before the state of new york public service commission

BEFORE THE STATE OF NEW YORK PUBLIC SERVICE COMMISSION

Case 11-G-0280

In the Matter Of

Corning Natural Gas Corporation

November 2011

Prepared Testimony of: GAS RATES PANEL Hieu Cam Junior Engineer Johanna Miller Utility Engineer I Aferdita Bardhi Utility Engineer II Aric J. Rider, Sr. Utility Engineer III

State of New York Department of Public Service Three Empire State Plaza Albany, New York 12223-1350

CASE 11-G-0280 GAS RATES PANEL

i

Table of Contents 1

Introductions and Qualifications .......................... 2 2 Scope of Testimony ........................................ 6 3 Firm Sales Forecast ...................................... 10 4 Rate Year Revenues at Current Rates ...................... 15 5 Rate Year One .......................................... 15 6 Rate Year Two .......................................... 21 7 Rate Year Three ........................................ 22 8

Other Revenues ........................................... 23 9 Depreciation Rates ....................................... 24 10 Amortization Period of the Depreciation over Accrual ..... 25 11 Capital Expenditure Forecasts ............................ 27 12 Capital Expenditure Justification ........................ 28 13 Capital Expenditure Project Estimation ................... 31 14 Recommendations for Capital Expenditure Justification and 15 Project Estimation ....................................... 34 16 Capital Expenditure Variance Reports ..................... 36 17 Capital Expenditures Overview ............................ 38 18 Proposed Capital Expenditure Adjustments ................. 40 19 Meters and Regulators .................................. 41 20 New Main Installations ................................. 42 21 Main – High Pressure Distribution ...................... 43 22 Transportation Equipment ............................... 47 23 Tools and Equipment .................................... 48 24 General Office ......................................... 48 25 IT Equipment ........................................... 49 26 Virgil Franchise Expansion ............................. 50 27

Line 13 Plant Adjustment ................................. 51 28 Service Extension Adjustment ............................. 52 29 Gas Plant in Service ..................................... 52 30 Net Plant True-Up Mechanism .............................. 54 31 Tariff Changes ........................................... 56 32 Tariff Consolidation ................................... 56 33 Bath Revenue True-up Adjustment ........................ 57 34 Lost and Unaccounted For Gas Factors ................... 58 35

Cost of Service Study .................................... 61 36 Revenue Allocation ....................................... 65 37 Rate Design .............................................. 71 38 Merchant Function Charge ................................. 74 39 Revenue Decoupling Mechanism ............................. 78 40 41


2

Introductions and Qualifications 1

Q. Mr. Cam, please state your name and business address. 2

A. Hieu T. Cam, Three Empire State Plaza, Albany, New 3

York 12223. 4

Q. Mr. Cam, what is your position with the Department of 5

Public Service (Department)? 6

A. I am a Junior Engineer in the Gas Rates and Tariffs 7

Section of the Office of Electric, Gas and Water. 8

Q. Mr. Cam, please state your educational background and 9

professional experience. 10

A. I received a Bachelor of Science Degree in Civil 11

Engineering from Clarkson University in 2007. After 12

graduating from Clarkson University, I worked for The 13

Whiting-Turner Contracting Company where my tasks 14

included estimating and monitoring sub-contractors, 15

drafting bid documents and conducting field 16

inspections. In 2008, I returned to Clarkson 17

University where I obtained a Master of Science in 18

Civil Engineering. I joined the Department in 2010 as 19

a Junior Engineer. 20

Q. Mr. Cam, what are your duties in the Gas Rates and 21

Tariff Section? 22


3

A. My duties include drafting reports and memoranda, 1

forecasting sales and revenues and reviewing various 2

other utility filings. 3

Q. Have you previously testified in proceedings before 4

the Public Service Commission (Commission)? 5

A. No. 6

Q. Ms. Miller, please state your name, employer, and 7

business address. 8

A. Johanna Miller. I am employed by the Department, 9

Three Empire State Plaza, Albany, New York 12223. 10

Q. In what capacity are you employed by the Department? 11

A. I am a Utility Engineer I in the Office of Electric, 12

Gas and Water, Gas Rates and Tariffs Section. 13

Q. Please summarize your education and professional 14

experience. 15

A. I received a Bachelors of Science degree in Mechanical 16

Engineering from the University of Delaware in January 17

of 2008. I began employment with the Department in 18

May of 2008 as a Junior Engineer and was promoted to 19

my current position of Utility Engineer I in May of 20

2009. 21

Q. Have you filed testimony before the Commission in 22

other proceedings? 23

A. Yes, I have testified in Central Hudson’s rate cases 24


4

08-G-0888 and 09-G-0589. 1

Q. Ms. Bardhi, please state your name, employer, and 2

business address? 3

A. Aferdita Bardhi. I am employed by the Department, 4

Three Empire State Plaza, Albany, New York 12223. 5

Q. Ms. Bardhi, could you please discuss your educational 6

background, professional experience and 7

responsibilities? 8

A. I graduated from the State University of New York at 9

Buffalo in 1999 with a Bachelors of Science degree in 10

Civil Engineering. I joined the Department in 11

February 2005 and am currently employed as a Utility 12

Engineer 2 in the Office of Electric, Gas and Water, 13

Gas Rates and Tariffs Section. Previously, I have 14

worked as a structural engineer in the private sector. 15

My current duties with the Department relate to gas 16

utility matters, including preparation of materials 17

for proceedings before the Commission. 18

Q. Have you filed testimony before the Commission in 19

other proceedings? 20

A. Yes, most recently in National Grid’s electric rate 21

case 10-E-0050. 22

Q. Mr. Rider, please state your name, employer and 23

business address. 24


5

A. Aric J. Rider, Sr. I am employed by the Department. 1

My business address is Three Empire State Plaza, 2

Albany, New York 12223. 3

Q. Mr. Rider, what is your current position? 4

A. I am a Utility Engineer 3, currently assigned to the 5

Gas Rates and Tariffs Section of the Office of 6

Electric, Gas and Water. 7

Q. Mr. Rider, please provide a summary of your 8

educational background and professional experience. 9

A. I hold a Bachelor of Science Degree in Civil 10

Engineering Technology, which I received in 2001 from 11

the State University of New York Institute of 12

Technology at Utica/Rome. Within the Office of 13

Electric, Gas and Water, I am currently assigned to 14

the Gas Rates and Tariffs Section. I previously have 15

been assigned to the Gas Rates, Gas Safety, Gas Policy 16

and Electric Rates Sections. My duties involve the 17

engineering analysis of utility operations as they 18

relate to the ratemaking process, as well as 19

participating in various reviews of local distribution 20

companies’ activities. 21

Q. Mr. Rider, have you previously testified before the 22

Commission? 23


6

A. Yes, I have testified in several proceedings before 1

the Commission regarding cost of service (COS), 2

capital expenditures, depreciation, sales forecasts, 3

revenue allocation, rate design, merchant function 4

charges (MFC), revenue decoupling mechanisms (RDM), 5

gas safety performance mechanisms and tariff issues. 6

Scope of Testimony 7

Q. What is the scope of the Gas Rates Panel’s (Panel) 8

testimony in this proceeding? 9

A. The Company filed a three year rate case (rate year 10

one is 12 months ended April 30, 2013, rate year two 11

is 12 months ended April 30, 2014, and rate year three 12

is 12 months ended April 30, 2015) followed by two 13

more years of staged increases. We are testifying to 14

a three year rate plan consisting of the following 15

issues: (1) our firm sales and transportation forecast 16

in terms of the number of customers and our negotiated 17

contracts forecast; (2) our forecasted gas delivery 18

revenues at current rates; (3) other revenues 19

including reconnect fees and surcharges; (4) updates 20

to specific Company depreciation rates; (5) the 21

amortization period for the depreciation over accrual; 22

(6) capital expenditure projects justification and 23

estimation; (7) our adjustments to the Company’s 24


7

capital expenditures budget; (8) Line 13 plant 1

adjustment; (9) service extensions; (10) net plant in 2

service; (11) net plant true-up mechanism; (12) tariff 3

consolidation; (13) the Bath system true-up mechanism; 4

(14) the loss factor of adjustment (LAUF); (15) the 5

Company’s COS studies which support revenue 6

allocation, rate design and unbundled rates for 7

competitive services; (16) our revenue allocation and 8

rate design; (17) the MFC; and (18) the RDM. 9

Q. Are you sponsoring any exhibits? 10

A. Yes. We are sponsoring 22 exhibits. 11

Q. Would you briefly describe each exhibit? 12

Exhibit ___(GRP-1) contains our referred to Company 13

responses to Staff’s interrogatory requests (IRs). 14

Exhibit ___(GRP-2 Corrected) contains a comparison of 15

our forecast customers and volumes with the Company’s 16

forecasts. 17

Exhibit ___(GRP-3) contains graphs comparing our and 18

customer and usage forecasts with the Company. 19

Exhibit ___(GRP-4 Corrected) contains a comparison of 20

our priced out revenues at current rates with the 21

Company. 22

Exhibit ___(GRP-5) contains our proposed other revenue 23

forecast. 24


8

Exhibit ___(GRP-6) contains a New York State utility 1

depreciation survey. 2

Exhibit ___(GRP-7) contains a comparison of New York 3

State gas utilities’ historic capital expenditure 4

budgets versus their operating revenues and net plant 5

in service. 6

Exhibit ___(GRP-8) contains our recommended project 7

justification template. 8

Exhibit ___(GRP-9 Corrected) contains the proposed 9

capital budgets which include our adjustments to 10

specific projects. 11

Exhibit ___(GRP-10) contains our adjustments to 12

transportation equipment and tools and equipment 13

forecasts. 14

Exhibit ___(GRP-11 Corrected) contains our recommended 15

changes to plant in service. 16

Exhibit ___(GRP-12 Corrected) contains the development 17

of depreciation expense for the rate year. 18

Exhibit ___(GRP-13) contains our proposed consolidated 19

tariff. 20

Exhibit ___(GRP-14) contains our recommended LAUF 21

factor. 22

Exhibit ___(GRP-15) contains a study by Staff of the 23

Department regarding the LAUF incentive. 24


9

Exhibit ___(GRP-16 Corrected) contains our proposed 1

revenue allocation for rate years one, two and three. 2

Exhibit ___(GRP-17) contains a summary of customer 3

costs from different cost studies. 4

Exhibit ___(GRP-18 Corrected) contains our priced out 5

forecasts at current rates and proposed rates. 6

Exhibit ___(GRP-19) contains our development of the 7

MFC. 8

Exhibit ___(GRP-20) contains our proposed methodology 9

for transitioning the MFC from the current rate year 10

to the new rate year. 11

Exhibit ___(GRP-21 Corrected) contains our RDM 12

targets. 13

Exhibit ___(GRP-22) contains our proposed methodology 14

for transitioning the RDM from the current rate year 15

to the new rate year. 16

Q. How are the IRs responded to by the Company, 17

identified in the Panel’s testimony and exhibits, 18

organized? 19

A. When we refer to IR responses, we reference Staff’s 20

assigned request number (e.g., DPS-21). 21

Q. Have you included the Company's entire responses to 22

the various IRs in Exhibit ___(GRP-1)? 23


10

A. Not in all cases. Due to the voluminous nature of 1

some of the responses, we have only included those 2

pages of the responses we deem relevant. To the 3

extent the Company or any other party believes we may 4

have omitted anything of further relevance, they can 5

supplement the record with the additional information. 6

Firm Sales Forecast 7

Q. Can you briefly explain how the Company prepared its 8

customer and volumetric firm sales forecast? 9

A. For Service Classification (SC) No. 1 - Corning 10

Residential, the Company added approximately 100 new 11

customers due to service inquiries in its Virgil 12

franchise territory. For all other SCs, the Company 13

used the test year customer data, twelve months ending 14

December 31, 2010, as the rate year forecast. The 15

customer counts did not increase for the second and 16

third rate years. The Company used the test year 17

sales data, normalized for changes in the weather, for 18

all three rate years. 19

Q. Does the Panel recommend changes to the Company’s 20

sales forecast? 21

A. Yes. We recommend modifications to the customer 22

forecast and we also propose to develop a use per 23

customer (UPC) forecast per SC that we apply to our 24


11

customer forecast to generate our volumetric forecast. 1

Our changes are summarized in Exhibit ___(GRP-2 2

Corrected). 3

Q. Please explain how you developed your customer 4

forecast. 5

A. We plotted a twelve month rolling average of the 6

amount of customers against time for the most recent 7

three years to determine the trend of growth (or 8

reduction in some cases). For the SCs that showed a 9

linear trend, the amount of customers was extrapolated 10

into the rate years. For the SCs that showed 11

fluctuations, the latest twelve months of customer 12

counts were used as the forecast for the rate years. 13

Q. Please explain how you forecasted UPC for each SC. 14

A. Generally, we tested the Company’s data to determine 15

if a linear regression analysis had a reasonable 16

correlation coefficient, an R2, between the actual and 17

calculated data of greater than 0.8. For other SCs, 18

where usages fluctuated and a regression analysis 19

failed to yield a significant linearity, an average 20

UPC was used. 21

Q. How did the Panel forecast UPC for the residential 22

SCs? 23


12

A. For SC No. 14 - Corning Aggregation Residential, and 1

SC No. 1 - Corning Residential, we used the latest 2

twelve month average UPC as the forecast. However, 3

the Company has begun serving residential customers in 4

its expanded franchise area (Virgil) and, we, 5

therefore, forecasted the residential customers for 6

Virgil separately because they pay a separate 7

surcharge to write down plant. For Virgil, we agreed 8

with the Company’s UPC forecast. 9

Q. Why did the Panel use the latest twelve month UPC for 10

residential SCs? 11

A. As customers update or replace their appliances and 12

heating equipment, their usages will decline as shown 13

in Exhibit ___(GRP-3). We believe the latest twelve 14

month UPC for residential SCs is the best indication 15

currently available for customers’ usage in the rate 16

years. 17

Q. Did you consider that the migration of residential 18

customers between SCs could affect the Panel’s UPC 19

forecast? 20

A. Yes. Based on the discussion with the Company and per 21

its response to IR DPS-254, it appears that the SC No. 22

14 - Corning Residential customers are migrating back 23

to SC No. 1 - Corning Residential. Customers in SC 24


13

No. 14 - Corning Aggregation Residential use on 1

average 200 ccf more per year as compared to SC No. 1 2

- Corning Residential customers and, therefore, the 3

UPC for SC No. 1 - Corning Residential for the rate 4

years can be determined by analyzing the usage and 5

amount of customers migrating to SC No. 1 - Corning 6

Residential in each rate year. 7

Q. Please explain how you forecasted total volumes for 8

each SC. 9

A. We forecasted volumes by multiplying our forecasted 10

UPC for each SC by our forecasted amount of customers 11

in each SC. 12

Q. Are your results for residential customer counts and 13

volume consistent with the Company’s? 14

A. No. Based on our forecast, we projected 50, 95, and 15

140 more residential customers than the Company 16

forecasted for rate years one, two and three, 17

respectively. Overall, we projected 115,112, 154,282, 18

and 198,990 ccf higher volume than the Company’s firm 19

residential sales forecast for rate years one, two and 20

three, respectively. 21

Q. How did the Company forecast sales volumes for 22

negotiated contract customers? 23


14

A. For negotiated contracts numbered 1, 2, 3, 4, 5 and 6, 1

the Company used actual sales volumes from the test 2

year period (twelve months ending December 31, 2010) 3

for the forecasted sales amount in each of the three 4

rate years. For the NYSEG contract, the Company used 5

the weather normalized sales from the test year for 6

the forecasted sales amount in each of the three rate 7

years. 8

Q. Does the Panel agree with the Company’s method of 9

using actual sales as opposed to weather normalized 10

sales? 11

A. Yes. Contract customers typically use large amounts 12

of gas for manufacturing and other industrial uses, 13

thus, their consumption of gas is less dependent on 14

weather. 15

Q. How does the Panel forecast sales for these customers? 16

A. Since there are many factors, such as the instability 17

of the economy and declines or expansions of 18

manufacturing facilities, that can affect how these 19

customers use gas, it is difficult to forecast their 20

usage based on historical data. For this reason, we 21

used the latest twelve month usage to forecast the 22

sales volumes for the three rate years. Similar to 23

the Company’s method, we used weather normalized sales 24


15

to forecast the sales for NYSEG and actual sales for 1

all other contract sales. 2

Q. Please summarize your results. 3

A. As shown on Exhibit ___(GRP-2 Corrected), our forecast 4

is 1,158,703 ccf higher than the Company’s forecast 5

for contracts for each of the rate years. 6

Rate Year Revenues at Current Rates 7

Rate Year One 8

Q. Please identify the components of the Company’s firm 9

delivery revenue forecast for rate year one. 10

A. The Company forecasted base delivery revenue and other 11

revenues consisting of local production, accelerated 12

recovery of plant and MFC. 13

Q. What did the Company forecast in rate year one? 14

A. The Company forecasted $11,128,548 for base delivery 15

revenue. For local production, accelerated recovery 16

of plant and MFC revenue the Company forecasted 17

$1,699,584 (Company Exhibit ___(CNG-3), Summary Page 1 18

of 4). 19

Q. Does the Panel agree with the Company’s forecast? 20

A. No. 21

Q. What did the Panel forecast for base delivery revenue 22

and other revenue in rate year one at current rates? 23

A. As shown on Exhibit ___(GRP-4 Corrected), we 24


16

forecasted $10,470,243 for rate year one base delivery 1

revenues at current rates. Our local production 2

revenues, accelerated recovery of plant and MFC 3

revenue is forecasted at $1,678,841. Our total 4

delivery revenue forecast, excluding gas costs, is 5

$13,040,415 which results in an upward adjustment to 6

rate year one revenues of $212,283, excluding taxes. 7

Q. Please explain the difference in the Panel’s forecast 8

to base delivery revenue and other revenue? 9

A. We made the following adjustments: (1) priced out our 10

sales forecast, (2) increased transportation contract 11

revenue, (3) adjusted the MFC, (4) included RDM 12

revenue, (5) included Line 15 transportation charges 13

(6) included Bath transportation charges, (7) updated 14

Commission specific plant write downs, (8) updated the 15

local production forecast, and (9) priced out our 16

negotiated contract forecasts. 17

Q. Please describe how the Panel priced out its sales 18

forecast. 19

A. We allocated our weather normalized forecasted annual 20

sales volumes to the rate blocks using a three year 21

historic distribution. We then priced those volumes 22

and the forecasted number of customer bills out at 23

current rates. Our base delivery revenue resulted in 24


17

an increase of $190,135 compared to the Company’s 1

forecast. 2

Q. Please explain how the Panel adjusted the Company’s 3

transportation contract revenue. 4

A. We adjusted the transportation revenue upward by 5

$25,382 based on the Company’s updated forecast as 6

shown in response to IR DPS-182. In addition, the 7

Company incorrectly priced out one of its 8

transportation customer’s revenue at the test year 9

rate and not the actual rate year rate, which is 10

slightly higher. 11

Q. Please explain the Panel’s RDM adjustment. 12

A. The Company did not include RDM revenue in its 13

delivery revenue forecast and should have. 14

Q Is it necessary to include RDM revenue? 15

A. Yes. We must assume that the current RDM rates will 16

continue in rate year one and we, therefore, included 17

$21,378 of RDM target revenues in our price out for 18

rate year one. 19

Q. Please explain the Panel’s MFC adjustment compared to 20

the Company’s forecast. 21

A. The Company forecasted MFC revenue of $500,174 in base 22

delivery revenue and $378,026 in other revenues for a 23

total of $878,200 revenues in rate year one. We 24


18

included, in base delivery revenue, the fixed MFC 1

component totaling $361,963 which consists of $123,449 2

for gas supply procurement and $238,514 for records 3

and collections which reduces the Company’s total 4

forecast of $878,200 by $516,237. 5

Q. For simplicity, have you broken the total MFC revenue 6

into three pieces? 7

A. Yes. We will discuss the fixed MFC, the variable MFC 8

and the other revenue components. 9

Q. What should the forecast for the fixed MFC component 10

be for rate year revenues at current rates? 11

A. We forecasted $361,963 consisting of $123,449 for gas 12

supply procurement and $238,514 for records and 13

collections, which are the targets developed in the 14

last rate case. 15

Q. What are you calling the variable MFC component? 16

A. The variable MFC component is the commodity 17

uncollectibles and the return on gas in storage. 18

Q. Do you believe that the commodity uncollectible 19

component and the return on gas in storage should be 20

included in the current delivery revenue price out? 21

A. No. The commodity uncollectible component and the 22

return on gas in storage components are estimates 23

based on a forecast of gas costs and then reconciled 24


19

annually. Since these components will fluctuate based 1

on actual gas costs, they should be excluded from 2

current revenues and expenses, so there will be no 3

impact on base delivery rates. 4

Q. Are the expenses associated with the commodity 5

uncollectibles and the return on gas in storage 6

components reflected in Staff’s methodology? 7

A. No and the Accounting Rates Panel reflected the 8

removal of those expenses. 9

Q. Do you believe that the other revenue component should 10

be included in the current delivery revenue price out? 11

A. No, because the Company will not bill firm customers 12

for the $378,026. 13

Q. Please explain the Panel’s Line 15 and Bath 14

transportation charge adjustments. 15

A. Since the Company omitted these revenues from its 16

price out, we increased the Company’s revenues by 17

$99,602 for Line 15 (collected through Hammondsport’s 18

DRA) and $34,739 for Bath’s transportation revenues 19

(collected through Hammondsport’s GAC). 20

Q. Please explain the Panel’s adjustment on the price out 21

of individually negotiated contracts. 22

A. We increased the priced out of individually negotiated 23

contracts by $91,151 compared to the Company’s 24


20

forecast. This difference can be attributed to 1

Staff’s sales forecast differences and the 2

Commission’s order in Case 09-G-0252 (issued May 19, 3

2011) regarding the treatment of Peak Resort’s 4

revenues. 5

Q. What did the Company estimate for Peak Resort’s 6

revenues in its price out? 7

A. The Company estimated $10,000 per month in its price 8

out. 9

Q. What amount did the Commission actually require 10

Corning to price out in this rate case filing? 11

A. The Commission required the Company to price out 12

$16,000 per month and we included the $16,000 per 13

month in our price out here. 14

Q. Please explain the Panel’s adjustment to plant write 15

downs. 16

A. The Commission required specific write downs on plant 17

in two areas; the Virgil franchise expansion and the 18

Root Pipeline/Compressor Station project. For the 19

Virgil franchise expansion, the Commission required an 20

accelerated write down of plant to minimize the cross-21

subsidization risk to core customers and instituted a 22

surcharge for Virgil customers over seven years. For 23

the Root Pipeline/Compressor Station project the local 24


21

production transportation revenues are required to be 1

applied against the asset until fully written off. 2

Q. Did the Panel adjust revenues for the Virgil 3

surcharges and revenues for transportation from the 4

Root Pipeline and Compressor Station project? 5

A. Yes, we increased the Company’s revenues by $61,999 6

based on the price out of our sales forecast and the 7

Staff Policy Panel’s forecast for Root Pipeline and 8

Compressor Station project revenues. 9

Q. Please explain the Panel’s adjustment to local 10

production access revenue. 11

A. The Staff Policy Panel provided us with an imputation 12

level of $545,284 for access revenue which we 13

reflected in our adjustment to rate year one revenues. 14

Rate Year Two 15

Q. What did the Company forecast for base delivery 16

revenue, local production revenue, accelerated plant 17

recovery and MFC revenue in rate year two at rate year 18

one rates? 19

A. The Company forecasted $13,694,198 for base revenue 20

and $765,486 for local production revenue, accelerated 21

plant recovery and MFC revenue. 22

Q. Did the Panel implement the same adjustments in rate 23

year two it used in rate year one, if so what were the 24


22

results? 1

A. We did have the same adjustments, except for RDM and 2

Line 15 transportation revenue (these revenues were 3

rolled into base rates in rate year one), for rate 4

year two. As shown in Exhibit ___(GRP-4), we forecast 5

rate year two base delivery revenues at rate year one 6

rates of $10,432,940. Our local production revenue, 7

accelerated plant recovery and MFC revenue is 8

$811,326. Our total delivery revenue forecast, 9

excluding gas costs is $11,924,337 which results in a 10

downward adjustment of rate year two revenues by 11

$2,535,347, excluding taxes. 12

Rate Year Three 13

Q. What did the Company forecast for base delivery 14

revenue, local production revenue, accelerated plant 15

recovery and MFC revenue in rate year three at rate 16

year two rates? 17

A. The Company forecasted $14,595,662 for base revenue 18

and forecasted $765,486 for local production revenue, 19

accelerated plant recovery and MFC revenue in rate 20

year three (Company Exhibit ___(CNG-3), Summary Page 2 21

of 4). 22

Q. Did the Panel implement the same adjustments in rate 23

year three it used in rate year two, if so what were 24


23

the results? 1

A. We did have the same adjustments for rate year three. 2

As shown in Exhibit ___(GRP-4 Corrected), we forecast 3

rate year three base delivery revenues at rate year 4

two rates of $11,103,775. Our local production 5

revenue, accelerated plant recovery, Bath Surcharge 6

and MFC revenue is $1,062,454. Our total delivery 7

revenue forecast, excluding gas costs is $12,891,454 8

which results in a downward adjustment of rate year 9

three revenues by $2,469,694, excluding taxes. 10

Other Revenues 11

Q. How did the Company forecast other revenues? 12

A. The Company used the test year as its forecast for 13

each of the rate years. This resulted in $3,800 and 14

$12,726 per rate year in reconnect charges and 15

surcharge revenues, respectively. 16

Q. Does the Panel agree? 17

A. No. 18

Q. What does the Panel forecast for other revenues in 19

each of the three rate years? 20

A. As shown in Exhibit ___(GRP-5), we recommend using a 21

three year average resulting in $4,313 and $13,807 for 22

reconnect charges and surcharge revenues, 23

respectively. 24


24

Q. Why does the Panel use a three year average? 1

A. The revenues resulting from reconnect charges and 2

surcharges are inherently hard to forecast due to the 3

fact that there are no patterns or trends. We believe 4

a three year average, as opposed to the Company’s test 5

year, better reflects what will occur in the rate 6

years. 7

Depreciation Rates 8

Q. Is the Company proposing any changes in regard to its 9

depreciation rates that were instituted in the last 10

rate case? 11

A. No, the Company did not propose any changes to its 12

depreciation rates. 13

Q. Is the Panel proposing any changes to the Company’s 14

depreciation rates? 15

A. Yes, we are proposing to increase the Average Service 16

Lives (ASLs) for account numbers 367, 376, and 380 to 17

be increased to 73, 73, and 55 years, respectively. 18

Q. How did the Panel derive the new ASLs for the 19

aforementioned accounts? 20

A. The ASLs were determined by averaging the ASLs of 21

other major utilities in New York State as shown in 22

Exhibit ___(GRP-6). 23

Q. Why did the Panel use an average in lieu of the 24


25

Company’s previous depreciation study? 1

A. The Company does not retire plant by specific location 2

as shown in the response to IR DPS-220. The survivor 3

curve, developed by the Company’s witness in the last 4

rate case, was derived using plant records that 5

specify retirements by vintage. The Company, however, 6

has recorded retirements and additions using a first 7

in first out method. The Company’s survival rate, 8

therefore, does not reflect the actual ASLs of its 9

plant accounts. In addition, because of the first in 10

first out accounting treatment, the Company’s rate 11

base may be overstated. We, therefore, recommend 12

using the average ASLs of our proxy group. 13

Amortization Period of the Depreciation over Accrual 14

Q. Did the Commission adopt, as part of a Joint Proposal 15

(JP), a depreciation over accrual amortization of 15 16

years in Case 08-G-1137 (issued August, 20 2008)? 17

A. Yes. 18

Q. Did the Company propose a change to the current 19

amortization of its depreciation over accrual? 20

A. No. 21

Q. Does the Panel recommend a change to the amortization 22

period? 23

A. Yes. We recommend a ten year amortization. 24


26

Q. Please explain why. 1

A. We believe reducing the amortization period to ten 2

years will help mitigate the intergenerational 3

inequities of a lengthy amortization period. Rates 4

should be set to ensure customers equally benefit and 5

equally share in the costs to provide service. A long 6

amortization period would result in future customers 7

benefiting from the over-recoveries of cost that the 8

current customers have to bear. Moreover, reducing 9

the amortization period can help accelerate the 10

recovery of potential over accrual of depreciation 11

reserves that may be understated as a result of how 12

the Company tracks its continued property records. In 13

addition, changing the amortization period for the 14

variance in the depreciation reserve from 15 to ten 15

years helps mitigate potential customer bill impacts 16

by lowering the Company’s annual depreciation expense. 17

Finally, the 15 year amortization adopted in the last 18

rate case was arrived at through negotiations and 19

ultimate settlement of an overall rate plan. 20

Historic Capital Expenditure Forecast 21

Q. Did you develop a comparison of New York State gas 22

utility historic capital expenditure budgets vs. their 23

operating revenues and net plant in service? 24


27

A. Yes as shown on Exhibit ___(GRP-7). 1

Q. Please explain how Corning’s capital budgets compare 2

to the other New York State gas utilities. 3

A. Corning’s capital budgets as a percentage of both 4

total operating revenue and net plant in service are 5

higher than most of the utilities. 6

Q. Do you have any concerns about the comparison? 7

A. We believe a greater focus should be placed on 8

Corning’s capital budgeting process to make sure 9

spending is cost justified. 10

Capital Expenditure Forecasts 11

Q. After Corning’s last rate proceeding (Case 08-G-1137), 12

what capital expenditure budget level did the Board of 13

Directors approve for 2010? 14

A. According to Exhibit ___(CNG-11)(FAQ-15), the Board of 15

Directors adopted a calendar year 2010 budget of 16

$5,417,875, which includes $1,831,083 for Lines 4 and 17

7 upgrades associated with its Compressor Station 18

project. 19

Q. What capital expenditure budget level did the Board of 20

Directors approve for 2011? 21

A. The Board of Directors adopted a calendar year 2011 22

budget of $4,602,338. 23

Q. Have the 2012, 2013, 2014 and 2015 capital expenditure 24


28

budgets presented by the Company been approved by the 1

Board of Directors? 2

A. No. 3

Q. Please summarize the Company’s capital construction 4

forecasts for 2012-2015. 5

A. The Company proposed a total capital budget of 6

$7,666,067 for 2012, $4,464,228 for 2013, $4,436,088 7

for 2014, and $4,311,239 for 2015. Corning’s budgets 8

for 2012-2015 are shown in Company Exhibit ___(CNG-8). 9

The Company presents its capital budget by 14 major 10

project categories. 11

Capital Expenditure Justification 12

Q. Please explain the documentation that supports 13

Corning’s capital spending plan. 14

A. The Company did not provide any supporting 15

documentation to justify its capital spending plan. 16

Q. Does the Company have policies and procedures in place 17

for initiating, developing and executing capital 18

projects? 19

A. No. The Company stated in response to IR DPS-229 that 20

it does not have written policies and procedures in 21

place for initiating, developing and executing capital 22

projects. 23


29

Q. Does the Company have a near-term and long-term 1

strategic plan? 2

A. No, the Company stated in response to IR DPS-228 that 3

it does not have a written near-term or long-term 4

strategic plan. 5

Q. Does the Company have a documented capital expenditure 6

project prioritization system? 7


it does not have a specific documented capital 9

expenditure project prioritization system. 10

Q. Does the Company have project management performance 11

measures in place? 12


it does not have specific project management 14

performance measures. 15

Q. Does the Company document changes to a project’s 16

initial budget? 17

A. No, according to the response to IR DPS-230 the 18

reasons for a budget change during planning, design, 19

or construction are not documented. 20

Q. Does the Company track and document any review or 21

authorization of projects where expenditures exceed 22

initial budget authorizations? 23


30

A. No, according to the response to IR DPS-233, there is 1

no documentation of project overruns other than what 2

is identified via monthly capital budget variance 3

reports. 4

Q. Does the Company track the time it takes to complete 5

operation and maintenance and capital work by its 6

outside contractors and internal workforce? 7


it does not have a formal reporting system that tracks 9

the time it takes to complete operation and 10

maintenance and capital work by its outside 11

contractors and internal workforce. 12

Q. Please explain why a strategic plan is important for 13

improving the Company’s budgeting process. 14

A. Near-term and long-term strategic plans are important 15

in the Company’s decision making process and in 16

allocating the necessary resources to pursue the 17

organization’s strategic goals. 18

Q. Why is it beneficial to create and document a capital 19

expenditure project prioritization process? 20

A. Capital projects should be evaluated regularly and 21

integrated into a multi-year financial plan, which is 22

driven by the Company’s strategic plan. 23


31

Q. Why are project management performance measures 1

important in the budgeting process? 2

A. Project management performance measures are useful in 3

determining the effectiveness of cost estimation and 4

scheduling. 5

Q. Please explain why procedures to review and authorize 6

projects when expenditures exceed initial budget 7

authorizations are important. 8

A. The Panel believes it is important to document any 9

changes to the Company’s initial capital expenditure 10

budget to improve the estimation process and control 11

costs. 12

Q. Please explain why tracking the time it takes to 13

complete operation and maintenance and capital work by 14

outside contractors and internal workforce is 15

important. 16

A. The Panel believes this information would be 17

beneficial in determining whether in-house labor or 18

contract labor would be more cost efficient for a 19

specific project. 20

Capital Expenditure Project Estimation 21

Q. With regard to project estimation, why is accuracy on 22

the part of Corning important? 23


32

A. We believe the capability for Corning to consistently 1

produce accurate project estimates is important for 2

several reasons: (1) accurate project estimation has a 3

direct impact on the validity of cost-benefit 4

evaluations and the correctness of planning decisions; 5

(2) accurate project estimation of several alternative 6

projects being considered results in a greater 7

tendency of an alternative being correctly chosen or 8

correctly rejected; (3) accurate project estimation is 9

more likely to strengthen the incentive and ability to 10

develop and design more innovative, lower cost 11

alternatives and/or components within alternatives due 12

to an increased confidence in scope, cost and schedule 13

relationships including the ability to decide to defer 14

a project to continue to seek better alternatives; (4) 15

accurate project estimation is more likely to instill 16

discipline in the cost control and project management 17

process; and, (5) accurate project estimation will 18

provide a check and balance for projects that are bid 19

out for contract, particularly if performance 20

incentives are included. 21

Q. How would the Panel define “accurate project 22

estimation?” 23


33

A. We believe an accurate project estimate needs to 1

encourage efficiency by providing a reasonable and 2

realistic estimate of the resource requirements of a 3

project considering the inter-relationships between 4

project scope, cost and schedule as well as project 5

constraints and circumstances. In this respect, we 6

believe project estimation should be developed through 7

defined and refined work scopes, through benchmarking, 8

and through experience gained through competitively 9

bid projects. Ideally, an estimate would be slightly 10

low, but realistic, to encourage innovation and 11

discipline. Importantly, if an estimate is 12

unreasonably high, it will encourage unnecessary scope 13

expansion, cost over-runs and/or schedule over-runs. 14

Similarly, if an estimate is unreasonably low, it may 15

be ignored as a credible limit, and thus also 16

encourages over-runs. The need for reasonable and 17

realistic estimates is most important during the 18

planning and decision making approval stage of a 19

project, and again at project construction initiation 20

to facilitate project management and cost control. 21

Admittedly, the ability to produce a more accurate 22

estimate improves as the project progresses; but 23

unfortunately, a more accurate estimate near the 24


34

completion date of a project is much less useful from 1

a project management perspective. 2

Q. What are the Panel’s concerns with Corning’s project 3

estimation process? 4

A. We are concerned that Corning has no written record of 5

project estimations and justifications. Poor cost 6

estimating and project management could have adverse 7

effects on its ability to execute its planned capital 8

expenditures in a cost effective manner. 9

Recommendations for Capital Expenditure Justification and 10

Project Estimation 11

Q. Please explain why written justifications should be 12

required for capital expenditure projects. 13

A. The Panel believes justifications are necessary in 14

order to estimate the monetary requirements needed to 15

meet the proposed project goals and objectives and to 16

better implement cost control. We also believe 17

project justification will assist the Company in 18

prioritizing work and improve its strategic planning. 19

Q. What are the Panel’s recommendations for improving 20

project justification? 21

A. The Panel recommends the Company develop a project 22

justification sheet for all capital expenditure 23

projects. 24


35

Q. What issues should be addressed in the project 1

justification sheet? 2

A. A description of the project, project analysis, 3

estimated costs, resources needed, operational impact 4

on the system, project risks, important project 5

milestones, customer impact and a summary of the 6

project benefits, options and recommendations. 7

Q. Did the Panel develop a template that Corning could 8

follow? 9

A. Yes, as shown in Exhibit ___(GRP-8). 10

Q. Do you recommend that the Commission require Corning 11

to complete a justification worksheet for each 12

project? 13

A. Yes. 14

Q. What are your recommendations regarding Corning’s 15

project estimation process? 16

A. We have the following recommendations Corning should: 17

(1) develop and document work scopes and investigate 18

site specific circumstances for projects with the dual 19

objectives of: (a) developing reasonable and realistic 20

estimates and (b) seeking and developing additional 21

alternatives that are more cost effective; (2) develop 22

and document definitive explanations for cost over-23

runs with the intent of identifying root causes of 24


36

over-runs and ways to remediate these causes; (3) use 1

and document benchmarking and competitive bidding to 2

help make its project resource estimates more 3

reasonable and realistic; (4) develop documented 4

policies, procedures and strategic plans; (5) create 5

and document a capital expenditure project 6

prioritization system; (6) develop and document 7

project management performance measures; (7) define 8

and document deliverables for each project; (8) 9

develop documented procedures to review and authorize 10

projects when expenditures exceed initial budget 11

authorizations; and, (9) track and document the time 12

it takes to complete operation and maintenance and 13

capital work by its outside contractors and internal 14

workforce. 15

Q. When should the Company develop your recommendations? 16

A. The Company should be required to fully implement our 17

recommendations beginning January 1, 2013. 18

Capital Expenditure Variance Reports 19

Q. Does the Commission believe that variance reports are 20

an important management tool to be used internally to 21

measure the Company’s performance? 22

A. Yes. The Commission stated in Case 07-G-0772 (issued 23

December 13, 2007) that such a tool is important and 24


37

that Corning should adopt it. Without a variance 1

reporting system, attempts to compare previous budgets 2

with actual performance cannot be done. 3

Q. Was Corning required to develop monthly variance 4

reports in Case 08-G-1137 (issued August 20, 2009)? 5

A. Yes. 6

Q. When were they started? 7

A. Corning began monthly variance reports in January 8

2011. 9

Q. Since Corning just developed monthly variance reports 10

in 2011, can you determine Corning’s budgeting 11

performance? 12

A. No. Since there is not a complete year of monthly 13

variance reporting, we do not know how well Corning 14

forecasted its capital budgets or if projects will 15

slide to future dates based on past performance. 16

Q. How did the Panel review the Company’s budget? 17

A. We reviewed the 2011 variance reports, compared the 18

annual budgets to actual annual spending, analyzed the 19

budget line-by-line and reviewed the Company’s IR 20

responses. 21


38

Capital Expenditures Overview 1

Q. Please summarize the capital expenditure adjustments 2

the Panel provided to the Staff Accounting Rates 3

Panel. 4

A. We are recommending adjustments that in total reduce 5

Corning’s rate year one average net plant in service 6

by $2.8 million and reduce its annual rate year one 7

depreciation expense by $85,342, reduce rate year two 8

average net plant in service by $1.9 million and 9

reduce its annual rate year two depreciation expense 10

by $119,051 and reduce rate year three average net 11

plant in service by $1.5 million and reduce its annual 12

rate year three depreciation expense by $165,936 13

(Exhibit ___(GRP-11 Corrected) and Exhibit ___(GRP-12 14

Corrected)). 15

Q. What is the purpose of reviewing the Company’s capital 16

budgets in this proceeding? 17

A. The intent of reviewing the Company’s capital 18

expenditure budgets is to recommend an overall level 19

of capital expenditures to be used in setting rates 20

for the rate years. It is our position that the 21

Company should spend at the levels it deems 22

appropriate to provide safe and adequate service. We 23

are, however, recommending adjustments to the amount 24


39

of plant forecasted to be added to the Company’s plant 1

in service balances during the rate years. These 2

adjustments reflect the level of capital additions we 3

believe the Company has justified in its initial rate 4

filing and during the discovery phase of the 5

proceeding and, thus, the level of plant in service 6

that is most appropriate for the Commission to use in 7

setting delivery rates. 8

Q. If the Company completes projects that it deems 9

appropriate to provide safe and adequate service at 10

higher spending levels than forecasted in the rate 11

years, will customers be exposed to a surcharge? 12

A. No. The rates customers pay will be set in accordance 13

with the level of forecasted net plant that the 14

Commission adopts in this proceeding as well as other 15

cost of service items. If the Company adds plant at 16

levels in excess of the forecasted levels, we are 17

recommending no provision for automatically adjusting 18

rates upward to recognize that increase. Conversely, 19

however, if the Company adds plant at levels less than 20

that forecasted, we are recommending that the Company 21

credit customers the associated revenue requirement 22

impact of the shortfall as compared to the forecasted 23

levels. 24


40

Proposed Capital Expenditure Adjustments 1

Q. Please describe the project areas where the Panel is 2

recommending specific adjustments to the Company’s 3

capital expenditure budget forecasts in 2011, 2012, 4

2013, 2014, and 2015. 5

A. We are proposing project category adjustments and 6

specific line item adjustments to the Company’s 2011, 7

2012, 2013, 2014, and 2015 capital expenditure budget 8

forecasts in the following areas: (1) meters and 9

regulators under Company project category 2; (2) new 10

main installations under Company project category 3; 11

(3) Bath Reliability – Second Supply, Line 15 12

Systematic Replacement Program, Line 6 Systematic 13

Replacement Program and Main – high pressure 14

distribution under Company project category 4; (4) 15

transportation equipment under Company project 16

category 9; (5) tools and equipment under Company 17

project category 10; (6) heating, ventilation and air 18

conditioning (HVAC) and parking lot refurbishment and 19

general office under Company project category 12; (7) 20

accounting and billing system upgrade and AS400 21

equipment/software/licensing costs under Company 22

project category 13; and, (8) Virgil expansion – main 23

and services under Company project category 14. 24


41

Q. Please summarize your adjustments by calendar year. 1

A. The Panel proposes a reduction in the capital 2

expenditure budgets of $832,500 in 2011, a reduction 3

of $4,266,704 in 2012 forecast, an increase of 4

$2,568,181 in 2013 forecast, a decrease of $867,158 in 5

2014 forecast and a decrease of $668,998 in 2015 6

forecast. The Company’s budgets for 2011 through 7

2015, along with our adjusted budgets, are shown in 8

Exhibit ___(GRP-9 Corrected). 9

Meters and Regulators 10

Q. Please describe your adjustments to project 2.1. 11

A. The Company forecasted 500 residential regulator 12

replacements for 2012-2015. In its response to IR 13

DPS-171 the Company replaced 410 in 2008, 430 in 2009, 14

and 380 in 2010. Based on these historic replacement 15

numbers, we believe 430 regulators is a more 16

reasonable target and we adjusted the Company’s 17

capital expenditures down by $2,853 in 2012, $2,920 in 18

2013, $2,971 in 2014 and $3,037 in 2015. 19


A. The Company forecasted $649 per non-residential 21

regulator unit in 2012. Based on the Company’s 22

response to IR DPS-172, the average cost of a non-23

residential regulator purchased by the Company from 24


42

2008-2010 was $384. Therefore, we believe $384 is a 1

reasonable cost for non-residential regulator 2

replacements and we adjusted the Company’s capital 3

expenditures down by $2,645 in 2012, $2,775 in 2013, 4

$2,914 in 2014 and $3,062 in 2015. 5


A. The Company forecasted 1,000 residential meter 7

replacements annually in 2012, 2013, 2014 and 2015. 8

We asked Corning how many meters it replaced 9

historically and the number that is required to be 10

replaced per its approved meter replacement program. 11

The Company’s response to IR DPS-159 stated that it 12

actually replaced 500 residential meters in 2008, 550 13

residential meters in 2009, and 925 residential meters 14

in 2010, and that it is required to replace 15

approximately 900 meters per year. We, therefore, 16

believe the actual number should be 925 residential 17

meter replacements in 2012, 2013, 2014 and 2015, based 18

on the Company’s recent performance and required 19

replacement level. We adjusted down the Company’s 20

capital expenditures by $5,350 in 2012, $5,457 2013, 21

$5,571 in 2014 and $5,694 in 2015. 22

New Main Installations 23

Q. Please describe your adjustments to Company project 3. 24


43

A. The Company has provided no justification for project 1

category 3.1, new installations. The Panel could not 2

justify the dollars associated with this project and, 3

therefore, adjusts the Company’s capital expenditures 4

down by $75,000 in 2012, $120,000 in 2013, $125,000 in 5

2014 and $130,000 in 2015. 6

Main – High Pressure Distribution 7

Q. Did the Commission require Corning to develop a long- 8

term plan to address Line 15 reliability? 9

A. In Case 08-G-1137 (issued April 20, 2011), the 10

Commission ordered Corning to address Line 15 11

reliability in its next filed base delivery rate case, 12

as well as develop a long-term plan to replace Line 13

15. The Commission required Corning to enter into a 14

contract with Bath prior to commencing construction. 15

Q. Did Corning propose a reliability project for Line 15? 16

A. Yes. The Company proposed to meet the Commission’s 17

mandate over a three year period from 2011 to 2013. 18

The plan includes replacing a portion of the existing 19

Line 15 and constructing approximately four miles of 20

pipe and stations required to interconnect Line 15 to 21

the Inergy owned Thomas Corners storage field 22

facility. 23

Q. Did Corning include capital expenditures in its rate 24


44

filing to address the Commission’s requirements? 1

A. Yes. The Company proposed the following projects: 2

Bath Reliability – Second Supply (project 4.3) and 3

Line 15 Systematic Replacement Program (project 4.4). 4

Q. Please describe project 4.3, Bath Reliability – Second 5

Supply. 6

A. In 2011 and 2012, the Company proposed capital 7

expenditures associated with Line 15 improvements. 8

Corning plans to install a new pipeline from Inergy 9

Storage in the Town of Bath to interconnect with the 10

existing Line 15. The total expenditure for this 11

project is estimated to be $4,550,000. 12

Q. How is the Bath Reliability – Second Supply project 13

related to the Line 15 Systematic Replacement Program? 14

A. After the completion of the Bath Second Supply project 15

in 2012, the Company plans to begin systematic 16

replacement of the entire existing Line 15 beginning 17

in 2013. 18

Q. Does a contract between Corning and Bath affect the 19

timeline of the Inergy interconnect construction 20

scheduled for 2012? 21

A. Yes, the Company stated, in its response to IR DPS-22

163, that it must have a signed contract agreement 23

with Bath by September 1, 2011, in order to complete 24


45

the Inergy interconnect by September/October 2012 time 1

frame. 2

Q. Did Corning and Bath enter into a long-term contract 3

as of September 1, 2011? 4

A. No. 5

Q. Did Corning take any action regarding the lack of an 6

executed contract? 7

A. Yes. It filed a letter with the Commission on 8

September 8, 2011 that requested an extension of time 9

to complete the project. 10

Q. What impact does this have on the timing of the Bath 11

Reliability – Second Supply project? 12

A. The Company estimates that design, layout, permitting, 13

and Public Service Law (PSL) Article 7 submittal and 14

approval will require approximately eight months to 15

complete and construction will require another three 16

to four months. Therefore, the Panel believes 17

construction will likely occur in 2013. 18

Q. Please describe the Line 15 Systematic Replacement 19

Program for 2014 and beyond. 20

A. Corning proposes to replace approximately one mile of 21

Line 15 per year from 2014 to 2026. Each one mile 22

replacement from 2014 to completion will require 23

approximately three months for design, layout and 24


46

permitting and one month for construction. 1

Q. Please describe the Panel’s adjustment to the Line 15 2

Systematic Replacement Program. 3

A. We propose to shift costs associated with the Line 15 4

Systematic Replacement Program in 2013 to 2012, to 5

account for the delay of the Bath Reliability – Second 6

Supply project. Therefore, our adjustment is an 7

increase of $750,000 in 2012 and a decrease of 8

$750,000 in 2013. 9

Q. Please describe the Line 6 Systematic Replacement 10

Program. 11

A. The Company proposes to systematically replace 12

approximately 3/4 mile of Line 6 per year until 13

complete. The repair costs for Line 6 amounts to 14

approximately $1.6 million over three years (2013-15

2015). 16

Q. Please describe your adjustment to the Line 6 17

Systematic Replacement Program. 18

A. Beginning in 2013, the Company proposed to begin a 19

replacement program for Line 6. The Company stated 20

that both Line 15 and Line 6 are required to maintain 21

system reliability. As described above, the Line 15 22

Replacement Program is scheduled to be completed over 23

a thirteen year time frame. We believe this is a 24


47

reasonable time frame and propose that Line 6 should 1

be replaced on a similar thirteen year time frame. 2

Line 6 consists of approximately six miles of pipe, 3

which results in replacing about a half mile of pipe 4

per year. We also believe this project can commence 5

in 2012 to offset the slipping of the Bath Reliability 6

– Second Supply project. Therefore, our adjustment is 7

an increase of $350,000 in 2012, a decrease of 8

$500,000 in 2013, a decrease of $175,000 in 2014 and a 9

decrease of $201,250 in 2015. 10

Transportation Equipment 11

Q. Please describe your adjustments to Company major 12

project category 9. 13

A. The Company forecasted $183,052 in 2012, $184,190 in 14

2013, $235,958 in 2014, and $187,849 in 2015. Based 15

on Company Exhibit ___(CNG-11)(FAQ-16), the historic 16

three year average spending for transportation 17

equipment was $79,750, as shown in Exhibit ___(GRP-18

10). The Panel believes this as a more reasonable 19

budget as it is more consistent with historic 20

spending. Therefore, our adjustment to the Company’s 21

capital expenditures is a $103,296 reduction in 2012, 22

a $104,440 reduction in 2013, a $156,208 reduction in 23

2014 and a $108,099 reduction in 2015. 24


48

Tools and Equipment 1

Q. Please describe your adjustments to Company major 2

project category 10. 3

A. The Company forecasted $75,644 in 2012, $57,580 in 4

2013, $54,063 in 2014, and $52,781 in 2015. Based on 5

Company Exhibit ___(CNG-11)(FAQ-16), the historic 6

three year average spending for tools and equipment is 7

$50,643, as shown in Exhibit ___(GRP-10). The Panel 8

believes this as a more reasonable budget as it is 9

more consistent with historic spending. Therefore, 10

our adjustment to the Company’s capital expenditures 11

is a $25,000 reduction in 2012, a $7,207 reduction in 12

2013, a $3,420 reduction in 2014 and a $2,138 13

reduction in 2015. 14

General Office 15

Q. Did the Company include HVAC equipment in its capital 16

budget in Cases 05-G-1359, 07-G-0772 and 08-G-1137? 17

A. Yes. 18

Q. Did the Company spend the budgeted dollars in these 19

previous rate cases on a new HVAC system? 20

A. No, therefore, we do not believe any spending is 21

likely to occur in the rate years. 22

Q. Please describe your adjustments to project 12.1 HVAC. 23

A. We reduced the Company’s capital expenditures for 24


49

project 12.1 by $90,000 in 2011, $50,000 in 2012 and 1

$50,000 in 2013. 2

Q. Did the Company include parking lot refurbishment in 3

its capital budgets in Cases 05-G-1359, 07-G-0772 and 4

08-G-1137? 5

A. Yes. 6


previous cases on parking lot refurbishment? 8

A. No, therefore, we do not believe any spending is 9

likely to occur in the rate years. 10


A. We reduced the Company’s capital expenditures down by 12

$35,000 in 2012, $35,000 in 2013 and $35,000 in 2014. 13

IT Equipment 14

Q. Did the Company include a new billing system in its 15

capital budgets in Cases 05-G-1359, 07-G-0772 and 08-16

G-1137? 17

A. Yes. 18

Q. In Case 08-G-1137, did Corning agree to expeditiously 19

purchase or lease and install a new billing system to 20

replace the Company’s current system? 21

A. Yes. 22


previous cases on a new billing system? 24


50

A. No as stated in response to IR DPS-21. 1

Q. Has the Company developed a Request for Proposal for a 2

new billing system? 3

A. No and, therefore, we do not believe any spending will 4

occur in the rate years. 5

Q. Please describe your adjustments to project 13.7, IT 6

equipment. 7

A. We reduced the Company’s capital expenditures by 8

$350,000 in 2011, $350,000 in 2012, $150,000 in 2013 9

and $150,000 in 2014. 10

Q. Please describe your adjustments to project 13.9, 11

AS400 Equipment, Software, and Licensing Costs. 12

A. In response to IR DPS-154, the Company provided its 13

2011 variance reports to date. As of May 2011 no 14

money has been spent on project 13.9. Therefore, we 15

do not believe the Company will spend the budgeted 16

dollars on this project in the rate years and we have 17

adjusted the Company’s capital expenditures down by 18

$60,000 in 2011. 19

Virgil Franchise Expansion 20

Q. Please describe your adjustment to project 14.1, 21

Virgil expansion mains and services. 22

A. Pursuant to the Staff Policy Panel’s testimony, the 23

expenses associated with this project were removed and 24


51

this adjustment is reflected in our proposed capital 1

expenditures budget. Therefore, we reduced the 2

Company’s capital expenditures forecast by $340,000 in 3

2011 and $150,000 in 2012. 4

Line 13 Plant Adjustment 5

Q. Please provide background on the Line 13 project. 6

A. In 2008, Corning constructed approximately two miles 7

of 10-inch steel pipeline (Root Pipeline or Line 13) 8

from a point in Pennsylvania approximately 75 feet 9

south of the New York State border to the Company's 10

existing distribution system in the Town of Caton. 11

The purpose of the pipeline was to provide 12

transportation service to a local producer's well, in 13

Pennsylvania. It was acknowledged in the JP adopted 14

in Case 08-G-1137, that the owner of the Root Well 15

would give Corning approximately $649,000 of pipe for 16

use in the construction of Line 13. 17

Q. Was any adjustment made to plant for the Line 13 18

Project? 19

A. Yes, in Case 08-G-1137, a contribution in aid of 20

construction (CIAC) was booked to plant Account 376. 21

Corning installed new gas main from its existing 22

facilities to the Pennsylvania border for Line 13 and 23

the pipe was provided by the owner of the Root Well. 24


52

Q. In the current filing, did the Company remove the Line 1

13 CIAC from rate base? 2

A. Yes it did and we also reflected this in our model. 3

Service Extension Adjustment 4

Q. Does the Panel recommend an adjustment to plant 5

Account 380 (Services Extensions)? 6

A. Yes. 7

Q. Please describe your adjustment. 8

A. The Staff Policy Panel decreased the plant in service 9

balance by $29,786 because the Company has not charged 10

customers for excess footage of service installations. 11

Gas Plant in Service 12

Q. Based on the recommended changes to the capital budget 13

and depreciation rates, did the Panel develop the net 14

plant in service for each of the rate years? 15

A. Yes we did. 16

Q. Can you generally describe how the gross plant balance 17

was determined? 18

A. We categorized the capital expenditures by plant 19

account number. The expenditures were then allocated 20

by month using Corning’s historic expenditure 21

experience. We assumed that non-interest bearing 22

construction work in progress was held constant; 23

therefore, expenditures are equal to additions. A 24


53

retirement percentage was developed using a historic 1

relationship with actual additions and retirements and 2

then we applied it to the forecast additions by month. 3

Beginning with the plant balances at the end of June 4

2011, with the adjustment to Account 380 services, we 5

forecasted the level of gross plant in service for the 6

rate years by adjusting for monthly additions and 7

retirements. Exhibit ___(GRP-11 Corrected) shows the 8

results of our projection. 9

Q. Please explain how the Virgil and Root 10

Pipeline/Compressor Station project write downs were 11

reflected in the Panel’s plant roll forward. 12

A. The write downs associated with the Virgil franchise 13

expansion and Root Pipeline/Compressor Station project 14

were deducted from plant in service on a monthly basis 15

because of the surcharge and plant write down 16

mechanisms. 17

Q. Can you generally describe how the depreciation 18

reserve balance was determined? 19

A. We applied the current depreciation accrual rates to 20

the forecast plant balances until the beginning of the 21

rate year and then applied our proposed accrual rates 22

to the monthly rate year plant balances to determine 23

the depreciation expense by month. Starting with the 24


54

depreciation reserve balance as of June 2011 we added 1

the monthly depreciation expense and then subtracted 2

retirements. 3

Q. How did you reflect the excess reserve amortization? 4

A. From June 2011 until April 2012 we reduced the monthly 5

reserve balance by $12,635 which reflects the 6

amortization at 15 years. Beginning May 2012, we 7

reduced the monthly reserve balance by $15,373 which 8

was based on our proposed ten year amortization of the 9

remaining over accrual, as shown in Exhibit ___(GRP-12 10

Corrected). 11

Q. Please indicate your adjustment to net plant in 12

service? 13

A. Exhibit ___(GRP-11 Corrected) shows our adjustment to 14

net plant as a reduction of $2.8 million in rate year 15

one, a reduction of $1.9 million in rate year two and 16

a reduction of $1.5 million in rate year three. 17

Net Plant True-Up Mechanism 18

Q. Did the Commission develop a one-way capital budget 19

true-up mechanism in Case 08-G-1137? 20

A. Yes. If Corning failed to spend the total level of 21

dollars as indicated by the Commission in the rate 22

year, 12 months ended August 31, 2010, it was to defer 23

a credit to customers equal to the difference 24


55

multiplied by the pre-tax rate of return. 1

Q. Did Corning meet its capital expenditure target for 2

the twelve months ended August 31, 2010? 3

A. Yes. 4

Q. Do you recommend that the true-up mechanism continue? 5

A. Yes, with some modifications. We recommend a net 6

plant true-up mechanism instead of a capital 7

expenditure true-up mechanism. This will simplify the 8

true-up mechanism, and is also more consistent with 9

the net plant true-up mechanisms established for other 10

utilities in the State. We recommend that the amount 11

authorized by the Commission for Corning’s net plant 12

targets be compared to the actual average net plant 13

during the rate years. If actual expenditures fall 14

short of the Commission approved amount, the Company 15

should defer for ratepayer benefit, the amount of the 16

revenue requirement effect due to any shortfall 17

multiplied by the authorized pre-tax rate of return, 18

as well as, the related depreciation expense 19

allowance. This deferral will be subject to carrying 20

charges calculated at the authorized pre-tax rate of 21

return. 22

Q. Why is this deferral mechanism needed? 23

A. This is needed to protect ratepayers if the forecasted 24


56

capital programs slip, are cancelled or if the actual 1

expenditures and additions lead to an average net 2

plant balance that is less than forecasted. 3

Q. What are your recommended net plant targets? 4

A. The Panel’s recommended net plant targets are $34.6 5

million in rate year one, $39.2 million in rate year 6

two, and $42.6 million in rate year three (Exhibit 7

___(GRP-11 Corrected)). 8

Tariff Changes 9

Tariff Consolidation 10

Q. Did the Company propose to consolidate Hammondsport 11

tariffs into Corning’s tariffs? 12

A. Yes. 13


A. Yes. However, we also recommend further consolidation 15

of Corning’s Bath tariff so that the Company would 16

only have one tariff for all of its customers. Our 17

recommended consolidated tariff is shown in Exhibit 18

___(GRP-13). 19

Q. Are there other reasons why tariff consolidation is 20

recommended? 21

A Currently, the Company has three different tariffs to 22

serve three different franchise areas: Corning, Bath, 23

and Hammondsport. This is redundant and inefficient 24


57

because similar customers are served in many SCs 1

instead of just one SC. The consolidation of the 2

three tariffs would reduce paperwork and improve the 3

efficiency of the Department and the Company by 4

grouping all similar customers paying similar rates 5

under one tariff. 6

Q. Are there potential bill impacts associated with this 7

consolidation? 8

A Yes, since similar customers from different service 9

areas are paying different rates, consolidating these 10

customers under one tariff will affect their rates. 11

Bill impacts should be carefully considered when 12

designing final rates. 13

Q. How would tariff consolidation affect other aspects of 14

this rate filing? 15

A. If the Commission adopts our proposal to consolidate 16

the Company’s tariffs, this would affect the Company’s 17

COS studies, the MFC and the current LAUF factors. 18

Bath Revenue True-up Adjustment 19

Q. Are Bath’s revenues currently reconciled annually? 20

A. Yes. Corning’s tariff has a target level of revenues 21

and any imbalances are surcharged or refunded through 22

the DRA to all firm customers. 23


58

Q. Did the Company propose any changes to the current 1

Bath revenue reconciliation? 2

A. The Company proposed to eliminate the Bath revenue 3

reconciliation altogether. 4

Q. Does the Panel agree with the Company’s proposal? 5

A. Yes. 6

Lost and Unaccounted For Gas Factors 7

Q. What LAUF factors are the Company proposing? 8

A. The Company proposed factors of 1.0176, 1.000, and 9

1.005 for Corning, Bath and Hammondsport, 10

respectively. The Company is also proposing a LAUF 11

factor of 1.0173 for Corning and Hammondsport if its 12

tariff consolidation proposal is adopted. 13

Q. What is the Panel proposing? 14

A. Since we propose tariff consolidation for Corning’s 15

three service areas, we recommend one system wide LAUF 16

factor set at 1.0080 using a three year average, as 17

shown in Exhibit ___(GRP-14). 18

Q. Why does the Panel propose using a three year average? 19

A. A three year average is more reflective of the current 20

condition of the Company’s distribution system since 21

Corning has been aggressively replacing older 22

pipelines in recent years. 23


59

Q. Please describe how the current LAUF incentive 1

mechanism operates? 2

A. The LAUF incentive mechanism currently provides an 3

incentive for the Company if its actual LAUF factor is 4

below the fixed LAUF factor and a disincentive if the 5

actual LAUF factor is above the fixed LAUF factor. 6

Q. Did Staff of the Department conduct a study regarding 7

the LAUF incentive mechanism? 8

A. Yes. Staff of the Department conducted an internal 9

study regarding the LAUF incentive mechanism and 10

developed several recommendations, as shown in Exhibit 11

___(GRP-15). 12

Q. Please describe the recommendations. 13

A. Generally, a dead band should be developed around the 14

fixed LAUF factor and all firm customers will be 15

charged for the differences between the fixed LAUF 16

factor and the actual LAUF factor within the dead 17

band. 18

Q. Why does the Panel recommend the Company adopt these 19

changes? 20

A. The LAUF incentive was initially designed to provide 21

the Company with an incentive to improve the 22

efficiency and the performance of the pipeline system. 23

The efficiency increases as gas losses are reduced 24


60

when older pipes are replaced with newer pipes. There 1

is a point at which the system reaches its equilibrium 2

and further reduction in lost gas is minimal and not 3

easily measured. Further, as discussed in the 4

internal study, charging only firm sales customers for 5

the differences in LAUF is inequitable. 6

Q. Please describe the development of the dead band. 7

A. We propose a dead band around the fixed LAUF factor 8

where the Company would no longer have an incentive or 9

disincentive. The dead band will be equal to two 10

standard deviations as determined from the previous 11

three years of actual system-wide LAUF factors. 12

However, the maximum standard deviation should be 13

limited to 0.5% with a lower LAUF limit of 1.000 for 14

the dead band. If the bottom of the dead band is at 15

the 1.0000 limit, the top of the dead-band will be set 16

at one plus four standard deviations. For the system-17

wide Corning LAUF factor, our calculated minimum of 18

the dead band is below the 1.0000 limit, so the 19

minimum of the dead band is set at 1.0000 and, 20

therefore, the maximum of the dead band is set at four 21

standard deviations to 1.0195. 22

Q. Does Exhibit ___(GRP-15) shows how all firm customers 23

will be charged for differences in LAUF? 24


61

A. Yes. 1

Cost of Service Study 2

Q. Did the Company file a COS study in this proceeding? 3

A. Yes. The Company filed two COS studies: a 4

Jurisdictional and a Class Accounting COS study based 5

on the historical 12 month period ended December 31, 6

2010, as shown in the Company’s Exhibit ___(CNG-10), 7

Schedule PMN-4 and PMN-7 (original COS study) and the 8

Revised Jurisdictional and Class Accounting COS study 9

with Line 15 and Reliability Additions, shown in 10

Company Exhibit ___(CNG-10), Schedule PMN-6 (revised 11

COS study). 12

Q. Please briefly explain how the original COS study was 13

performed? 14

A. The Company’s original COS study is a cost matrix 15

based on the historic test year ended December 31, 16

2010. The Company’s customer sales and revenues data 17

per books were adjusted for variations in weather. 18

Each element of rate base, revenue and operating 19

expenses were assigned or allocated to the Company’s 20

three jurisdictions, Corning, Hammondsport and Bath 21

and further to each of the jurisdictions’ SCs. The 22

Company determined the use of specific plant 23

investments and then allocated these assets in the 24


62

test year. External and internal allocators were 1

developed separately to assign the various costs to 2

each jurisdiction and SC. The original COS study 3

resulted in a total Company Rate of Return (ROR) of 4

7.30%, of which Corning’s ROR was 6.85%, Bath’s ROR 5

was 19.39% and Hammondsport’s ROR was 9.45%. The 6

revised COS study with Line 15 and Reliability 7

Additions, resulted in a total Company ROR of 6.09%, 8

Corning’s ROR of 6.08%, Bath’s ROR of 6.40% and 9

Hammondsport’s ROR of 5.81%. 10

Q. How did the Company allocate mains and services, and 11

their associated expenses to each jurisdiction and SC? 12

A. The Company allocated transmission mains (Account 367) 13

to Corning based on book costs. The remaining balance 14

was allocated to Bath and Hammondsport based on design 15

day usage. Within each jurisdiction, transmission 16

mains and their associated expenses were allocated to 17

each SC by design day usage. Both distribution mains 18

and services and associated expenses were allocated to 19

each jurisdiction solely based on book values. 20

Distribution mains were further allocated to each SC 21

by design day usage, while services were allocated to 22

each SC by customers. 23

Q. How did the Company allocate costs for the Bath 24


63

Reliability Project? 1

A. Corning separated the total costs into three 2

components: “System Supply Addition Storage,” “Bath 3

Reliability Addition Storage” and “Line 15 4

Improvements.” “Bath Reliability Addition Storage” 5

and “Line 15 Improvements” were allocated strictly to 6

Bath and Hammondsport based on design day usage. 7

“System Supply Addition Storage” was allocated to all 8

jurisdictions proportional to their usage during the 9

three winter months. 10

Q. Why is “System Supply Addition Storage” treated 11

differently than the other two components? 12

A. The “Bath Reliability Addition Storage” and “Line 15 13

Improvements” are the components of the Bath 14

Reliability Project that the Company considered 15

reliability related for Bath and Hammondsport. The 16

Corning service area does not physically use any gas 17

transported through this system, thus, the Company 18

claims Corning’s service area should not bear any 19

costs for upgrading or maintaining this system. 20

Q. Does the Panel believe the method in which the Company 21

allocated the Bath Reliability Project is reasonable? 22

A. No, since we advocate for tariff consolidation, the 23

Company’s methodology of allocating the Bath 24


64

Reliability project is inconsistent with our proposed 1

tariff consolidation. If the tariffs are 2

consolidated, we recommend allocating all components 3

of the Bath Reliability project equally to all SCs 4

within Bath, Hammondsport, and Corning by design day 5

usage. We asked the Company to run the revised COS 6

study in this manner. The adjusted COS study was 7

provided in response to IR DPS-227. The ROR results 8

reported in the response to IR DPS-227 are 6.02%, 9

10.52%, and 26.71% for Corning, Bath, and 10

Hammondsport, respectively. The Company wide ROR 11

remains at 6.91%. 12

Q. If the Commission rejects your tariff consolidation 13

proposal, which COS study should the Commission rely 14

on for revenue allocation and rate design purposes? 15

A. If the Commission rejects tariff consolidation, we 16

recommend allocating the total supply storage costs 17

which consists of the “System Supply Addition Storage” 18

and “Bath Reliability Addition Storage” components to 19

Corning based on a two-step process. 20

Q. Please explain. 21

A. We asked the Company what portion of the Bath 22

Reliability Project was used for system supply 23

purposes. In response to IR DPS-57, the Company 24


65

stated that the Inergy storage asset was 9.05% of its 1

total supply portfolio. We, therefore, believe that 2

9% of the Bath Reliability Project should be 3

considered system upgrades and the remainder should be 4

considered reliability and allocated strictly to Bath 5

and Hammondsport. 6

Q. Did you ask the Company to run the revised COS study 7

in this manner? 8

A. Yes. We asked the Company to rerun the revised COS 9

study incorporating the two step allocation 10

methodology. The results were provided in response to 11

IR DPS-227. The resulting system wide ROR for the 12

Company is 6.91% and the corresponding RORs for 13

Corning, Bath and Hammondsport are 6.63%, 4.46% and 14

15.56%, respectively. 15

Revenue Allocation 16

Q. Please describe Corning’s overall revenue allocation 17

methodology? 18

A. Corning allocated its proposed total levelized 19

increase in base rates of approximately $1.4 million 20

for rate year one as shown on Company Exhibit ___(CNG-21

10), Schedule PMN-5, by first assigning this increase 22

to the firm SCs based on each SC’s contribution to 23

base delivery rates in rate year one at current rates. 24


66

That allocated amount was then adjusted based on each 1

SC’s ROR pursuant to the revised COS study shown in 2

Exhibit ___(CNG-10), Schedule PMN-6, in an attempt to 3

correct for discrepancies outside of the tolerance 4

band in rate year one. 5

Q. Do you have any recommendations with respect to the 6

overall revenue allocation? 7

A. Yes. Since we are recommending tariff consolidation, 8

we believe revenues should be allocated to the SCs on 9

an equal percentage basis, or a revenue allocation 10

factor of 1.00. 11

Q. Please explain why you recommend using a 1.00 revenue 12

allocation factor for all SCs. 13

A. We believe that the consolidation of tariffs can 14

impact the next COS study. We do not want to try and 15

correct for discrepancies in this case only to find 16

out that tariff consolidation created the opposite 17

effect in the relative ROR in the next COS study. 18

Q. If the Commission does not adopt your tariff 19

consolidation proposal, how would the Panel allocate 20

the incremental revenue requirement? 21

A. If the Commission does not adopt our tariff 22

consolidation proposal, we would allocate the 23

incremental revenue requirement using the response to 24


67

IR DPS-227 part 6 which uses our two step allocation 1

methodology. We recommend using a plus or minus 10% 2

tolerance band to correct for return discrepancies in 3

rate year one. If the relative ROR falls outside of 4

the tolerance band, we would use a maximum revenue 5

allocation factor of 1.25 or a minimum allocation 6

factor of 0.75 to correct for return discrepancies in 7

rate year one, while checking for significant bill 8

impacts due to tariff consolidation. We would 9

recommend a 1.00 revenue allocation factor for all SCs 10

in rate year two and rate year three. 11

Q. Why not allocate a proposed increase to fully correct 12

for discrepancies between SCs? 13

A. Rate design is not an exact science and other factors 14

have to be considered. For instance, a COS study does 15

not provide definitive results and customer impacts 16

must be considered in the revenue allocation and rate 17

design process. If the Commission does not adopt our 18

tariff consolidation proposal, the revenue allocation 19

factor should be applied in rate year one. However, 20

the decision to apply the revenue allocation factors 21

should also consider the resulting customer bill 22

impacts of the final base rate increase determination. 23

Q. Did the Accounting Rates Panel provide you with the 24


68

recommended incremental base delivery rate changes for 1

rate year one? 2

A. Yes, the Accounting Rates Panel indicated that Staff 3

would be recommending a rate year one decrease to base 4

delivery rates of $310,043. 5

Q. How is the incremental revenue requirement allocated 6

to the SCs? 7

A. We develop the incremental revenue requirement per SC 8

in Exhibit ___(GRP-16 Corrected). 9

Q. Please explain the process taken to allocate the 10

incremental revenue requirement to SCs. 11

A. We used the Accounting Rates Panel’s incremental 12

revenue requirement less taxes and late payment fees. 13

Next, we added $125,000 for the low income program to 14

reach our incremental revenue requirement for rate 15

year one of ($180,938). Our goal is to design rates 16

so that when the Company provides the low income 17

credit to HEAP customers; the Company has been made 18

whole. 19

Q. Will the $125,000 low income program be added to the 20

incremental revenue requirement in each of the rate 21

years? 22

A. No. Once we increase the revenue requirement in rate 23

year one, the adjustment will be embedded in base 24


69

rates and built upon for rate years two and three. 1

Q. Did the Company forecast an increase to late payment 2

revenues in the rate years? 3

A. No. The Company left late payment revenues constant 4

at $94,721. 5

Q. Please explain the approach you recommend for 6

forecasting late payment revenue. 7

A. We applied a late payment revenue percentage to the 8

incremental revenue requirement developed by the 9

Accounting Rates Panel to determine the change in late 10

payment revenue. We then adjusted the incremental 11

revenue requirement by the result. We are 12

recommending that the Company’s originally filed late 13

payment revenues of $94,721 be changed by the same 14

percentage as Staff’s revenue requirement decrease. 15

The resulting incremental late payment revenue would 16

raise the revenue requirement by $1,815. 17

Q. What was the Panel’s next step in allocating the 18

incremental revenue requirement to the SCs? 19

A. We divided our incremental revenue requirement by our 20

rate year sales revenues plus RDM and MFC revenues to 21

create a percentage increase to base delivery revenue. 22

Next, we multiplied the resulting percentage to each 23

SC’s delivery revenues. 24


70

Q. What did the Panel do with the resulting incremental 1

revenue requirement by SC? 2

A. For each SC, we added the incremental revenue 3

requirement to the change in the MFC revenue for our 4

adjusted revenue increase by SC. However, 5

Hammondsport customers have an extra step for Line 15 6

DRA revenues in rate year one. 7

Q. What did the Panel do with Line 15 transportation 8

revenues currently collected in Hammondsport’s DRA? 9

A. We moved Line 15 transportation revenues out of the 10

DRA and into base delivery rates in rate year one 11

because of our tariff consolidation proposal. We did 12

this by allocating the $99,602 from the DRA to each 13

Hammondsport SC on a volumetric basis. Next, we 14

increased the target incremental revenue requirement 15

for each SC by the Line 15 DRA revenues. 16

Q. Why do Hammondsport SCs show the highest delivery rate 17

increase on Exhibit ___(GRP-16 Corrected)? 18

A. The Line 15 revenues have been moved from the DRA to 19

base rates. Hammondsport customers will no longer be 20

charged for transportation in the DRA. We are 21

prepared to show these bill impacts by SC. 22

Q. Will the Panel add Line 15 revenues to the incremental 23

revenue requirement in each of the rate years? 24


71

A. No. Just like the low income program, once we 1

increase the revenue requirement in rate year one, the 2

adjustment will be embedded in base rates for rate 3

years two and three. 4

Q. How did the Panel allocate the incremental revenue 5

requirement for rate year two? 6

A. We used the same process for allocating the 7

incremental revenue requirement of $639,112 except for 8

the low income program and the Line 15 revenue change 9

as previously discussed. 10

Q. Were there any changes in the Panel’s incremental 11

revenue allocation methodology for rate year three? 12

A. No. We did not change our methodology from rate year 13

two and allocated $628,070 to the SCs. 14

Rate Design 15

Q. Please explain the Company’s approach to rate design. 16

A. The Company moved towards consolidating the Corning 17

and Hammondsport tariffs in rate design. Final rates 18

were created through an iterative process of 19

increasing the minimum charges and applying the 20

increase to deficient classes. There was no movement 21

towards a rate reduction to SCs above the system 22

average ROR. 23

Q. Did the Company propose any rate structure changes? 24


72

A. Yes. The Company would like to eliminate the 1

inclusion of 3 ccf in the minimum charge. 2

Q. Do you agree with the Company’s proposal? 3

A. No, we do not. The PSL Section 65(6) prohibits gas 4

companies from having service charges that must be 5

paid by a customer even if he or she uses no gas. The 6

exclusion of gas from the minimum charge creates a 7

service charge. Therefore, we do not recommend 8

changing the rate block structure. 9

Q. Please describe the rate design principles that you 10

recommend. 11

A. We recommend moving the minimum charge for each SC 12

closer to the minimum costs identified in the revised 13

COS study independent of the incremental revenue 14

requirement (Exhibit ___(GRP-17)). The balance will 15

be made up by applying an equal percentage to the 16

remaining blocks. 17

Q. Please summarize your minimum charge recommendations 18

over the term of the rate plan. 19

A. We recommend increasing the minimum charge for 20

residential customers by $1.50 in each rate year. For 21

commercial customers we recommend increasing the 22

minimum charge by $5.00 in each rate year. Finally, 23

for transportation and flex rate customers, we 24


73

increased the minimum charge to $50.00 from $15.25 in 1

rate year one. In rate years two and three, we 2

increased the minimum charge for transportation 3

customers by $25.00, reaching a minimum charge of 4

$100.00 in rate year three. 5

Q. Please explain why you are only recommending a minimum 6

charge increase of $1.50 for residential customers and 7

$5.00 for commercial customers. 8

A. SCs are made up of customers that can have very 9

different usages. Impacts for low use customers in 10

each SC should also be considered in the rate design 11

process. 12

Q. How did the Panel price out its proposed rates? 13

A. Exhibit ___(GRP-18 Corrected) shows the development of 14

rates for each SC. We used our forecasted sales 15

volumes and customer counts for rate year one and 16

priced out the forecast at our proposed rates to 17

determine if the revenue requirement target was met 18

for each of the SCs. We followed the same procedure 19

for rate years two and three. 20

Q. How should bill impacts tables be used when developing 21

rates in this case? 22

A. Bill impacts should be run for each SC to determine if 23

there are any significant impacts. 24


74

Q. If the bill impacts show significant impacts for a SC, 1

how would the Panel ameliorate those impacts? 2

A. If the impacts are due to our minimum charge 3

increases, we would reduce the increases. If the 4

impacts are due to tariff consolidation, we could 5

phase in the delivery rates over the term of the rate 6

plan. 7

Q. Is the Panel prepared to run bill impacts for each SC? 8

A. Yes we are ready to run bill impacts for any 9

incremental revenue requirement, including 10

levelization and local production credits. 11

Merchant Function Charge 12

Q. Does Corning currently have an MFC? 13

A. Yes. 14

Q. Has the Company proposed any structural changes to its 15

MFC? 16

A. No, the Company has proposed to keep the current 17

methodology as noted in the Company’s response to IR 18

DPS-64, but update the components. 19

Q. How did the Company calculate the MFC components for 20

the rate years? 21

A. The Company developed two MFCs; one for Corning and 22

Hammondsport and another for Bath. The Company set 23

the supply procurement and records and collections 24


75

component using the revised COS study. The Company 1

also included the commodity uncollectible rate of 2

1.105%, other customer capital rate of 3.35% and an 3

average Balance of Gas in Storage amount of $1,629,250 4

(of which 80% is allocated to the MFC). All these 5

costs were allocated on the basis of the Company’s 6

rate year forecasted sales to Bath, and Corning and 7

Hammondsport then divided by the corresponding 8

normalized firm sales to create two rates. 9

Q. Does Staff’s tariff consolidation proposal affect the 10

MFC? 11

A. Yes, Staff’s tariff consolidation proposal will affect 12

the MFC. We recommend a single MFC for all firm 13

customers. We recommend continuing the procedures 14

used in the last rate case for the development of the 15

commodity uncollectible, gas supply procurement, 16

record and collections and return on gas in storage 17

rates. 18

Q. How did you develop the commodity uncollectible 19

component? 20

A. The Accounting Rates Panel recommends an overall 21

uncollectible rate of 1.10%. We multiplied this rate 22

by the forecasted cost of gas in the rate year, per 23

Staff witness Colby, to determine our estimated 24


76

commodity uncollectible expense. The estimated 1

commodity uncollectible expense was divided by our 2

firm sales forecast to determine the rate which should 3

be charged to customers. 4

Q. How did you develop the gas supply procurement 5

component? 6

A. We used the $80,309 figure supplied by the Company in 7

Exhibit ___(CNG-10), Schedule PMN-9. This number was 8

then divided by our firm forecast to create the rate. 9

Q. How did you develop the records and collections 10

component? 11

A. We used the $184,231 figure supplied by the Company in 12

Exhibit ___(CNG-10), Schedule PMN-9. This number was 13

then divided by our firm forecast to create the rate. 14

Q. How did you develop the return on gas in storage 15

component? 16

A. We multiplied the average of the monthly averages gas 17

storage number of $1,619,158 from Staff witness Colby 18

by the Other Customer Capital rate resulting in the 19

full return on gas storage inventory. Next we took 20

80% of the full return and divide that by our firm 21

forecast to create the rate. The remaining 20% will 22

continue to be charged through the DRA to all 23

customers. 24


77

Q. What are your recommendations for the rate year one? 1

A. As shown in Exhibit ___(GRP-19), we propose a total 2

MFC of $411,183 which is a rate of $0.02793 per ccf 3

for rate year one. 4

Q. Does the Panel calculate an MFC rate for rate years 5

two and three? 6

A. No we do not. The fixed MFC components, which are the 7

supply procurement and records and collections 8

components, will remain the same over the rate plan. 9

The per unit rate will be updated during the MFC 10

reconciliation using the Company’s most recent sales 11

forecast. Gas expense will be forecasted in the MFC 12

reconciliation and used to develop the return on gas 13

in storage and the commodity uncollectible components. 14

The commodity uncollectible percent will remain fixed 15

in each rate year. 16

Q. How should the MFC components be reconciled? 17

A. The current methodology should continue, as shown on 18

Exhibit ___(GRP-19). 19

Q. When should the MFC be reconciled? 20

A. We recommend that the MFC components be reconciled on 21

a rate year basis in conjunction with the Company’s 22

filing for its annual RDM reconciliation. 23

Q. How does the Panel transition from the previous rate 24


78

year to the current rate year? 1

A. We recommend that the MFC year should be aligned with 2

the new rate years (i.e., May 1st to April 30th. 3

Q. How should this happen? 4

A. We recommend that the MFC reconciliation transition to 5

the new rate year (May 1st to April 30th). The fixed 6

MFC components will be prorated, as shown in Exhibit 7

___(GRP-20). The commodity uncollectible component 8

will be reconciled to actual commodity costs times the 9

fixed uncollectible rate. The return on gas in 10

storage component will be reconciled to actual 11

commodity costs. 12

Revenue Decoupling Mechanism 13

Q. What is the purpose of an RDM? 14

A. The purpose of an RDM is to break the link between 15

utility sales and its delivery revenue to eliminate 16

the disincentive to promote energy efficiency. 17

Q. Does Corning currently have an RDM? 18

A. Yes. 19

Q. Has the Company proposed any changes to the RDM? 20

A. Yes, the Company proposed excluding the weather 21

normalizing adjustment from the RDM because Corning 22

believes that it is redundant. 23



79

A. No. 1

Q. What are your concerns? 2

A. We are concerned with: (1) the fact that weather is 3

the major driver of sales discrepancies, (2) the 4

impact to the Company’s cash flow and (3) consistency 5

within the state. 6

Q. Please explain your concern with respect to weather. 7

A. Weather is the most significant reason why sales and 8

transportation revenue differs from forecast levels, 9

and these differences can shift significant charges 10

into the RDM if the Company eliminates the weather 11

normalization clause. 12

Q. Is the weather normalization adjustment “real time?” 13

A. Yes. The Company credits or surcharges customers for 14

weather related differences in customers’ current 15

bills. 16

Q. How can eliminating the weather normalization clause 17

impact the Company’s cash flow? 18

A. If overall weather was warmer than normal for the 19

heating season, the Company would have to surcharge 20

for the difference in the RDM on a significant delay. 21

Q. How do all the other New York gas utilities with an 22

RDM treat the weather normalization clause? 23

A. All other New York gas utilities with an RDM continue 24


80

to bill customers a weather normalization clause and 1

adjust their billed RDM revenue accordingly. 2

Q. How does Corning execute its RDM reconciliation? 3

A. Currently, the Company uses an annual revenue per rate 4

code (RPRC) target and multiplies the target per rate 5

code by the actual average number of customers to 6

determine the allowed RDM revenue. The allowed RDM 7

revenues are compared to the actual RDM revenues which 8

are adjusted for weather. Any difference is 9

surcharged or refunded on a calendar year basis 10

including simple interest at the prevailing Other 11

Customer Capital Rate issued by the Commission. 12

Q. How does Corning define a customer? 13

A. A customer is equal to the minimum charge revenue 14

divided by the minimum charge rate. 15

Q. Why are RPRC targets currently developed on an annual 16

period? 17

A. The revenue requirement and rates are developed on an 18

annual basis and, therefore, the RDM should be set on 19

an annual basis. We developed RDM targets for each of 20

the rate years, as shown on Exhibit ___(GRP-21 21

Corrected). 22

Q. Does the current RDM year line up with proposed rate 23

years? 24


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A. No. The current RDM year begins September 1st and the 1

proposed rate year begins on May 1st. This is 2

problematic based on the current RDM methodology. 3


A. We have annual RDM targets and we have a mismatch in 5

rate years. We, therefore, have a partial year linking 6

period to reconcile. 7

Q. How does the Panel suggest the Company transition from 8

the current rate year to the proposed rate year? 9

A. We recommend that the RDM reconciliation transition to 10

the new rate year (May 1st to April 30th). We recommend 11

using an eight month RPRC target which we develop by 12

prorating the current target, as shown in Exhibit 13

___(GRP-22). 14

Q. Would this occur each rate year? 15

A. No. Once the RDM year is on the same schedule as the 16

rate year, the transfer is complete. 17

Q. Can the change in delivery service rates impact the 18

RDM reconciliation? 19

A. Yes. 20


A. Due to the billing and meter reading cycles, the 22

reported monthly billed revenue is not associated with 23

service rendered purely within the month. In the 24


82

first month of the rate year, billed revenue is pro-1

rated to reflect service rendered prior to the rate 2

year at old rates and billed revenue for service in 3

the rate year at the new rates. Using the reported 4

monthly billed revenues will skew the RDM 5

reconciliation results. 6

Q. How do we correct for this problem? 7

A. The Company should calculate the billed RDM revenue 8

using its billing determinants. 9

Q. Should the Company continue to check customer counts 10

by using a surrogate or proxy customer count? 11

A. Yes. In the last rate case a proxy customer count was 12

developed and filed as part of the RDM reconciliation. 13

We would like the Company to continue filing this 14

proxy customer count because it acts as a check for 15

any billing anomalies. 16

Q. Does the Staff proposed low income program affect the 17

RDM? 18

A. No. As long as the Company matches the target RDM 19

revenues and the actual RDM revenues received in the 20

rate year. For example, if the actual revenues 21

exclude the low income credit, the target revenues 22

must also exclude the low income credit. 23

Q. When should the Company file its RDM reconciliation? 24


83

A. The Company should file no later than 45 days after 1

the end of the rate year. 2

Q. When should the Company institute the reconciliation 3

rate? 4

A. The shortfall or excess will be surcharged or refunded 5

to customers on a volumetric basis over the 12 month 6

period commencing September 1st. 7

Q. Does this complete your testimony at this time? 8

A. Yes it does. 9

before the state of new york public service commission

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