d. at 3-28.
Gorman, Di 62
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Q
A
Duff & Phelps' range is based on several methodologies. First, Duff &
Phelps estimates a market risk premium of 6.9% based on the difference between
the total market return on common stocks (S&P 500) less the income return on
Treasury bond investments over the 1926-2015 period.
Second, Duff & Phelps updated the Ibbotson & Chen supply-side model
which found that the 6.9% market risk premium based on the S&P 500 was
influenced by an abnormal expansion of price-to-earnings ("P/E") ratios relative to
earnings and dividend growth during the period, primarily over the last 25 years.
Duff & Phelps believes this abnormal P/E expansion is not sustainable.48
Therefore, Duff & Phelps adjusted this market risk premium estimate to normalize
the growth in the P/E ratio to be more in line with the growth in dividends and
earnings. Based on this alternative methodology, Duff & Phelps published a long­
horizon supply-side market risk premium of 6.03%.49
Finally, Duff & Phelps developed its own recommended equity, or market,
risk premium by employing an analysis that considered a wide range of economic
information, multiple risk premium estimation methodologies, and the current state
of the economy by observing measures such as the level of stock indices and
corporate spreads as indicators of perceived risk. Based on this methodology, and
utilizing a "normalized" risk-free rate of 4.0%, Duff & Phelps concluded that the
current expected, or forward-looking, market risk premium is 5.5%, implying an
expected return on the market of 9.5%.50
WHAT ARE THE RESULTS OF YOUR CAPM ANALYSIS?
As shown in my Exhibit No. 317, based on my low market risk premium of 6.0%
and my high market risk premium of 7.8%, a risk-free rate of 3.40%, and a proxy
48/d. at 3-30.
49/d. at 3-31 .
sold. at 3-40.
Gorman, Di 63
Northwest Industrial Gas Users
1 group beta of 0.74, my CAPM analysis produces a return of 7.86% to 9.19%.
2 Based on my assessment of risk premiums in the current market, as discussed
3 above, I recommend the proxy group high-end CAPM return estimate of 9.19%,
4 rounded to 9.20%.
5 XII.G. Return on Equity Summary
6 Q
7
8
9 A
BASED ON THE RESULTS OF YOUR RETURN ON COMMON EQUITY
ANALYSES DESCRIBED ABOVE, WHAT RETURN ON COMMON EQUITY DO
YOU RECOMMEND FOR IGC?
Based on my analyses, I estimate IGC's current market cost of equity to be 9.30%.
TABLE10
Return on Common Equity Summary
Description
DCF
Risk Premium
CAPM
Results
9.40%
9.30%
9.20%
10 My recommended return on common equity of 9.30% is at the midpoint of
11 my estimated range of 9.20% to 9.40%. As shown in Table 10 above, the high-
12 end of my estimated range is based on my DCF studies. The low-end is based on
13 my CAPM return. The risk premium is within my recommended range.
14 My return on equity estimates reflect observable market evidence, the
15 impact on Federal Reserve policies on current and expected long-term capital
16 market costs, an assessment of the current risk premium built into current market
17 securities, and a general assessment of the current investment risk characteristics
18 of the electric utility industry, and the market's demand for utility securities.
Gorman, Di 64
Northwest Industrial Gas Users
1 XII.H. Financial Integrity
2 Q
3
4 A
5
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8 Q
9
10 A
11
12
13
14
15
16
17
18
19
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21 Q
22
23 A
24
WILL YOUR RECOMMENDED OVERALL RATE OF RETURN SUPPORT AN
INVESTMENT GRADE BOND RATING FOR IGC?
Yes. I have reached this conclusion by comparing the key credit rating financial
ratios for IGC at my proposed return on equity and the Company's actual test-year­
end capital structure to S&P's benchmark financial ratios using S&P's new credit
metric ranges.
PLEASE DESCRIBE THE MOST RECENT S&P FINANCIAL RATIO CREDIT
METRIC METHODOLOGY.
S&P publishes a matrix of financial ratios corresponding to its assessment of the
business risk of utility companies and related bond ratings. On May 27, 2009, S&P
expanded its matrix criteria by including additional business and financial risk
categories.51
Based on S&P's most recent credit matrix, the business risk profile
categories are "Excellent," "Strong ," "Satisfactory," "Fair," "Weak," and
"Vulnerable." Most utilities have a business risk profile of "Excellent" or "Strong."
The financial risk profile categories are "Minimal," "Modest," "Intermediate,"
"Significant," "Aggressive," and "Highly Leveraged." Most of the utilities have a
financial risk profile of "Aggressive." IGC's parent, MDU Resources, has a
"Satisfactory" business risk profile and a "Significant" financial risk profile.
PLEASE DESCRIBE S&P'S USE OF THE FINANCIAL BENCHMARK RATIOS
IN ITS CREDIT RATING REVIEW.
S&P evaluates a utility's credit rating based on an assessment of its financial and
business risks. A combination offinancial and business risks equates to the overall
s1s&P updated its 2008 credit metric guidelines in 2009, and incorporated utility metric
benchmarks with the general corporate rating metrics. Standard & Poor's RatingsDirect: "Criteria
Methodology: Business Risk/Financial Risk Matrix Expanded," May 27, 2009.
Gorman, Di 65
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assessment of IGC's total credit risk exposure. On November 19, 2013, S&P
updated its methodology. In its update, S&P published a matrix of financial ratios
that defines the level of financial risk as a function of the level of business risk.
S&P publishes ranges for primary financial ratios that it uses as guidance
in its credit review for utility companies. The two core financial ratio benchmarks
it relies on in its credit rating process include: (1) Debt to Earnings Before Interest,
Taxes, Depreciation and Amortization ("EBITDA"); and (2) Funds From Operations
("FFO") to Total Debt.52
HOW DID YOU APPLY S&P'S FINANCIAL RATIOS TO TEST THE
REASONABLENESS OF YOUR RATE OF RETURN RECOMMENDATIONS?
I calculated each of S&P's financial ratios based on IGC's cost of service for its
retail jurisdictional operations. While S&P would normally look at total consolidated
IGC financial ratios in its credit review process, my investigation in this proceeding
is not the same as S&P's. I am attempting to judge the reasonableness of my
proposed cost of capital for rate-setting in IGC's retail regulated utility operations.
Hence, I am attempting to determine whether my proposed rate of return will in
turn support cash flow metrics, balance sheet strength, and earnings that will
support an investment grade bond rating and IGC's financial integrity.
PLEASE DESCRIBE THE RESULTS OF THIS CREDIT METRIC ANALYSIS AS
IT RELATES TO IGC.
The S&P financial metric calculations for IGC at a 9.30% return are developed on
my Exhibit No. 318, page 1. The credit metrics produced below, with IGC's
financial risk profile from S&P of "Significant" and business risk profile by S&P of
"Satisfactory", will be used to assess the strength of the credit metrics based on
IGC's retail operations in Idaho.
52standard & Poor's RatingsDirect: "Criteria: Corporate Methodology," November 19, 2013.
Gorman, Di 66
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1 My proposed debt ratio for IGC is 52.0%. As shown on page 3 of my Exhibit
2 No. 318, this adjusted debt ratio is above the S&P median debt ratio of
3 approximately 51% for A-rated utilities and below the S&P median of 53.6% for
4 BBB-rated utilities. Hence, I concluded this capital structure reasonably supports
5 IGC's current investment grade bond rating.
6 Based on an equity return of 9.30% and a 48.0% common equity ratio, IGC
7 will be provided an opportunity to produce a debt to Earnings Before Interest,
8 Taxes, Depreciation and Amortization ("EBITDA") ratio of 2.7x. This is within
9 S&P's "Intermediate" guideline range of 2.5x to 3.5x."53 This ratio supports an
10 investment grade credit rating.
11 IGC's retail operations FFO to total debt coverage at a 9.30% equity return
12 and a 48.0% common equity ratio is 26%, which is within S&P's "Intermediate"
13 metric guideline range of 23% to 35%. This FFO/total debt ratio will support an
14 investment grade bond rating.
15 At my recommended return on equity of 9.30% and proposed capital
16 structure, and the Company's embedded debt cost, IGC's financial credit metrics
17 continue to support credit metrics at an investment grade utility level.
18 XIII. RESPONSE TO IGC WITNESS DR. J. STEPHEN GASKE
19 XIII.A. Summary of Rebuttal
20 Q
21 A
22
WHAT IS DR. GASKE'S RETURN ON EQUITY RECOMMENDATION?
Dr. Gaske recommends a return on equity of 9.90% based on results summarized
in Table 11 below.
53/d.
Gorman, Di 67
Northwest Industrial Gas Users
TABLE11
Dr. Gaske's Results
DCF
Basic (Analyst) Growth
Blended Growth
Risk Premium
Large Company Stocks (S&P
500)
Small Company Stocks
Regression Analysis
Market DCF (S&P 500)
Forward-Looking CAPM
Median
(1)
9.40%
8.61%
10.00%
18.60%
9.90%
12.10%
9.70%
High
(2)
11.06% 7.59%
9.50% 7.66%
Source: Direct Testimony of Dr. J. Stephen Gaske at 39.
Adjusted
Median
(4)
9.04%
8.28%
9.00%
Reject
9.20%
9.00%
9.10%
1 As outlined in Table 11 above under Column (4), Dr. Gaske's DCF models
2 indicate a return no higher than 9.04%. Further, reasonable adjustments to his
3 risk premium studies would indicate a fair return on equity for IGC regulated
4 operations of no higher than 9.20%. Hence, a reasonable interpretation of Dr.
5 Gaske's models, adjusted to reflect IGC's regulated operations investment risk,
6 indicates a fair return on equity in this proceeding of 9.0% to 9.2%, which supports
7 my return on equity recommendation.
8 Q DO DR. GASKE'S RETURN ON EQUITY STUDIES SUPPORT A 9.90%
9 RETURNFORIGC?
10 A No. Dr. Gaske's studies support a return on equity in the range of 8.61 % to 9.40%
11 for IGC.
12 Q
13 A
PLEASE DESCRIBE DR. GASKE'S DCF ANALYSIS.
Dr. Gaske developed two versions of the DCF analysis.
Gorman, Di 68
Northwest Industrial Gas Users
1 His first approach is based on a traditional or basic DCF analysis using analysts'
2 projected growth rate estimates. This basic DCF analysis estimates a return on
3 equity for IGC in the range of 7.30% and 10.63%, with a median of 9.04%. Then,
4 Dr. Gaske increased his proxy group return by adjusting each DCF estimate by a
5 4.0% flotation cost adjustment. This increased the proxy group median from
6 9.04% up to 9.40%.
7 Second, Dr. Gaske develops a blended DCF analysis relying on both his
8 retention and analysts' projected growth rate estimates. His retention growth rate
9 is based on Value Line projected dividends, earnings and returns. This blended
10 approach yields a return on equity in the range of 7.36% to 9.14% with a median
11 of 8.28%. Again, Dr. Gaske adjusted his blended growth DCF return by a 4.0% to
12 account for flotation costs. This increased his blended growth DCF return from
13 8.28% to 8.61 %.
14 Q
15
16 A
17
18
19
20 Q
21
22 A
23
24
25
PLEASE DESCRIBE THE ISSUES YOU HAVE WITH DR. GASKE'S DCF
ANALYSES.
My primary issue with Dr. Gaske's DCF studies lies in his proposal to adjust all of
the DCF return estimates by a flotation cost adder of 4.0%. The effect of this
flotation cost adjustment is to increase the DCF return estimate by approximately
35 basis points.
DO YOU BELIEVE THAT DR. GASKE'S FLOTATION COST ADJUSTMENT TO
HIS DCF RETURN ESTIMATES IS REASONABLE?
No. Dr. Gaske's proposed flotation cost adjustment for IGC is not based on known
and measurable costs for IGC. Therefore, his flotation cost adjustment should be
rejected .
Gorman, Di 69
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1 Q
2
3 A
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10 A
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19 Q
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HOW DID DR. GASKE DEVELOP A FLOTATION COST ADJUSTMENT FOR
IGC?
Dr. Gaske reviews a representative sample of flotation costs incurred with 32 new
common stock issues by gas utilities since January 2004. This produces an
average flotation cost of 4.1 %. Dr. Gaske rounds this up to 4.0%, and increases
his proposed return on equity by approximately 35 basis points. This flotation cost
adjustment is intended to recover the cost a utility incurred by issuing additional
stock to the public.54
WHY IS DR. GASKE'S FLOTATION COST ADJUSTMENT FLAWED?
Dr. Gaske's flotation cost adjustment is not based on the recovery of prudent and
reasonable flotation expenses for IGC. Rather, as discussed at pages 16-17 of
his direct testimony, Dr. Gaske derives a flotation cost adjustment based on cost
information of other companies relying on publicly available information. Because
Dr. Gaske does not show that his adjustment is based on IGC's actual and
verifiable flotation expenses, there are no means of verifying whether his proposal
is reasonable or appropriate. Stated differently, Dr. Gaske's flotation cost adder is
not based on known and measurable IGC costs. Therefore, the Commission
should reject his proposed flotation expense return on equity adder.
IF DR. GASKE HAD SHOWN AN ACTUAL AND VERIFIABLE FLOTATION
EXPENSE ALLOCATED TO IGC'S REGULATED OPERATIONS, WOULD HIS
PROPOSED FLOTATION COST ADJUSTMENT BE REASONABLE?
No. A clear understanding of how the actual and verifiable flotation costs were
treated in the past for ratemaking purposes is also needed. Specifically, if the
flotation expenses had been amortized to cost of service , then these costs would
have already been recovered in past rates. If this is the case, then allowing a
54 Gaske Direct testimony at 16-17.
Gorman, Di 70
Northwest Industrial Gas Users
1 return on equity adjustment in this case would provide cost recognition in
2 prospective rates for costs that have already been recovered, this double recovery
3 of flotation costs would be unjust and unreasonable.
4 As such, Dr. Gaske would have to identify MDU Resources' actual flotation
5 costs that are properly allocated to regulated operations, show the time period
6 these costs were incurred, and show how they have been treated for ratemaking
7 purposes in the past. Without this clear demonstration, Dr. Gaske's proposed
8 flotation cost adjustment is simply not a known and measurable component of
9 IGC's cost of service in this case.
10 Q
11
12 A
CAN DR. GASKE'S DCF ANALYSES BE ADJUSTED TO PRODUCE MORE
REASONABLE RESULTS?
Yes. Removing the flotation cost adjustment from Dr. Gaske's DCF studies
13 produces a DCF return in the range of 8.3% up to 9.0%. These are the medians
14 of his proxy group studies which eliminate low-end and high-end outliers. Hence,
15 these estimates reasonably reflect the investment risk and a fair return for his proxy
16 group based on his own DCF studies. Conservatively, Dr. Gaske's DCF studies
17 demonstrate that a fair return on equity for IGC in this case is not higher than
18 9.04%, or approximately 9.0%.
19 Q
20
21 A
22
23
24
25 Q
26
DO YOU HAVE ANY OTHER ISSUES WITH DR. GASKE'S DCF RETURN
RESULTS?
Yes. Dr. Gaske's proposal to set the return on equity for IGC above the median
DCF results will place an unreasonable burden on the ratepayers and should be
rejected. As discussed below, IGC's relative risk is comparable to the risk of the
utility companies included in the proxy group.
WHY DO YOU BELIEVE THAT IGC FACES RISKS THAT ARE COMPARABLE
TO THE RISKS FACED BY DR. GASKE'S PROXY GROUP COMPANIES?
Gorman, Di 71
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13 Q
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27
28
This is evident by Dr. Gaske's own testimony. He describes his stringent
methodology to identify companies that are risk comparable to IGC's operations
and on his Exhibit No. 05, Schedule 3, he shows that the average credit rating for
his proxy group of A is slightly higher than the MDU Resources' credit rating of
BBB+ from S&P. The relative risks discussed on pages 30-38 of Dr. Gaske
testimony are already incorporated in the credit ratings of the proxy group
companies. S&P and other credit rating agencies go through great detail in
assessing a utility's business risk and financial risk in order to evaluate their
assessment of its total investment risk. Therefore, this total risk investment
assessment of MDU, in comparison to a proxy group, is fully absorbed into the
market's perception of MDU's risk and the proxy group fully captures the
investment risk of MDU.
HOW DOES S&P ASSIGN CORPORATE CREDIT RATINGS FOR REGULATED
UTILITIES?
In assigning corporate credit ratings the credit rating agency considers both
business and financial risks. Business risks among others include company's size
and competitive position, generation portfolio, as well as a consideration of the
regulatory environment, current state of the industry and the economy as whole.
Specifically, S&P states:
To determine the assessment for a corporate issuer's business risk
profile, the criteria combine our assessments of industry risk,
country risk, and competitive position. Cash flow/leverage analysis
determines a company's financial risk profile assessment. The
analysis then combines the corporate issuer's business risk profile
assessment and its financial risk profile assessment to determine
its anchor. In general, the analysis weighs the business risk profile
more heavily for investment-grade anchors, while the financial risk
profile carries more weight for speculative-grade anchors.55
55Standard & Poor's RatingsDirect: "Criteria/Corporates/General: Corporate
Methodology," November 19, 2013.
Gorman, Di 72
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A
PLEASE DESCRIBE DR. GASKE'S UTILITY RISK PREMIUM ANALYSES.
Dr. Gaske develops three risk premium studies based on the average Moody's
corporate bond yield for the 6-month period from December 2015 to May 2016 of
4.34%.56 For his first risk premium study Dr. Gaske derived an equity risk premium
of 5. 7%, which is the difference between the annual total return on a large company
stock of 12.0% and the return on long-term corporate bonds of 6.3% since 1926
as published by Morningstar SBBI Presentation 1926-2015 Slide 6.57 Then, Dr.
Gaske added the Moody's corporate bond yield of 4.3% to his risk premium of
5.7% to produce a return on equity for MDU of 10.00%. (Gaske Direct testimony
at 26).
In his second risk premium analysis Dr. Gaske estimates a risk premium
over the return for a small company stock again using the data from Ibbotson
Associates. He estimates MDU's market capitalization based on the Company's
projected rate base and equity ratio and he determines that MDU falls in the
lbbotson's 101h decile, which has a return of 20.6%. Then, he estimates a risk
premium of 14.2% over the return of long-term corporate bonds of 6.4%. Adding
his small company risk premium of 14.2% to Moody's corporate bond yield of 4.3%
produces a return on equity of 18.6%.
Finally, Dr. Gaske developed an additional risk premium based on the
concept that equity risk premia are inversely related to interest rates. He
developed a regression analysis based on the authorized gas returns and 30-year
Treasury yields during the period 1992 to the second quarter of 2016. Applying
his regression equation to the current (2.65%), near-term projected (3.08%) and
56 Gaske Direct Testimony at 26.
s1 Id.
Gorman, Di 73
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1
2
3 Q
4
5 A
long-term projected (4.30%) yields, Dr. Gaske estimates an average return on
equity based on this model of 9.91 % for IGC.
ARE DR. GASKE'S LARGE AND SMALL COMPANY RISK PREMIUMS A FAIR
RETURN ON EQUITY ESTIMATE FOR MDU?
No. Dr. Gaske's large and small risk premium estimates reasonably reflect returns
6 on the overall market or some unregulated market index. These returns on equity
7 were not calibrated to reflect the low risk of IGC's regulated utility operations.
8 Q
9
10 A
11
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25
DO YOU BELIEVE THAT DR. GASKE'S PROPOSAL FOR A SMALL COMPANY
RETURN ON EQUITY ADDER FOR IGC IS REASONABLY DEVELOPED?
No. This is unreasonable for several reasons. First, Dr. Gaske has not properly
gauged an investment risk adjustment for IGC relative to his proxy group.
Therefore, to the extent IGC could justify a small company risk adder, it should be
relative to the proxy group market return and not to the return on the total market.
Second, the development of a small company adder should not be the only
consideration in developing a fair return for IGC's regulated business operations.
The risk assessment for IGC's regulated operations should reflect small company
risk adders, as well as regulatory risk reductions. Dr. Gaske's small company risk
return is not a fair return for IGC because he ignores the risk reduction produced
by regulatory protections and cost-based prices.
Finally, Dr. Gaske's risk premium analysis is the development of his small
company risk premium of 14.2%. The total return of 20.6% for the 101h decile
reflects risks that are not characteristic of IGC. This total return used by Dr. Gaske
reflects companies that have beta estimates of approximately 1.40.58 These beta
estimates are substantially higher than the average beta of 0.74 for the proxy
group. Therefore, his small company risk premium produces a return estimate that
5s2015 SBBI Valuation Yearbook at 109.
Gorman, Di 74
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3
4 Q
5
6 A
7
8
9
10 Q
11
12 A
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23
is inflated and does not reflect a risk appropriate return for IGC. Hence, the return
produced by Dr. Gaske small company risk premium is not reasonable and should
be rejected.
DO YOU HAVE ANY COMMENTS CONCERNING DR. GASKE'S LARGE
COMPANY RISK PREMIUM?
His large company risk premium suffers from the same deficiencies described
above in regards to his small company risk premium. However, Dr. Gaske's large
company risk premium produces a return on equity that is more in line with market
expectation.
IS DR. GASKE REGRESSION RISK PREMIUM METHODOLOGY
REASONABLE?
No. Dr. Gaske's contention that there is a simplistic inverse relationship between
equity risk premiums and interest rates is not supported by academic research .
While academic studies have shown that, in the past, there has been an inverse
relationship among these variables, researchers have found that the relationship
changes over time and is influenced by changes in perception of the risk of bond
investments relative to equity investments, and not simply changes to interest
rates.59
In the 1980s, equity risk premiums were inversely related to interest rates
but that was likely attributable to the interest rate volatility that existed at that time.
As such, when interest rates were more volatile, the relative perception of bond
investment risk increased relative to the investment risk of equities. This changing
investment risk perception caused changes in equity risk premiums.
59"The Market Risk Premium : Expectational Estimates Using Analysts' Forecasts," Robert
S. Harris and Felicia C. Marston, Journal of Applied Finance , Volume 11 , No. 1, 2001 and "The
Risk Premium Approach to Measuring a Utility's Cost of Equity," Eugene F. Brigham, Dilip K.
Shome, and Steve R. Vinson, Financial Management, Spring 1985.
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In today's marketplace, interest rate volatility is not as extreme as it was
during the 1980s.60 Nevertheless, changes in the perceived risk of bond
investments relative to equity investments still drive changes in equity premiums
and cannot be measured simply by observing nominal interest rates. Changes in
nominal interest rates are heavily influenced by changes to inflation outlooks,
which also change equity return expectations. As such, the relevant factor needed
to explain changes in equity risk premiums is the relative changes to the risk of
equity versus debt securities investments, and not simply changes in interest rates.
Importantly, Dr. Gaske's analysis simply ignores investment risk
differentials. He bases his adjustment to the equity risk premium exclusively on
changes in nominal interest rates. This is a flawed methodology that does not
produce accurate or reliable risk premium estimates.
13 Q DO YOU HAVE ANY OTHER ISSUES WITH DR. GASKE'S REGRESSION RISK
PREMIUM? 14
15 A Yes. Dr. Gaske's Treasury yields used to estimate the return for IGC of 9.91 % are
based on the current (2.65%), near-term (3.08%) and long-term (4.30%) projected
30-year Treasury yields, which are almost six months old. Based on the most
recent Blue Chip publication the current and near-term projected 30-year Treasury
yields are 2.28% and 2.82%, respectively.61 Further, Dr. Gaske's long-term
projected Treasury bond yield of 4.30% is simply too high and is unreasonable.
His projected 4.30% yield is approximately 200 basis points higher than the current
Treasury bond yield of 2.28% and approximately 120 basis points higher than the
projected Treasury yield of 3.1 %62 that will cover the rate-effective period as
16
17
18
19
20
21
22
23
60"The Risk Premium Approach to Measuring a Utility's Cost of Equity," Eugene F. Brigham ,
Dilip K. Shame, and Steve R. Vinson, Financial Management, Spring 1985, at 44.
618lue Chip Financial Forecasts, December 1, 2016 at 2.
621d.
Gorman, Di 76
Northwest Industrial Gas Users
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4 Q
5
6 A
projected by the consensus economists. Dr. Gaske's long-term projected Treasury
yield of 4.30% is well beyond the rate-effective period , and as such, is not a
reasonable interest rate to use in a risk premium study.
CAN DR. GASKE'S REGRESSION RISK PREMIUM ANALYSIS BE REVISED
TO REFLECT CURRENT PROJECTIONS OF TREASURY YIELDS?
Yes. Disregarding Dr. Gaske's simplistic and incomplete belief that risk premiums
7 can be explained by only changes to nominal interest rates, his data can be used
8 to produce a reasonable return estimate. By adding my weighted average equity
9 risk premium over Treasury bonds of 6.1 % to his updated current (2.28%), near-
10 term (2.82%) and long-term (3.1%) projected Treasury yields will produce a return
11 on equity estimate no higher than 9.2% for IGC.
12 Q
13 A
14
15
16
17
18 Q
19
20 A
21
22
23
24
PLEASE DESCRIBE DR. GASKE'S MARKET DCF ANALYSIS.
Dr. Gaske developed a market DCF analysis as a benchmark to test the
reasonableness of his proxy group DCF estimates. He calculated the required
return for the companies included in the S&P 500, based on an expected dividend
yield of 2. 7% and an expected growth rate of 9.4%, which produced a market DCF
return of 12.1 %. 63
DO YOU HAVE ANY CONCERNS IN REGARDS TO DR. GASKE'S MARKET
DCF ANALYSIS.
Yes. I have two major concerns with his analysis. First, his market DCF return is
based on a growth rate of 9.4%, which is significantly above the long-term
sustainable growth rate of 4.1 % that I discussed earlier. It is unreasonable to
assume that this growth rate that is almost twice the growth of the U.S. economy
can be sustained indefinitely.
63 Exhibit No. 05, Schedule 6, Page 1 of 10.
Gorman, Di 77
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Second, the S&P 500 includes companies with risk characteristics
significantly different than the risks encountered by IGC and its parent company.
The companies in the utility industry operate as natural monopolies and are
shielded from the economic turbulence faced by corporations operating in other
industries. As noted by the major credit rating agencies, the utility industry has
relatively low risk in comparison with the market. Indeed, the regulatory process
itself provides an effective mechanism to mitigate some of the market risks
influencing the U.S. economy. Therefore, using Dr. Gaske's market DCF analysis
as a benchmark will produce an unreliable and inflated return on equity for a low­
risk utility such as IGC. Therefore, the Commission should disregard the results
of Dr. Gaske's market DCF analysis.
CAN DR. GASKE'S RISK PREMIUM STUDIES BE USED TO ESTIMATE A FAIR
RETURN FOR IGC REGULATED OPERATIONS?
Dr. Gaske's risk premium models largely ignore the investment risk and a fair
return based on that risk for IGC's regulated operations. Hence, these models are
primarily just not useful in estimating a fair risk-adjusted return for regulated utility
systems.
However, he has estimated two returns for the S&P 500: one based on a
risk premium estimate of 10.0% (Dr. Gaske's large company risk premium) and
one based on a DCF return on the market of 12.1 %. The midpoint of these two
estimates produces a market return estimate of 11 .05%. Using a risk-free rate of
3.1 %, and a comparable risk proxy group systematic risk beta factor of 0. 7 4, would
produce a risk premium estimated fair return for the proxy group of 9.00%.64
As discussed above his small company stock return of 18.6% is based on
non-regulated small companies. There has been no demonstration that this proxy
64(11 .05% -3.1 %) x 0.74 + 3.1 % = 8.98%, rounded to 9.00%.
Gorman, Di 78
Northwest Industrial Gas Users
1
2
3
4
5 Q
6 A
group reasonably reflects the investment risk of MDU Resources, much less its
lower-risk regulated subsidiaries. Hence, this small company market return
estimate should simply be rejected. Therefore, I did not include this market return
in the revision of his market DCF.
PLEASE DESCRIBE DR. GASKE'S CAPM STUDY.
Dr. Gaske develops a CAPM study based on a DCF-market return of 12.1 % as
7 described above, a risk-free rate of 2.63% based on the 30-Yr. Treasury yield, and
8 a proxy group beta of 0. 7 4. These inputs produced a market risk premium of 9.5%
9 and CAPM return on equity of 9. 7%, as shown in the table on page 29 of his direct
10 testimony.
11 Q
12 A
13
14
15
16
17 Q
18
19 A
20
21
22 Q
23 A
WHAT ISSUES DO YOU HAVE WITH DR. GASKE'S CAPM ANALYSIS?
In his CAPM study Dr. Gaske again relies on his DCF-derived market return of
12.1 %, which as I described above consists of a growth rate estimate of 9.4%.
This growth estimate is significantly higher than the consensus economist
projections for a long-term sustainable growth rate of 4.1 %. Therefore Dr. Gaske's
market risk premium of 9.5% is overstated and should be rejected.
CAN DR. GASKE'S CAPM STUDY BE REVISED TO PRODUCE A FAIR
RETURN FOR IGC REGULATED OPERATIONS?
Yes. Using my highest market risk premium of 8.1 %, an updated risk-free rate of
3.1% and a beta estimate of 0.74, will result in a CAPM return estimate of9.10%65,
which will fairly compensate investors and ratepayers.
DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
Yes, it does.
65 8.1% X 0.74 + 3.1% = 9.1%
Gorman, Di 79
Northwest Industrial Gas Users
1 Q
2 A
3
4 Q
5 A
6
7
8 Q
9
10 A
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Qualifications of Michael P. Gorman
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Michael P. Gorman. My business address is 16690 Swingley Ridge Road,
Suite 140, Chesterfield, MO 63017.
PLEASE STATE YOUR OCCUPATION.
I am a consultant in the field of public utility regulation and a Managing Principal
with the firm of Brubaker & Associates, Inc. ("BAI"), energy, economic and
regulatory consultants.
PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND WORK
EXPERIENCE.
In 1983 I received a Bachelors of Science Degree in Electrical Engineering from
Southern Illinois University, and in 1986, I received a Masters Degree in Business
Administration with a concentration in Finance from the University of Illinois at
Springfield. I have also completed several graduate level economics courses.
In August of 1983, I accepted an analyst position with the Illinois Commerce
Commission ("ICC"). In this position, I performed a variety of analyses for both
formal and informal investigations before the ICC, including: marginal cost of
energy, central dispatch, avoided cost of energy, annual system production costs,
and working capital. In October of 1986, I was promoted to the position of Senior
Analyst. In this position, I assumed the additional responsibilities of technical
leader on projects, and my areas of responsibility were expanded to include utility
financial modeling and financial analyses.
In 1987, I was promoted to Director of the Financial Analysis Department.
In this position, I was responsible for all financial analyses conducted by the Staff.
Among other things, I conducted analyses and sponsored testimony before the
Appendix A
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26
ICC on rate of return, financial integrity, financial modeling and related issues. I
also supervised the development of all Staff analyses and testimony on these
same issues. In addition, I supervised the Staffs review and recommendations to
the Commission concerning utility plans to issue debt and equity securities.
In August of 1989, I accepted a position with Merrill-Lynch as a financial
consultant. After receiving all required securities licenses, I worked with individual
investors and small businesses in evaluating and selecting investments suitable to
their requirements.
In September of 1990, I accepted a position with Drazen-Brubaker &
Associates, Inc. ("DBA"). In April 1995, the firm of Brubaker & Associates, Inc.
was formed . It includes most of the former DBA principals and Staff. Since 1990,
I have performed various analyses and sponsored testimony on cost of capital,
cost/benefits of utility mergers and acquisitions, utility reorganizations, level of
operating expenses and rate base, cost of service studies, and analyses relating
to industrial jobs and economic development. I also participated in a study used
to revise the financial policy for the municipal utility in Kansas City, Kansas.
At BAI, I also have extensive experience working with large energy users
to distribute and critically evaluate responses to requests for proposals ("RFPs")
for electric, steam, and gas energy supply from competitive energy suppliers.
These analyses include the evaluation of gas supply and delivery charges,
cogeneration and/or combined cycle unit feasibility studies, and the evaluation of
third-party asset/supply management agreements. I have participated in rate
cases on rate design and class cost of service for electric, natural gas, water and
wastewater utilities. I have also analyzed commodity pricing indices and forward
pricing methods for third party supply agreements, and have also conducted
regional electric market price forecasts .
Appendix A
Gorman, Di 81
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4 A
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17 Q
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19 A
20
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23
In addition to our main office in St. Louis, the firm also has branch offices
in Phoenix, Arizona and Corpus Christi, Texas.
HAVE YOU EVER TESTIFIED BEFORE A REGULATORY BODY?
Yes. I have sponsored testimony on cost of capital, revenue requirements, cost of
service and other issues before the Federal Energy Regulatory Commission and
numerous state regulatory commissions including: Arkansas, Arizona , California,
Colorado, Delaware, Florida, Georgia , Idaho, Illinois, Indiana, Iowa, Kansas,
Louisiana, Michigan, Mississippi, Missouri, Montana, New Jersey, New Mexico,
New York, North Carolina, Ohio, Oklahoma, Oregon, South Carolina, Tennessee,
Texas, Utah, Vermont, Virginia , Washington, West Virginia, Wisconsin , Wyoming,
and before the provincial regulatory boards in Alberta and Nova Scotia, Canada. I
have also sponsored testimony before the Board of Public Utilities in Kansas City,
Kansas; presented rate setting position reports to the regulatory board of the
municipal utility in Austin, Texas, and Salt River Project, Arizona, on behalf of
industrial customers; and negotiated rate disputes for industrial customers of the
Municipal Electric Authority of Georgia in the LaGrange, Georgia district.
PLEASE DESCRIBE ANY PROFESSIONAL REGISTRATIONS OR
ORGANIZATIONS TO WHICH YOU BELONG.
I earned the designation of Chartered Financial Analyst ("CFA") from the CFA
Institute. The CFA charter was awarded after successfully completing three
examinations which covered the subject areas of financial accounting, economics,
fixed income and equity valuation and professional and ethical conduct. I am a
member of the CFA lnstitute's Financial Analyst Society.
Appendix A
Gorman, Di 82
Northwest Industrial Gas Users
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
100 l SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 301
Line
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lntermountain Gas Company
Rate of Return
(December 31, 2016)
Weighted
Descri~tion Weight1 Cost Cost
(1) (2) (3)
Long-Term Debt 52.00% 4.94% 2.57%
Common Equity 48.00% 9.30% 4.46%
Total 100.00% 7.03%
Source:
1SNL Financial, downloaded on December 14, 2016.
Exhibit No. 301
Case No. INT-G-16-02
M.Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 302
lntermountain Gas Company
Valuation Metrics
Price to Earnings (PIE} Ratio 1
11-Year
Line Company Average 2016 2 2015 2014 2013 2012 2011 2010
(1) (2) (3) (4) (5) (6) (7) (8)
1 Atmos Energy 15.44 21.40 17.50 16.09 15.87 15.93 14.36 13.21
2 Chesapeake Utilities 16.13 20.90 19.15 17.70 15.62 14.81 14.16 12.21
3 New Jersey Resources 16.18 20.20 16.61 11.73 15.98 16.83 16.76 14.98
4 NiSource Inc. 19.97 23.80 37.34 22.74 18.89 17.87 19.36 15.33
5 Northwest Nat. Gas 19.49 27.70 23.69 20.69 19.38 21 .08 19.02 16.97
6 South Jersey Inds. 17.28 23.10 17.95 18.03 18.90 16.94 18.48 16.81
7 Southwest Gas 16.89 22.50 19.35 17.86 15.76 15.00 15.69 13.97
8 Spire Inc. 15.82 19.80 16.49 19.80 21 .25 14.46 13.05 13.74
9 UGI Corp. 14.98 20.80 17.71 15.81 15.44 16.38 15.03 10.86
10 WGL Holdings Inc. 15.91 20.00 16.99 15.15 18.25 15.27 16.97 15.11
11 Average 16.81 22.02 20.28 17.56 17.53 16.46 16.29 14.32
12 Median 16.44 21.15 17.83 17.78 17.11 16.15 16.22 14.48
Sources:
' The Value Line Investment Survey Investment Analyzer Software, downloaded on November 30, 2016.
2 The Value Line Investment Survey, September 2, 2016.
2009
(9)
12.54
14.20
14.93
14.34
15.17
14.96
12.20
13.39
10.30
12.58
13.46
13.80
2008 2007 2006
(10) (11) (12)
13.59 15.87 13.52
14.15 16.72 17.85
12.27 21.61 16.13
12.07 18.82 19.16
18.08 16.74 15.85
15.90 17.18 11.86
20.27 17.26 15.94
14.31 14.19 13.60
13.30 15.14 13.97
13.66 15.60 15.46
14.76 16.91 15.33
13.91 16.73 15.66
Exhibit No. 302
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 3
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lntermountain Gas Company
Valuation Metrics
Market Price to Cash Flow (MP/CF) Ratio 1
11-Year
Company Average 201621' 2015 2014 2013 2012 2011
(1) (2) (3) (4) (5) (6) (7)
Atmos Energy 7.60 11.74 9.30 8.79 7.72 7.02 6.87
Chesapeake Utilities 8.66 11.23 10.16 9.25 8.12 7.46 7.35
New Jersey Resources 11.70 15.15 11.71 8.95 11 .29 12.29 12.71
NiSource Inc. 7.34 8.83 10.38 10.56 8.71 7.81 6.81
Northwest Nat. Gas 9.09 12.24 9.46 8.84 8.61 9.48 908
South Jersey Inds. 10.71 11.76 10.70 10.57 11.57 10.95 11.98
Southwest Gas 5.58 7.08 6.56 6.35 5.94 5.55 5.60
Spire Inc. 9.48 10.52 8.47 12.03 13.76 8.80 8.08
UGI Corp. 7.22 8.88 8.47 7.49 6.55 6.30 7.51
WGL Holdings Inc. 8.91 12.19 9.59 8.46 9.83 903 9.52
Average 8.63 10.96 9.48 9.13 9.21 8.47 8.55
Median 8.51 11.48 9.52 8.90 8.66 8.31 7.80
Sources:
' The Value Line Investment Survey Investment Analyzer Software, downloaded on November 30, 2016.
'The Value Line Investment Survey, September 2, 2016.
Note:
• Based on the average of the high and low price for 2016 and the projected 2016 cash flow per share,
published in The Value Line Investment Survey, August 19, September 16, and October 28, 2016.
2010
(8)
6.15
6.36
11.32
5.09
8.94
10.78
4.91
8.12
602
8.34
7.60
7.24
2009
(9)
5.76
9.48
11.34
4.06
8.26
9.57
3.84
8.58
5.74
7.17
7.38
7.71
2008 2007 2006
(10) (11) (12)
6.48 7.44 6.36
7.88 8.58 9.40
9.15 13.76 11 01
4.87 6.69 6.87
8.75 8.54 7.83
10.38 11.23 8.32
4.89 5.42 5.28
8.95 8.46 8.46
7.11 7.92 7.48
7.68 8.39 7.81
7.62 8.64 7.88
7.78 8.42 7.82
Exhibit No. 302
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 2 of 3
Line
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lntermountain Gas Company
Valuation Metrics
Market Price to Book Value (MPIBV) Ratio'
11-Year
Company Average ~ 2015 2014 2013 2012 2011
(1) (2) (3) (4) (5) (6) (7)
Atmos Energy 1.42 2.22 1.72 1.55 1.39 1.28 1.30
Chesapeake Utilities 1.81 2.36 2.19 2.12 1.83 1.66 1.61
New Jersey Resources 2.18 2.58 2.28 2.13 2.05 2.33 2.31
NiSource Inc. 1.35 1.96 1.95 1.94 1.58 1.37 1.15
Northwest Nat. Gas 1.76 2.01 1.63 1.59 1.56 1.72 1.70
South Jersey Inds. 2.10 1.60 1.77 2.07 2.27 2.21 2.59
Southwest Gas 1.47 1.88 1.68 1.68 1.61 1.51 1.43
Spire Inc. 1.54 1.76 1.44 1.33 1.34 1.51 1.46
UGI Corp. 1.91 2.29 2.29 1.97 1.69 1.45 1.75
WGL Holdings Inc. 1.74 2.48 2.15 1.69 1.71 1.66 1.63
Average 1.73 2.11 1.91 1.81 1.70 1.67 1.69
Median 1.71 2.11 1.86 1.81 1.65 1.58 1.62
Sources:
' The Value Line Investment Survey Investment Analyzer Software, downloaded on November 30, 2016.
'The Value Line Investment Survey, September 2, 2016.
Note:
• Based on the average of the high and low price for 2016 and the projected 2016 cash flow per share.
2010
(8)
118
1.40
209
0.92
1.78
2.38
1.24
1.39
1.55
1.50
1.54
1.45
2009
(9)
1.05
1.37
2.16
0.69
1.73
1.95
0.97
1.68
1.66
1.45
1.47
1.56
2008 2007 2006
(10) (11) (12)
1.20 1.40 1.34
1.64 1.84 1.85
1.92 2.17 2.01
0.94 1.16 1.19
1.96 2.05 1.69
2.08 2.21 1.93
1.20 1.46 1.46
1.71 1.66 1.71
2.01 2.16 2.21
1.59 1.64 1.59
1.62 1.78 1.70
1.67 1.75 170
Exhibit No. 302
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 3 of 3
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMP ANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE ST A TE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 303
Line
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lntermountain Gas Company
Proxy Group
Credit Ratings 1 Common Egui!}'. Ratios
Company S&P Moody's SNL1 Value Line2
(1) (2) (3) (4)
Atmos Energy Corporation A A2 52.5% 56.5%
New Jersey Resources Corporation 3 A Aa2 54.6% 56.8%
Northwest Natural Gas Company A+ A3 47.4% 57.5%
South Jersey Industries, Inc. BBB+ N/A 41 .6% 50.8%
Southwest Gas Corporation BBB+ A3 49.9% 50.7%
Spire Inc. A-Baa2 41 .8% 47.0%
WGL Holdings, Inc. A+ A3 48.3% 56.1%
Average A A2 48.0% 53.6%
lntermountain Gas Company 48.0%4
Sources:
1 SNL Financial, Downloaded on November 11, 2016.
2 The Value Line Investment Survey , September 2, 2016.
3 New Jersey Resources Corporation is not rated; using ratings for
New Jersey Natural Gas, a wholly owned operating subsidiary of New Jersey Resources Corporation.
4 Exhibit No. 301.
Exhibit No. 303
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMP ANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE ST ATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 304
Line
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6
7
8
lntermountain Gas Company
Consensus Analysts' Growth Rates
Zacks
Estimated Number of
Company Growth %' Estimates
(1) (2)
Atmos Energy Corporation 7.20% N/A
New Jersey Resources Corporation 6.50% N/A
Northwest Natural Gas Company 4.00% N/A
South Jersey Industries, Inc. 10.00% N/A
Southwest Gas Corporation 4.50% N/A
Spire Inc. 4.80% N/A
WGL Holdings, Inc. 7.30% N/A
Average 6.33% N/A
Sources:
1 Zacks Elite, http://www.zackselite.com/, downloaded on November 11, 2016.
2 SNL Interactive, http://www.snl.com/, downloaded on November 11, 2016.
3 Reuters, http://www.reuters.com/, downloaded on November 11, 2016.
SNL
Estimated Number of
Growth %2 Estimates
(3) (4)
6.90% 2
5.30% 3
4.00%
10.00%
4.00%
4.70% 2
7.80% 3
6.10% 2
Reuters Average of
Estimated
Growth %3
(5)
7.30%
6.00%
4.00%
N/A
4.00%
4.70%
8.00%
5.67%
Number of Growth
Estimates Rates
(6) (7)
2 7.13%
5.93%
4.00%
N/A 10.00%
1 4.17%
2 4.73%
2 7.70%
2 6.24%
Exhibit No. 304
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No . 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 305
Line
1
2
3
4
5
6
7
8
9
lntermountain Gas Company
Constant Growth DCF Model
(Consensus Analysts' Growth Rates)
Company
Atmos Energy Corporation
New Jersey Resources Corporation
Northwest Natural Gas Company
South Jersey Industries. Inc.
Southwest Gas Corporation
Spire Inc.
WGL Holdings, Inc.
Average
Median
Sources:
'SNL Financial, Downloaded on November 17, 2016.
2 Exhibit No. 304.
13-WeekAVG
Stock Price 1
(1)
$73.29
$33.32
$59.36
$29.40
$70.19
$63.36
$62.25
$55.88
' The Value Line Investment Survey. September 2, 2016.
Analysts' Annualized
Growth' Dividend3
(2) (3)
7.13% $1.68
5.93% $0.96
4.00% $1.87
10.00% $1 .06
4.17% $1.80
4.73% $1.96
7.70% $1 .95
6.24% $1 .61
Adjusted Constant
Yield Growth DCF
(4) (5)
2.46% 9.59%
3.05% 8.99%
3.28% 7.28%
3.95% 13.95%
2.67% 6.84%
3.24% 7.97%
3.38% 11.08%
3.15% 9.38%
8.99%
Exhibit No. 305
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 306
1
2
3
4
5
6
7
8
lntermountain Gas Company
Payout Ratios
Dividends Per Share
2015 Projected
(1) (2)
Atmos Energy Corporation $1 .56 $2.15
New Jersey Resources Corporation $0.93 $1.02
Northwest Natural Gas Company $1 .86 $2.05
South Jersey Industries, Inc. $1.02 $1.40
Southwest Gas Corporation $1.62 $2.40
Spire Inc. $1.84 $2.20
WGL Holdings, Inc. $1.83 $2.05
Average $1.52 $1.90
Source:
The Value Line Investment Survey, September 2, 2016.
Earnings Per Share Payout Ratio
2015 Projected 2015 Projected
(3) (4) (5) (6)
$3.09
$178
$1 .96
$1.44
$2.92
$3.16
$3.16
$2.50
$4.20 50.49% 51 .19%
$1.85 52.25% 55.14%
$3.15 94.90% 65.08%
$1.80 70.83% 77.78%
$4.50 55.48% 53.33%
$4.20 58.23% 52.38%
$3.30 57.91% 62.12%
$3.29 62.87% 59.57%
Exhibit No. 306
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 307
Yn!
lntermountain Gas Company
Sustainable Growth Rate
J to 5 Year Pro· ctions
Dividends Earnings Book Value Book Value Adjustment
Company Per Share Per Share Per Sharv Growth ROE Facto,
(1) (2) (3) (4) (5) (6)
Atmos Energy Corporation $2.15 $4.20 $36.65 3.09% 11.46% 1.02
New Jersey Resources Corporation $1.02 $1.65 $17.15 5.71% 10.79% 1.03
Northwest Natural Gas Company $2.05 $3.15 $32.65 2.90% 9.59% 1.01
South Jersey Industries, Inc. $1.40 $1.80 $21.50 8.02% 8.37% 1.04
Southwest Gas Corix>ration $2.40 $4.50 $36.45 2.73% 11.70% 1.01
Spire Inc. $2.20 $4.20 $42.70 3.30% 9.84% 1.02
WGL Holdings, Inc. $2.05 $3.30 $34.60 6.74% 9.54% 1.03
Average $1.90 $3.29 $31.99 4.64% 10.18% 1.02
Sources and Notes:
Cols. (1), (2) and (3): The Value Une fnveslment Survey, September 2, 2016.
Col. (4): [ Col. (3) I Page 2 Col. (2)] '(115)-1.
Col. (5): Col. (2) I Col. (3).
Col. (6): [ 2 • (1 + Col. (4)) JI (2 + Col. (4)).
Col. (7): Col. (8) • Col. (5).
Col. (8): Col. (1) I Col. (2).
Col. (9): 1 -Col. (8).
Col. (10): Col. (9) • Col. (7).
Col. (11): Col. (10) + Page 2 Col. (9).
Adjusted Payout
ROE Ratio
(7) (8)
11.63% 51.19%
11.00% 55.14%
9.73% 65.08%
8.89% 77.78%
11.86% 53.33%
10.00% 52.38%
9.65% 62.12%
10.41% 59.57%
Sustainable
Retention Internal Growth
Rate ~ Rate
(9) (10) (11)
48.81% 5.68% 10.21%
44.86% 4.97% 5.27%
34.92% 3.40% 3.84%
22.22% 1.93% 5.89%
46.67% 5.54% 7.58%
47.62% 4.76% 6.29%
37.68% 3.73% 6.74%
40.43% 4.29% 6.55%
Exhibit No. 307
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 2
Line
lntermountain Gas Company
Sustainable Growth Rate
1J.Week 2015
Average Book Value
Company Stock Price' Per Share2
(1) (2)
Atmos Energy Cor!X)ration $73.29 $31.48
New Jersey Resources Corporation $33.32 S12.99
Northwest Natural Gas Company $59.36 $28.47
South Jersey Industries, Inc. $29.40 $14.62
Southwest Gas Corporation $70.19 $33.61
Spire Inc $63.36 $36.30
WGL Holdings, Inc. S62.25 S24.97
Average $55.88 $26.06
Sources and Notes:
1 SNL Financial, Downloaded on November 17, 2016.
2 The Value Line Investment Survey , September 2, 2016.
3 Expected Growth in the Number of Shares, Column (3) • Column (6).
' Expected Profit of Stock Investment, ( 1 - 1 / Column (3) ].
Market Common Shares
to Book Outstandi!:!9 {in Millionst
Ratio 2015 3-5 Years
(3) (4) (5)
2.33 101.48 120.00
2.57 8.5.19 86.00
2.08 27.43 28.00
2.01 70.97 86.00
2.09 47.38 52.00
1.75 43.36 48.00
2.49 49.78 55.00
2.19 60.80 67.86
Growth S Factor'
(&) (7)
3.41% 7.94%
0.19% 0.49%
0.41% 0.86%
3.92% 7.87%
1.86% 3.92%
2.05% 3.59%
2.01% 5.02%
1.98% 4.24%
V Factor'' s·v
(8) (9)
57.05% 4.53%
61.02% 0.30%
52.03% 0.45%
50.26% 3.96%
52.12% 2.04%
42.71% 1.53%
59.89% 3.01%
53.58% 2.26%
Exhibit No. 307
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 2 of 2
Chad M. Stokes (OSB No . 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 308
1
2
3
4
5
6
7
8
9
lntermountain Gas Company
Constant Growth DCF Model
(Sustainable Growth Rate)
Atmos Energy Corporation
New Jersey Resources Corporation
Northwest Natural Gas Company
South Jersey Industries, Inc.
Southwest Gas Corporation
Spire Inc.
WGL Holdings, Inc.
Average
Median
Sources:
13-WeekAVG
Stock Price'
(1)
$73.29
$33.32
$59.36
$29.40
$70.19
$63.36
$62.25
$55.88
'SNL Financial, Downloaded on November 17, 2016.
2 Exhibit No. 307, page 1.
'The Value Line Investment Survey, September 2, 2016.
Sustainable
Growth2
(2)
10.21%
5.27%
3.84%
5.89%
7.58%
6.29%
6.74%
6.55%
Annualized
Dividend'
(3)
$1.68
$0.96
$1.87
$1.06
$1.80
$1.96
$1.95
$1.61
Adjusted Constant
Yield Growth DCF
(4) (5)
2.53% 12.73%
3.03% 8.30%
3.27% 7.12%
3.80% 9.69%
2.76% 10.34%
3.29% 9.58%
3.35% 10.09%
3.15% 9.69%
9.69%
Exhibit No. 308
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 309
200
190
180
170
160
150
140
130
120
110
100
90
lntermountain Gas Company
Electricity Sales Are Linked to U.S. Economic Growth
Index 1988 = 100
Note:
1988 represents the base year. Graph depicts increases or decreases from the base year.
Sources:
U.S. Energy Information Administration
Federal Reserve Bank of St. Louis
Exhibit No. 309
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE ST ATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 310
Atmos Energy Corporation
New Jersey Resources Corporation
Northwest Natural Gas Company
South Jersey Industries, Inc
Southwest Gas Corporation
Spire Inc.
WGL Holdings, Inc.
Average
Median
Sources:
13-Weak AVG
Stock Price'
(1)
$73.29
$33.32
$59.38
$29.40
$70.19
$63.36
$62.25
$55.88
1 SNL Financial, Downloaded on November 17, 2016.
2 The Value Line Investment Survey, September 2, 2016.
3 Exhibit No. 304.
4 Blue Chip Financial Forecasts, December 1, 2016 at 14
lntermountain Gas Company
Multi-Stage Growth DCF Model
Annualized First Stage Second Stage Growth
Qiyidend2 Growth:, Yoar8 Yoar7 :!!!!!
(2) (3) (4) (5) (8)
$1.88 7.13% 8.85% 6.17% 5.89%
$0.96 5.93% 5.85% 5.37% 5.09%
$1.87 4.00% 4.04% 4.08% 4.13%
$1.08 10.00% 9.04% 8.08% 7.13%
$1.80 4.17% 4.18% 4.19% 4.21%
$1.96 4.73% 4.65% 4.57% 4.49%
$1.95 7.70% 7.13% 6.55% 5.98%
$1.81 8.24% 5.91% 5.58% 5.24%
Yoar9 !!!uQ
(7) (8)
5.21% 4.73%
4.81% 4.53%
4.17% 4.21%
6.17% 5.21%
4.22% 4.24%
4.41% 4.33%
5.40% 4.83%
4.91% 4.58%
Third Stage Multi-Stage
Growth4 ~
(9) (10)
4.25% 7.12%
4.25% 7.59%
4.25% 7.47%
4.25% 9.56%
4.25% 6.89%
4.25% 7.57%
4.25% 8.31%
4.25% 7.79%
7.57o/.
Exhibit No. 310
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 311
2.500
2.000
1.500
1.000
0.500
lntermountain Gas Company
Common Stock Market/Book Ratio
0.000 L..------------------------------------
#~~~#~~~ ~~~ ~~~~~#~~#~~#~#~~~~#~~~~~,1',,#
~
1980 -2000: Mergent Public Utility MarY.Jel.
2001 -2016: AUS Utility Reports, various dates.
Exhibit No. 311
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RATES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 312
lntermountain Gas Company
Equity Risk Premium -Treasury Bond
Authorized 30 yr. Indicated
Gas Treasury Risk
Line Year Returns1 Bond Yield2 Premium
(1) (2) (3)
1 1986 13.46% 7.80% 5.66%
2 1987 12.74% 8.58% 4.16%
3 1988 12.85% 8.96% 3.89%
4 1989 12.88% 8.45% 4.43%
5 1990 12.67% 8.61% 4.06%
6 1991 12.46% 8.14% 4.32%
7 1992 12.01% 7.67% 4.34%
8 1993 11.35% 6.60% 4.75%
9 1994 11.35% 7.37% 3.98%
10 1995 11.43% 6.88% 4.55%
11 1996 11.19% 6.70% 4.49%
12 1997 11.29% 6.61% 4.68%
13 1998 11.51% 5.58% 5.93%
14 1999 10.66% 5.87% 4.79%
15 2000 11.39% 5.94% 5.45%
16 2001 10.95% 5.49% 5.46%
17 2002 11.03% 5.43% 5.60%
18 2003 10.99% 4.96% 6.03%
19 2004 10.59% 5.05% 5.54%
20 2005 10.46% 4.65% 5.81%
21 2006 10.40% 4.99% 5.41%
22 2007 10.22% 4.83% 5.39%
23 2008 10.39% 4.28% 6.11%
24 2009 10.22% 4.07% 6.15%
25 2010 10.15% 4.25% 5.90%
26 2011 9.92% 3.91% 6.01%
27 2012 9.94% 2.92% 7.02%
28 2013 9.68% 3.45% 6.23%
29 2014 9.78% 3.34% 6.44%
30 2015 9.60% 2.84% 6.76%
31 2016 3 9.45% 2.52% 6.93%
32 Average 11.06% 5.70% 5.36%
33 Minimum
34 Maximum
Sources:
' Regulatory Research Associates, Inc ., Regulatory Focus, Major Rate Case Decisions,
January 1997 page 5, January 2011 page 3, and Octobet 2016 page 6.
2 St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/.
The yields from 2002 to 2005 represent the 20-Year Treasury yields oblained
from the Federal Reserve Bank.
3 The data includes the period Jan -Sep 2016.
Rolling
5 • Year
Average
(4)
4.44%
4.17%
4.21%
4.38%
4.29%
4.39%
4.42%
4.49%
4.73%
4.89%
5.07%
5.26%
5.45%
5.47%
5.62%
5.69%
5.68%
5.64%
5.65%
5.77%
5.79%
5.91%
6.24%
6.26%
6.32%
6.49%
6.68%
5.31%
4.17%
6.68%
Rolling
10 -Year
Average
(5)
4.42%
4.30%
4.35%
4.55%
4.59%
4.73%
4.84%
4.97%
5.10%
5.25%
5.38%
5.47%
5.54%
5.56%
5.69%
5.74%
5.80%
5.94%
5.96%
6.05%
6.14%
6.29%
5.30%
4.30%
6.29%
Exhibit No. 312
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No . 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 313
lntermou ntai n Gas Company
Equity Risk Premium -Utility Bond
Authorized Average Indicated Rolling Rolling
Gas "A" Rated Utility Risk 5 -Year 10 -Year
Line Year Returns1 Bond Yield2 Premium Average Average
(1) (2) (3) (4) (5)
1 1986 13.46% 9.58% 3.88%
2 1987 12.74% 10.10% 2.64%
3 1988 12.85% 10.49% 2.36%
4 1989 12.88% 9.77% 3.11%
5 1990 12.67% 9.86% 2.81% 2.96%
6 1991 12.46% 9.36% 3.10% 2.80%
7 1992 12.01% 8.69% 3.32% 2.94%
8 1993 11.35% 7.59% 3.76% 3.22%
9 1994 11.35% 8.31% 3.04% 3.21%
10 1995 11.43% 7.89% 3.54% 3.35% 3.16%
11 1996 11.19% 7.75% 3.44% 3.42% 3.11%
12 1997 11.29% 7.60% 3.69% 3.49% 3.22%
13 1998 11.51% 7.04% 4.47% 3.64% 3.43%
14 1999 10.66% 7.62% 3.04% 3.64% 3.42%
15 2000 11.39% 8.24% 3.15% 3.56% 3.45%
16 2001 10.95% 7.76% 3.19% 3.51% 3.46%
17 2002 11.03% 7.37% 3.66% 3.50% 3.50%
18 2003 10.99% 6.58% 4.41% 3.49% 3.56%
19 2004 10.59% 6.16% 4.43% 3.77% 3.70%
20 2005 10.46% 5.65% 4.81% 4.10% 3.83%
21 2006 10.40% 6.07% 4.33% 4.33% 3.92%
22 2007 10.22% 6.07% 4.15% 4.43% 3.96%
23 2008 10.39% 6.53% 3.86% 4.32% 3.90%
24 2009 10.22% 6.04% 4.18% 4.27% 4.02%
25 2010 10.15% 5.46% 4.69% 4.24% 4.17%
26 2011 9.92% 5.04% 4.88% 4.35% 4.34%
27 2012 9.94% 4.13% 5.81% 4.68% 4.56%
28 2013 9.68% 4.48% 5.20% 4.95% 4.63%
29 2014 9.78% 4.28% 5.50% 5.22% 4.74%
30 2015 9.60% 4.12% 5.48% 5.38% 4.81%
31 2016 3 9.45% 3.89% 5.56% 5.51 % 4.93%
32 Average 11.06% 7.08% 3.98% 3.94% 3.90%
33 Minimum 2.80% 3.11%
34 Maximum 5.51% 4.93%
Sources:
' Regulatory Research Associates, Inc., Regulatory Focus, Major Rate Case Decisions, Calendar 2015.
January 1997 page 5, January 2011 page 3, and Octobet 2016 page 6.
2 Mergen! Public Utility Manual, Mergen! Weekly News Reports, 2003. The utility yields
for the period 2001-2009 were obtained from the Mergen! Bond Record. The utility
yields from 2010-2016 were obtained from http://credittrends.moodys.com/.
3 The data includes the period Jan -Sep 2016.
Exhibit No. 313
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No . 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMP ANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STA TE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 314
Line
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lntermountain Gas Company
Bond Yield Spreads
Public Utility Bond C~ta Bond Utility to Corporate
T-Bond A-T-Bond Ba•T-Bond Aaa-T-Bond Baa-T-Bond Baa A·Aaa
l'.!!! Yield1 ~ Baa2 Spread Spread Aaa1 Baa' Spread Spread Spread Spread
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)
1980 11.30% 13.34% 13.95% 2.04% 2.65% 11.94% 13.67% 0.64% 2.37% 0.28% 1.40%
1981 13.44% 15.95% 16.60% 2.51% 3.16% 14.17% 16.04% 0.73% 2.60% 0.56% 1.78%
1982 12.76% 15.86% 16.45% 3.10% 3.69% 13.79% 16.11% 1.03% 3.35% 0.34% 2.07%
1983 11.18% 13.66% 14.20% 2.48% 3.02% 12.04% 13.55% 0.86% 2.38% 0.65% 1.62%
1984 12.39% 14.03% 14.53% 1.64% 2.14% 12.71% 14.19% 0.32% 1.80% 0.34% 1.32%
1985 10.79% 12.47% 12.96% 1.68% 2.17% 11.37% 12.72% 0.58% 1.93% 0.24% 1.10%
1986 7.80% 9.58% 10.00% 1.78% 2.20% 9.02% 10.39% 1.22% 2.59% -0.39% 0.56%
1987 8.58% 10.10% 10.53% 1.52% 1.95% 9.38% 10.58% 0.80% 2.00% -0.05% 0.72%
1988 8.96% 10.49% 11.00% 1.53% 2.04% 9.71% 10.83% 0.75% 1.87% 0.17% 0.78%
1989 8.45% 9.77% 9.97% 1.32% 1.52% 9.26% 10.18% 0.81% 1.73% -0.21% 0.51%
1990 8.61% 9.86% 10.06% 1.25% 1.45% 9.32% 10.36% 0.71% 1.75% -0.29% 0.54%
1991 8.14% 9.36% 9.55% 1.22% 1.41% 8.77% 9.80% 0.63% 1.67% -0.25% 0.59%
1992 7.67% 8.69% 8.86% 1.02% 1.19% 8.14% 8.98% 0.47% 1.31% --0.12% 0.55%
1993 6.60% 7.59% 7.91% 0.99% 1.31% 7.22% 7.93% 0.62% 1.33% --0.02% 0.37%
1994 7.37% 8.31% 8.63% 0.94% 1.26% 7.96% 8.62% 0.59% 1.25% 0.01% 0.35%
1995 6.88% 7.89% 8.29% 1.01% 1.41% 7.59% 8.20% 0.71% 1.32% 0.09% 0.30%
1996 6.70% 7.75% 8.17% 1.05% 1.47% 7.37% 8.05% 0.67% 1.35% 0.12% 0.38%
1997 6.61% 7.60% 7.95% 0.99% 1.34% 7.26% 7.86% 0.66% 1.26% 0.09% 0.34%
1996 5.58% 7.04% 7.26% 1.46% 1.68% 6.53% 7.22% 0.95% 1.64% 0.04% 0.51%
1999 5.87% 7.62% 7.88% 1.75% 2.01% 7.04% 7.87% 1.18% 2.01% 0.01% 0.58%
2000 5.94% 8.24% 8.36% 2.30% 2.42% 7.62% 8.36% 1.68% 2.42% -0.01% 0.62%
2001 5.49% 7.76% 8.03% 2.27% 2.54% 7.08% 7.95% 1.59% 2.45% 0.08% 0.68%
2002 5.43% 7.37% 8.02% 1.94% 2.59% 6.49% 7.80% 1.06% 2.37% 0.22% 0.88%
2003 4.96% 6.58% 6.84% 1.62% 1.89% 5.67% 6.77% 0.71% 1.81% 0.08% 0.91%
2004 5.05% 6.16% 6.40% 1.11% 1.35% 5.63% 6.39% 0.58% 1.35% 0.00% 0.53%
2005 4.65% 5.65% 5.93% 1.00% 1.28% 5.24% 6.06% 0.59% 1.42% -0.14% 0.41%
2006 4.99% 6.07% 6.32% 1.08% 1.32% 5.59% 6.48% 0.60% 1.49% --0.16% 0.48%
2007 4.83% 6.07% 6.33% 1.24% 1.50% 5.56% 6.48% 0.72% 1.65% --0.15% 0.52%
2008 4.28% 6.53% 7.25% 2.25% 2.97% 5.63% 7.45% 1.35% 3.17% --0.20% 0.90%
2009 4.07% 6.04% 7.06% 1.97% 2.99% 5.31% 7.30% 1.24% 3.23% -0.24% 0.72%
2010 4.25% 5.46% 5.96% 1.21% 1.71% 4.94% 6.04% 0.69% 1.79% -0.08% 0.52%
2011 3.91% 5.04% 5.56% 1.13% 1.65% 4.64% 5.66% 0.73% 1.75% --0.10% 0.40%
2012 2.92% 4.13% 4.83% 1.21% 1.91% 3.67% 4.94% 0.75% 2.01% --0.11% 0.46%
2013 3.45% 4.48% 4.98% 1.03% 1.53% 4.24% 5.10% 0.79% 1.65% --0.12% 0.24%
2014 3.34% 4.28% 4.80% 0.94% 1.46% 4.16% 4.85% 0.82% 1.51% -0.06% 0.11%
2015 2.84% 4.12% 5.03% 1.27% 2.19% 3.89% 5.00% 1.05% 2.16% 0.03% 0.23%
2016 3 2.52% 3.89% 4.70% 1.37% 2.18% 3.62% 4.74% 1.10% 2.22% -0.04% 0.28%
Average 8.72% 8.24% 8.68% 1.52% 1.98% 7.58% 8.68% 0.84% 1.94% 0.02"/o 0.68%
Yield Spreads
Treasury Vs. Corporate & Treasury Vs. Utility
4.00%
3.50%
3.00%
2.50%
2.00%
1.50%
1.00%
0.50%
0.00%
1980 1982 1984 1986 1988 1990 1992 1994 1996 1998
-+-Utility A -T-Bond Spread
-.-Corporate Aaa -T -Bond Spread
Sources:
1 St. Louis Federal Reserve: Eoonomic Research, http://research.stlouisfed.org/.
2 Mergent Public Utility Manual, Mergent Weekly News Reports, 2003. The utility yields
for the period 2001-2009 i,vere obtained from the Mergent Bond Record. The utility
yields from 2010-2016 were obtained from http:llcredittrends.moodys.com/.
3 The data includes the period Jan -Sep 2016.
2000 2002 2004 2006 2008 2010 2012 2014 2016
~UtilityBaa -T-Bond Spread
-+-Corporate Baa -T -Bond Spread
Exhibit No. 314
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -3 88-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMP ANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE ST ATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 315
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lntermountain Gas Company
Treasury and Utility Bond Yields
Treasury "A" Rated Utility "Baa" Rated Utility
Date Bond Yield1 Bond Yield2 Bond Yield2
(1) (2) (3)
11/10/16 2.94% 4.12% 4.70%
11/04/16 2.56% 3.81% 4.38%
10/28/16 2.62% 3.86% 4.40%
10/21/16 2.48% 3.75% 4.30%
10/14/16 2.55% 3.83% 4.41%
10/07/16 2.46% 3.76% 4.33%
09/30/16 2.32% 3.64% 4.26%
09/23/16 2.34% 3.65% 4.26%
09/16/16 2.44% 3.76% 4.37%
09/09/16 2.39% 3.69% 4.29%
09/02/16 2.28% 3.58% 4.19%
08/26/16 2.29% 3.62% 4.22%
08/19/16 2.29% 3.60% 4.22%
Average 2.46% 3.74% 4.33%
Spread To Treasury 1.28% 1.87%
Sources:
1 St. Louis Federal Reserve: Economic Research, http://research.stlouisfed .org.
2 http://credittrends.moodys.com/.
Exhibit No. 315
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 3
10.00%
··""'
7.00%
'·"°"
4.00%
3.00%
lntermountain Gas Company
Trends in Bond Yields
_______ "Baa" Rated Utility Bond Yield
-"A" Rated Utility Bond Yield
--.---30-YearTreasury Bond
'·""" ,__ _________ ,_ _______________________________ _
,.#... ,I'" #"~ #''), ,..#' ,I''), -,:-. #'' ~ ... ti... ~,ts" ,f,.., ... ;"'" ,f, ...... .,...
Sources:
Mergent Bond Record.
www.moodys.com, Bond Yields and Key Indicators.
St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/
Exhibit No. 315
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 2 of 3
lntermountain Gas Company
Yield Spread Between Utility Bonds and 30-Year Treasury Bonds
6.00% --------------------------
5.00% +---------------.+------------------------------
4.00% +--------------
3.00% I-------
2.00%
1.00%
-+-A Spread -Baa Spread
Sources:
Mergent Bond Record.
www.moodys.com, Bond Yields and Key Indicators.
St. Louis Federal Reserve: Economic Research, http://research.stlouisfed.org/
Exhibit No. 315
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 3 of 3
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMP ANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 316
Line
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lntermountain Gas Company
Value Line Beta
Company
Atmos Energy Corporation
New Jersey Resources Corporation
Northwest Natural Gas Company
South Jersey Industries, Inc.
Southwest Gas Corporation
Spire Inc.
WGL Holdings, Inc.
Average
Source:
The Value Line Investment Survey,
September 2, 2016.
Beta
0.75
0.80
0.65
0.80
0.75
0.70
0.75
0.74
Exhibit No. 316
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RA TES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE STATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 317
Line
1
2
3
4
lntermountain Gas Company
CAPM Return
High Low
Market Risk Market Risk
Description Premium Premium
(1) (2)
Risk-Free Rate 1 3.40% 3.40%
Risk Premium2 7.80% 6.00%
Beta3 0.74 0.74
CAPM 9.19% 7.86%
Sources:
1 Blue Chip Financial Forecasts; December 1, 2016, at 2.
2 Duff & Phelps, 2016 Valuation Handbook Guide to Cost of Capital
at 2-4, 3-31 , and 3-40.
3 Exhibit No. 316.
Exhibit No. 317
Case No. INT-G-16-02
M. Gorman, NWIGU
p. 1 of 1
Chad M. Stokes (OSB No. 004007)
Tommy A. Brooks (OSB No. 076071)
Cable Huston LLP
1001 SW Fifth Ave., Suite 2000
Portland, OR 97204-1136
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Michael C. Creamer (ISB No. 4030)
Givens Pursley LLP
601 W. Bannock St.
Boise, ID 83 702
Telephone: [phone]
Facsimile: (208) -388-1300
[e-mail]
Attorneys for Northwest Industrial Gas Users
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF
INTERMOUNTAIN GAS COMPANY
FOR THE AUTHORITY TO CHANGE
ITS RATES AND CHARGES FOR
NATURAL GAS SERVICE TO NATURAL
GAS CUSTOMERS IN THE ST ATE OF
IDAHO
CASE NO. INT-G-16-02
EXHIBIT NO. 318
lntermountain Gas Company
Standard & Poor's Credit Metrics
Rate Base
Weighted Common Return
Pre-Tax Rate of Return
Income to Common
5 EBIT
6 Depreciation & Amortization
Imputed Amortization
Deferred Income Taxes & ITC
Funds from Operations (FFO)
Retail
Cost of Service
Amount ($000)
(1)
236,926,497
4.46%
10.03%
10,576,399
23,754,571
21,707,112
32,283,511
1 O Imputed & Capitalized Interest Expense $
11 EBITDA $ 45,461,683
12 Total Debt Ratio
13 Debt to EBITDA
14 FFO to Total Debt
Sources:
52%
2.7x
26%
S&P Benchmark (Medial Volatility)112
Intermediate Significant Aggreaeive
(2) (3) (4)
2.5x - 3.5x
23% • 35%
3.5x -4.5x
13% -23%
4.5x - 5.5x
9%-13%
1 Standard & Poor's RatingsDirect: "Criteria: Corporate Methodology,R November 19, 2013.
Reference
(5)
Darrington, Exhibit No. 16.
Page 2, Line 2. Col. 3.
Page 2, Line 3, Col. 4.
Line 1 x Line 2.
Line 1 x Line 3.
Darrington, Exhibit No. 16.
N/A
N/A
Sum of line 4 and Lines 6 through 8.
N/A
Sum of Lines 5 through 7 and Line 10.
Page 3, Line 4, Col. 2.
(Line 1 x Line 12) / Line 11.
line 91 (Line 1 x line 12).
2 Standard & Poor's RatingsDirect: RMDU Resources Group Inc. Outlook Revised To Stable From Negative On Planned Sale Of Unregulated Assets;
Ratings Affirmed," November 21, 2016.R
Note:
Based on the November 2015 S&P report, MDU has an RExcellenr business risk profile and a RSignificant" financial risk profile,
and falls under the "Medial Volatility"' matrix.
Exhibit No. 318
Case No. INT-G-16-02
M.Gorman, NWIGU
p. 1 of 3
Line
1
2
3
4
lntermountain Gas Company
Standard & Poor's Credit Metrics
(Pre-Tax Rate of Return)
Description Weight Cost
(1) (2)
Long-Term Debt 52.00% 4.94%
Common Equity 48.00% 9.30%
Total 100.00%
Tax Conversion Factor*
Source:
Exhibit No. 301 .
* Darrington, Exhibit No. 16.
Pre-Tax
Weighted Weighted
Cost Cost
(3) (4)
2.57% 2.57%
4.46% 7.46%
7.03% 10.03%
1.6706
Exhibit No. 318
Case No. INT-G-16-02
M.Gorman, NWIGU
p. 2 of 3
Line
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2
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8
9
10
11
12
lntermountain Gas Company
Standard & Poor's Credit Metrics
(June 30, 2016)
Credit Rating FFO / Debt (%) Debt I Cai;!ital (%)
(1) (2) (3)
Value Line Publicl)l Traded Electric Utilit)l Coml;!anies
A Rated
Average A-19.02
Median A-16.26
BBB Rated
Average BBB 16.39
Median BBB 17.06
All Utilities
Average BBB+ 17.27
Median BBB+ 16.30
Electric Oi;!erating Subsidia!Y Coml;!anies
A Rated
Average A-21 .31
Median A-21.99
BBB Rated
Average BBB 20.61
Median BBB 19.94
All Utilities
Average BBB+ 20.92
Median BBB+ 20.93
Source:
www.globalcreditportal.com/ratingsdirecU
Downloaded November 17, 2016.
56.43
54.51
56.29
56.88
56.33
55.89
50.76
50.77
53.03
53.63
52 .03
52.15
Exhibit No. 318
Case No. INT-G-16-02
M.Gorman , NWIGU
p. 3 of 3