STATE OF MAINE PUBLIC UTILITIES COMMISSION

DOCKET NO. 2007-215

CENTRAL MAINE POWER COMPANY,REQUEST FOR NEW ALTERNATIVE RATE PLAN

("ARP 2008")

Central Maine Power

An Energy East Company

REDACTEDTESTIMONY OF

DR. GARY FAUTHMW CONSULTING

Volume VI-BADVANCED METERING INFRASTRUCTURE

COST ESTIMATE

May 1, 2007

Jared S. des RosiersJohn W. GulliverDeborah L. Shaw

Pierce Atwood LLPOne Monument Square

Portland, ME 04101

r

REDACTED

TABLE OF CONTENTSPREFILED DIRECT TESTIMONY OF

DR. GARY FAUTH

ADVANCED METERING INFRASTRUCTURECOST ESTIMATE

I. INTRODUCTION AND OVERVIEW 1

A. Qualifications of Witness 1

B. Cost Estimation Process 2

II. COST ESTIMATES BASED ON CURRENT INDUSTRY PRICING 5

A. AMI Systems Evaluated 5

B. Capital Cost Assumptions 9

C. Operating Cost Assumptions 17

D. Assessment of Alternative Scenario Costs 18

III. AMI COST EXPERIENCE AT OTHER UTILITIES 22

IV. CONCLUSIONS 24

Tables and Figures

Table GF-1. AMI Deployment Capital Cost (per Meter) Estimates - REDACTED 4

Table GF-2. Comparison of Substation-Based and Density-Based Hybridization Strategies -REDACTED 9

Table GF-3. Capital Costs Under Alternative Technology Scenarios - REDACTED 10

Table GF-4. Projected Endpoint Equipment Prices - REDACTED 12

Table GF-5. Capitalized Meter Replacement Costs - REDACTED 13

Table GF-6. Projected Installation Unit Price - REDACTED 14

Table GF-7. Key Communications Network Assumptions - REDACTED 15

REDACTED

Table GF-8. Aggregate Expenses, and Expenses per Meter Per Month - REDACTED 18

Figure GF-1. Customer Density Map of CMP 19

Exhibit GF-1. Professional and Educational Background of Dr. Gary Fauth

REDACTED

CENTRAL MAINE POWER COMPANYPREFILED DIRECT TESTIMONY OF

DR. GARY FAUTHDocket No. 2007-215

May 1, 2007

ADVANCED METERING INFRASTRUCTURECOST ESTIMATE

i

2 I. INTRODUCTION AND OVERVIEW

3 The purpose of this testimony is to present the basis for Central Maine Power

4 Company's ("CMP" or the "Company") estimate for the expected capital and operating

5 costs of CMP's proposed installation of an advanced metering infrastructure ("AMI")

6 system as part of its proposed new alternative rate plan. Based on a detailed analysis of

7 the costs and benefits of available technologies, CMP estimates that the cost per meter of

8 installing an AMI system will be approximately $ | ^ |, with a total cost for

9 CMP of about $| H|H- Ongoing operating costs are estimated at

10 $0.25/month/meter. As discussed below, these figures present a reasonable estimate of

11 AMI related costs for planning purposes, based on the currently available industry pricing

12 data and the reported costs of comparable AMI installations by other utilities and, as

13 such, have been used by the Company in its overall cost-benefit analysis of the AMI

14 installation discussed in detail in the testimony of Beth Nowack Cowan.

15 A. Qualifications of Witness

16 This testimony has been prepared by Gary Fauth, a consulting economist with 30

17 years of experience in analysis of regulated industries. For 10 years he was a faculty

Fauth - 1

REDACTED

1 member in the Kennedy School of Government, teaching economics and statistics as an

2 Associate Professor. His corporate experience includes positions as Director of

3 Economics at the Union Pacific Corporation, General Manager of Dun & Bradstreet

4 Technical Economic Services, and Executive Vice President of Faneuil Market Research.

5 His government experience includes a position as Assistant Deputy Director of Policy

6 Research at the Interstate Commerce Commission. Over the last eight years, working

7 with Michael Wiebe of MW Consulting, Dr. Fauth has estimated automated metering

8 costs for a number of major utilities including two utilities in North America - Pacific

9 Gas and Electric Company ("PG&E") and PPL Electric Utilities ("PPL"). - that have

10 built or approved systems to collect hourly and quarter-hourly data of the type specified

11 by CMP. Dr. Fauth has a PhD in economics from Harvard University. A summary of

12 Dr. Fauth's professional and educational background is attached as Exhibit GF-1.

13 B. Cost Estimation Process

14 Anticipating AMI system capital and operating costs without the benefit of firm

15 bids is challenging for two reasons. First, although prices taken from contracts with

16 utilities would be a reasonable base for building cost estimates, the terms of contracts

17 with utilities are generally not made public. Consequently, contract prices cannot be

18 referenced to build cost estimates. Second, technology and service vendors base prices

19 not solely on manufacturing costs but also on their current position in the overall AMI

20 marketplace. Individual vendors may price very aggressively if they view winning the

21 business as a strategic necessity, or less aggressively if they feel capacity constrained,

22 based on current orders. Consequently, any pricing analysis not based on current firm

23 bids is of necessity a preliminary effort at understanding cost.

Fauth - 2

REDACTED

1 In this testimony, the cost estimation process is structured around two parallel and

2 complementary approaches:

3 1. Estimation of costs for typical technologies that might be used at CMP,

4 based on currently observed industry pricing; and

5 2. Review of actual costs observed or anticipated at the two utilities that have

6 implemented AMI systems with functionality similar to that required by

7 CMP. This review also includes consideration of the costs Bangor Hydro

8 experienced when it recently installed automated metering.

9 This testimony first presents cost estimates based on observed industry pricing. It

10 then summarizes the evidence that exists about costs reported at other utilities. The

11 testimony identifies $HIHJjj[ | as a reasonable planning cost, based on a detailed

12 analysis using best estimates of industry pricing. This per meter cost yields an aggregate_^_

13 expenditure of $HBH for CMP. In Table GF-1 below, this industry per-meter

14 capital cost estimate is the dark shaded bar. For perspective, reported costs from PPL in

15 Eastern Pennsylvania, PG&E in Northern California, and Bangor Hydro are included in

16 the same figure, in light shaded bars. These three reported costs range from $124 to $150

17 per meter. This testimony discusses some of the factors that differentiate these utilities

18 and the systems they installed from the situation at CMP, so that the per-meter capital

19 cost differences can be more clearly understood, and concludes that the industry-pricing-

20 based estimate is consistent with the reported costs. This consistency increases the

21 confidence in the chosen planning cost.

Fauth - 3

REDACTED

1

2 Table GF-1. AMI Deployment Capital Cost (per Meter) Estimates

$140-

$120-

$100 H

$80 -

$60 •

$40 •

$20-

sn -

$124$135

Industry Pricing PPL Reported Costs PG&E Estimated Bangor HydroEstimate (Started 2002) Costs (Started 2006) Reported Costs

(Started 2004)

4 Sources: PPL Press Release, FERC AMI Report, Bangor Hydro Rate Case Proceeding

Fauth - 4

REDACTED

1 II. COST ESTIMATES BASED ON CURRENT INDUSTRY2 PRICING34 Current industry pricing is developed from industry trade shows, discussions with

5 sales executives at the various hardware and service firms in the industry, and,

6 occasionally, information shared by utilities that have considered or that have purchased

7 automated metering equipment. Inherently, there is a significant but unquantifiable

8 margin for error in the approach, since industry pricing changes with market conditions,

9 and since quoted prices at trade shows do not usually correspond to negotiated contract

10 prices, which are always subject to nondisclosure and therefore not available for

11 analytical use.

12 A. AMI Systems Evaluated

13 Two different kinds of systems were evaluated for hypothetical 100 percent

14 deployment in the CMP service area:

15 • A Power Line Carrier ("PLC") system, representative of the most widely

16 adopted system in North America today; and

17 • A Radio Frequency ("RF") system, representative of the emerging new RF

18 systems that offer mesh networking, Internet Protocol ("IP")

19 communications, and open architecture to accommodate third-party

20 devices that can provide additional functionality. Mesh networking

21 incorporates the meters as part of the communication network.

22 Both PLC and RF systems can capture the benefits of automation: the systems differ in

23 the way information flows between the meters and the central system controllers.

24 Broadband over Powerline ("BPL") is a type of PLC system that provides higher

25 bandwidth and reduced latency for the transport of meter data. BPL has not been

Fauth - 5

REDACTED

1 assessed for the cost estimates included in this testimony since it is generally a higher-

V,.,,'2 cost communication solution. During the RFP process, CMP will review all potential

3 technology solutions for the AMI system.

4 PLC systems use the utility power lines for communications between the

5 customer meters and the central data management system. With a PLC system, the

6 system controller for the entire AMI system issues information requests to individual

7 meters. The requests flow via a public communication network (telephone line or

8 satellite) to the substation serving the meters, and then over CMP's distribution power

9 lines directly to the meters The information requests are processed by communication

10 modules embedded in the meters, and responses - typically hourly consumption data over

11 a recent period - flow back to the system controller over the same path on which they

.•*--• 12 arrived.

13 RF systems use wireless communications protocols to communicate between the

14 meters and the system controller. Either the system controller or the meter can initiate

15 the communication. For example, when the system controller needs recent consumption

16 information, the request flows out over a public network (typically land-line or cellular

17 telephone) to an RF information gateway, typically mounted on a power pole or street

18 light near the meter being queried. The gateway relays the request wirelessly to the

19 meter, which responds, sending the information in the reverse direction, back to the

20 system controller.

21 For most purposes, the choice of technology is not a significant differentiating

22 factor except for cost, since similar functionality can be provided by both systems.

23 However, conventional wisdom in the industry is that PLC systems are better choices

Fauth - 6

REDACTED

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than RF systems for low-density service territories like CMP's. To understand whether

this conventional wisdom is still true, given the newer RF systems with lower cost mesh

communications networks, both technologies are distinguished and reviewed in this

testimony.

In addition to pure PLC or RF systems, two 50/50 hybrid PLC/RF systems that

exploit both types of automation systems have been evaluated in this testimony:

HA substation-based approach

|An alternative density-based approach

With hybrid approaches there will always be some communications network

redundancy. PLC systems require significant substation modifications to support

communications over the CMP power lines, while RF systems require installation of

communication gateways on utility poles or street lights to wirelessly link to the meters.

With hybrid systems, there will be situations where both the PLC and RF

communications network are installed and can potentially be used to support meter

automation. In these situations, either RF or PLC could be chosen as the automation

Fauth - 7

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REDACTED

system, but only one system is actually used to read the meters, resulting in infrastructure

redundancy. The hybrid systems considered here illustrate two alternative approaches for

minimizing this redundancy.

Table GF-2 compares the structure of the two hybrid approaches.

Both the

20 density-based and the substation-based approaches are considered in this testimony to

21 evaluate the cost advantages and disadvantages of each.

Fauth - 8

REDACTED

1 Table GF-2. Comparison of Substation-Based and Density-Based Hybridization Strategies

2

Statistic

Square Miles of RF System CoverageSubstations Requiring PLC ConversionRF Repeaters RequiredRF Take Out PointsCustomers With RF Coverage

Hybrid Basedon Substation

Analysis

REDACTEDREDACTEDREDACTEDREDACTEDREDACTED

Hybrid Basedon Density

Analysis

REDACTEDREDACTEDREDACTEDREDACTEDREDACTED

4 B. Capital Cost Assumptions

5 Confidential Table GF-3 presents the comparative capital costs of the 100

6 percent PLC system, the 100 percent RF system, and the two 50/50 hybrid systems.

7 Confidential Table GF-3 illustrates a capital cost range from $HHH for the 100

8 percent PLC system to $lHHi | for the 100 percent RF system. The remainder of

9 this section provides more detailed discussion of each of the cost line items included in

10 Confidential Table GF-3.

Fauth - 9

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REDACTED

CONFIDENTIAL Table GF-3. Capital Costs Under Alternative Technology Scenarios

2008-2010 Total Deployment Cost(Aggregate Capital Costs)

Integrated Metei/Modules HardwareMeter/Module InstallNetwork HardwareNetwork InstallationProject ManagementMDMSGrowth HardwareContingency

Total

PLC RF

50-50 HybridBased on

Substation50-50 Hybrid Based

on Area Density

REDACTED

2008-2010 Total Deployment Cost(Cqp ital Costs per Meter)

Integrated Meter/Modules HardwareMeter/Module InstallNetwork HardwareNetwork InstallationProject ManagementMDMSGrowth HardwareContingency

Total

PLC RF

50^0 HybridBased on

Substation50-50 Hybrid Based

on Area Density

REDACTED

Meters with integrated communications modules (endpoints located at customer

premises) account for slightly over | percent of the deployment costs. Included in this

cost are several elements including meters, A- and C- base adaptors, disconnect switches

and meter replacement.

For both systems all new meters were assumed.

Fauth - 10

REDACTED

While a meter retrofitting strategy could have been used for the PLC system,

similar to the one that Bangor Hydro implemented in its meter-reading automation

project,

Electromechanical meters, in

contrast, typically require external extensions, or collars, to accommodate additional

features, since space under-the-glass is more limited.

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11 At BlI lH percent of all meters are single phase devices, | ^H | are self-

12 contained polyphase devices, and | percent are transformer-rated polyphase devices. In

13 addition, based on CMP-specific calculations, the analysis assumes that |H

14 disconnect switches will be deployed, and m~ and C-base adapters will be needed

15 for some of the oldest meters in place. These older meters fit into meter panels that are

16 not configured to accept the current modern meter. Since AMI communications modules

17 for older A- and C-based meters are typically not available, an adapter is needed to

18 configure the older A- and C-based meter panel to accept today's modern meters, so that

19 communicating meters can be installed. The adapter is inserted into the A- or C-base

20 panel to accept the new forms of meters. Buying and installing the adapters adds costs to

21 the overall automation process. Confidential Table GF-4 presents the detailed meter

22 price assumptions that were used to develop the aggregate costs of endpoint hardware.

23

Fauth - 11

REDACTED

CONFIDENTIAL Table GF-4. Projected Endpoint Equipment Prices

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3

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Endpoiiir Equipment or SVivi'eSingle Phase Meter CostPolv Phase Self- Contained Meter CostPoly Phase Transformer-Rated Meter CostMeter Module Integration CostA&C Based Adapter CostDisconnect Switch CostSingle Phase Communications Module PricePoly Phase Communications Module Price

PLC RF

REDACTED •

Disconnect switches are among the hardest components to price out; historically,

4 the switches have been available for about ^|. However, recently, the interest in

5 disconnect switches has been very high, both to support remote turn-ons and turn-offs,

6 and also to support provision of pre-payment services. As a result of the higher

7 anticipated volumes, the prices of disconnect switches have been falling. Some vendors

8 are projecting HHH for disconnect switches today. However, transactions at that

9 price have yet to be observed. For this analysis, prices were chosen in between the

10 historical high prices and the future-looking low prices.

1 1 The single phase RF meter used in this analysis has extra information storage and

12 a bundled integration price, which explain its higher cost relative to the meter used in the

13 PLC system. The communications module prices are projected to be nearly equivalent

14 across the two systems.

1 5 Replacing meters, including their communications modules, that fail while in

16 service generates a capital expenditure at CMP. Table GF-5 indicates the annual failure

17 rates projected in this analysis, along with the costs of failure. A five-year warranty for

1 8 materials has been assumed.

Fauth- 12

REDACTED

Table GF-5. Capitalized Meter & Network Replacement Costs

Maintenance Cost Component

Annual Meter/Module Failure RateMeter/Module Failure Cost LaborMeter/Module Failure Cost MaterialsTake Out Point and Repeater Failure RateTake Out Point Failure Cost LaborTake Out Point Failure Cost MaterialsRepeater Failure Cost LaborRepeater Failure Cost MaterialsWarranty Period

PLC KF

REDACTED

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3

4 Finally, the analysis assumes that approximately | ! meters with modules need to be

purchased to replace existing meter inventory. This involves a cost of | for the

6 PLC system and |

7

for the RF system.

Endpoint installation accounts for about H | of the total deployed system

8 costs. Typically endpoints are installed by specialized installation vendors, who have the

9 available labor force and support software necessary to put the meters in place over a

10 concentrated two-year period. In this analysis, based on the CMP-estimated mix of hard-

11 to-reach meters, it has been assumed that j^HH of all meters can be installed on the

12 first site visit. HHHH of the meters will be installed by the installation vendor

13 after multiple visits, while HHH of the meters will be returned to CMP by the

14 installation vendor because installation could not be completed. These two percent of

15 meters will need to be installed by field services personnel at CMP. The analysis also

16 assumes that JHm^H of all installation efforts will encounter a meter panel in need of

17 repair, and at CMP will handle those repair costs as part of the deployment effort.

18 Endpoint pricing assumptions are detailed in Confidential Table GF-6.

Fauth-13

REDACTED

CONFIDENTIAL Table GF-6. Projected Installation Unit Prices

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3

Installation Task

A&C based Adapter installation priceSingle Phase First TV? installation priceSingle Phase Multiple Try Installation PriceSingle Phase Return to CMP Installation PricePoly Phase Self Contained First Try installation pricePoly Phase Self Contained Multiple Try Installation PricePoly Phase Self Contained Return to CMP Installation PricePoly Phase Transformer Rated First Try installation pricePoly Phase Transformer Rated Multiple Try Installation PricePoly Phase Transformer Rated Return to CMP Installation Price

FLC RF

REDACTED

Network hardware and installation account for between of total

|. For PLC systems, this analysis

6 assumes that all | substations need additional equipment to support information

7 transfer, and that percent of the substations need additional communications

8 infrastructure to support transfer of information to and from the Meter Data Management

9 System ("MDMS"). For RF systems, the analysis assumes that the communications

10 network has a mesh structure, which requires | network repeater devices per square

1 1 mile to fill in spaces where the meters themselves are too far apart for direct

12 communication. In addition, a major RF communications node is required for every

13 |^| meters, to concentrate the information and handle communications to and from

14 the system controller. All communications nodes, or take out points, in the RF

15 communications network will require communications infrastructure. Confidential

16 Table GF-7 summarizes the projected prices for network hardware and installation,

1 7 assuming installation is completed by a third-party vendor.

Fauth- 14

REDACTED

-.*.

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2 Tab;e 6: Key Communications Network Assumptions

Network Cost Component

Ta]» Out Pnint ( $&\<\ifypa. or Concentiatarl Hardware CostTsltp Dnt Pnint instsll«tinri prireRpneater*: r\rr ^nuarp MileH epp.ater CnstRepeater Installation Hnst"/. nf Talte Out Pnints that Ti>nnm> f!nmTrmniratirin<:One-Time nnmTnnniratinns Tnfrastmrtnre HnstTake Out Pninfs fnr 1 fin*/, HnvpTngf!P ftTifistftrs fnr 1 nflV. nnvRTapp

PLC KJ.

REDACTED

3

4 Replacement of failed network components is a capital expenditure, and Table

5 GF-5 presents the assumptions used to compute the failed equipment cost. A warranty

6 period of |H | is assumed, and labor escalation for union labor is used to calculate

7 maintenance costs in any particular year. In addition, it is assumed that the network

8 equipment will be replaced over a Jj-year period beginning in Hj. Finally, a spare

9 parts inventory is assumed for networks, equivalent to one percent of the hardware

10 installed during deployment.

11 In this analysis the MDMS is projected to cost iHHU. Both the PLC and

12 RF systems will require system controllers to interact with the communications network

13 and meter endpoints. This analysis includes HH for system controller hardware and

14 software. The system controller connects to the MDMS. This analysis includes |

16 The integration process assumes that information will be passed to the CMP customer

17 information system in the same format as today's transfers of handheld data. Integration

18 costs for CSS are further defined in the operating cost assumptions. Upgrades to the

Fauth-15

REDACTED

1 Company's CIS system are also forecasted to occur in 2008 at a cost of approximately

2 HH in order to support the additional meter data points.

3 Project management is projected to cost HI^H- The core project

4 management team is anticipated to include 5 Full Time Equivalents ("FTE's") in 2008

5 and 2009, and 4 FTE's in 2010. In addition, the projection assumes that vendor project

6 management fees of | [ will be charged to the project. Project management also

7 includes HH for communications to customers regarding the new system.

8 The capital expenditure includes the incremental costs associated with new

9 customer accounts. The incremental cost of adding the AMI communications module to

10 all new meters installed for growth is added each year to the overall costs: during

11 deployment years this expenditure for growth totals | ^B|. The analysis

12 assumes no new communications network will be required; the network created during

13 system deployment is assumed to have sufficient coverage and capacity to handle future

14 new customer growth.

15 Finally, the analysis assumes a contingency I^IH^H of overall deployment

16 costs. Contingency, by definition, is undefined with respect to particular uses, but some

17 events that might drive contingency use would include:

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Fauth- 16

REDACTED

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5 C. Operating Cost Assumptions

6 Operating costs are assumed to include monthly communications costs for all

7 take-out points, evaluated H^| per month per take out point. In addition, a team of

8 4.5 FTE's is projected to handle both network communication services and also meter

9 services system operations. In 2008, H|[| has been assumed for the testing,

10 integration and updates to the CSS to support AMI deployment and new MDMS

12 hardware and software costs as annual maintenance fees. The analysis also assumes a

13 full-time change management specialist for 2008 and 2009 to develop and implement

14 needed training programs for the revised internal processes made possible by AMI.

15 While part of the AMI project management team, change management is viewed as

16 expense rather than capital and hence described here in the operations and maintenance

17 section.

18 Total projected expenses for 2011, the first full year of operations after

19 deployment is complete, are shown in Confidential Table GF-8.

Fauth- 17

REDACTED

1 CONFIDENTIAL Table GF-8. Aggregate Expenses, and Expenses per Meter Per Month

2011 Annual O&M CostsTotal Annual O&MO&M cost per metei

PLC EF50-50 Hybrid Based

on Substation50-50 Hybrid Based

on Area Density

REDACTED2

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D. Assessment of Alternative Scenario Costs

5 Both the PLC and the RF technology that have been assessed have the

6 functionality to deliver the benefits outlined earlier in this testimony and in the testimony

7 of Ms. Nowack Cowan.

8

Figure GF-1 provides an illustrative density map of the CMP service territory.

The dark areas have 100 meters or more per square mile, while the light areas have less

than 100 meters per square mile. The lightest areas within the CMP service area

boundaries do not have any meters at all located within them.

Fauth- 18

REDACTED

2

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Figure GF-1. Customer Density Map of CMP

RF system design recognizes that providing cost-effective service at low customer

4 densities is challenging, and most older RF systems draw an economic line somewhere

5 around 100 customers per square mile. Newer RF systems, such as the one considered in

6 this testimony, typically can serve lower densities, but still eventually encounter rising

7 communications network costs as customer density declines.

In the CMP analysis,

The newer RF systems, with mesh network

10 technology, appear to be more efficient at serving lower density areas. By relying on the

11 meters to be the network in these areas, the newer RF systems may be more cost-effective

Fauth- 19

REDACTED

1 than older RF systems that required the construction of full RF listening networks to

2 communicate with the meters.

Fauth - 20

REDACTED

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There is, at this point, no clear basis upon which to choose one hybrid system

over the other; the costs are very similar. In the discussion here, the hybrid system based

on density was chosen by virtue of its slightly lower initial construction costs. The

slightly higher operating cost of the density-based hybrid will be offset by the initial

capital cost advantage.

Fauth-21

REDACTED

1 III. AMI COST EXPERIENCE AT OTHER UTILITIES

2 The previous section outlines deployment cost projections of |

3 including contingency, and operations and maintenance costs projections of |

4 IBHU^^I- I" order to test these estimates, CMP compared them to the costs of

5 utilities that have actually deployed AMI. Only two AMI systems that meet CMP's

6 functional requirements have been approved and financed in North America over the last

7 five years: a 1.3 million meter deployment at PPL in eastern Pennsylvania, and a 9.3

8 million meter deployment, including both gas and electric meters, at PG&E in northern

9 California.

10 PPL utilities has published testimony and issued press releases indicating that its

11 AMI system built to serve 1.3 million customers cost $160 million to build. This results

12 in a deployment cost per customer of $124. The PPL system, as originally designed, did

13 not include an MDMS, and it was completed several years ago, in 2004. In addition, the

14 PPL system utilized refurbished electromechanical meters, instead of all new electronic

15 meters. Recognizing that CMP's HJ[ | estimates include HIH meter for an

16 MDMS and also H^ | | for contingency, the CMP projection based on industry

17 pricing and the PPL actual deployment costs are reasonably consistent. The PPL

18 experience actually predates the expected CMP experience by six years, and it is

19 reasonable to expect that inflation, especially on installation costs, would drive the CMP

20 estimate to be higher. However, technology manufacturing costs have been driven down

21 over this same period, and competitive market pressures have also operated to keep prices

22 down. Consequently, the similarity of the PPL experience to the projected CMP

23 experience lends some credibility to the CMP projections based on industry pricing.

Fauth - 22

REDACTED

1 The Federal Energy Regulatory Commission ("FERC") has published a capital

**"' 2 cost per meter for PG&E of $135. The PG&E costs are current, so inflation adjustments

3 and competitive market adjustments are not a consideration. The PG&E reported costs

4 appear lower than the PLC cost being projected for CMP. This is at first surprising, since

5 PG&E operates in a significantly higher-cost labor market than does CMP, which might

6 be expected to drive up installation and project management costs. However, PG&E may

7 have benefited from a "big-buyer" discount because of its 9.3 million endpoints. Scale

8 permits AMI vendors to take advantage of manufacturing economies that are significant.

9 Bangor Hydro's system is reported in regulatory filings to cost $150 per endpoint.

10 Bangor Hydro operates in essentially the same labor market as does CMP, but the Bangor

11 Hydro project involved only 116,000 meters. It is likely that Bangor Hydro paid a higher

12 price for equipment than CMP can expect to pay, because of the small scale of the

*""' 13 Bangor Hydro project.

14 Remarkably little information is available on AMI system operating costs, so the

15 benchmarking that can be undertaken for capital costs cannot be duplicated for operating

16 costs. However, by taking into account communications costs, maintenance costs, and

17 staffing costs, the operating costs do cover the major cost areas associated with AMI

18 operations.

Fauth - 23

REDACTED

1 IV. CONCLUSIONS

2 The cost-estimation approach discussed in this testimony is based on industry

3 pricing, is logically sound, and is broadly consistent with reported costs from utilities that

4 have implemented AMI. Consequently, it is reasonable to use the resulting capital and

5 operating cost estimates discussed above as a planning base for CMP's AMI analysis, and

6 as an estimate of the costs CMP will incur for calculating estimated overall returns during

7 the period of the Company's proposed new alternative rate plan.

Fauth - 24

Exhibit GF-1Page 1 of4

Docket No. 2007-215May 1,2007

Gary Fauth

Education

Harvard University, Ph.D., economics (Harvard Graduate Prize Fellow)

Yale College, A.B., economics (highest honors)

Honors and Awards

Brookings Institution designation as Economic Policy FellowICC commendation for outstanding performance, 1980Woodrow Wilson Fellowship for graduate study, 1969

Professional Experiene

Consulting Economist 1999-Present

Recent project work includes:

• Design, analysis, and implementation of an automated meter reading system for two majorutilities, including strategic analysis of new business opportunities made possible by theautomated system

• Economic analysis of automated meter reading for several large electric utilities, in NorthAmerica and in Australia

• Cost analysis for the development of a new campus for a major eastern university

• Analysis of transportation investment strategies for Lower Manhattan, in the post 9/11environment

• Financial analysis of major highway investments in Chinese provincial capital ofShijiazhuang

• Analysis of the impacts of the Community Reinvestment Act, including development ofeconometric models to identify changes in lending stimulated by the Act.

Executive Vice President for Consulting, Faneuil Research 1993-1999

Project work included:

Exhibit GF-1Page 2 of 4

Docket No. 2007-215May 1,2007

• Analysis of manufacturing costs of motor vehicle emission control equipment for the AAMA

• Operational cost-saving study for a major railroad

• Ridership forecasting for a fixed rail transportation facility between Manhattan and Kennedyand LaGuardia airports

• Merger and acquisition analysis for a major railroad

Vice President, Transportation/Regional Economics Program, Charles River Associates, 1988-1993. Project work included:

• Assessing the competitive consequences of a merger between a natural gas pipeline and anatural gas distribution company

• Designing appropriate investment criteria for Urban Public Transit Systems

• Redefining natural gas transportation emergencies in light of recent moves to deregulate thepipeline industry

• Assessing air cargo information needs for marketing and planning functions at the New YorkPort Authority

• Evaluating ship and rail distribution costs for U.S. iron ore

• Identifying geographic markets for glass bottles

• Describing transport costs for pulpwood, and the competitive consequences of a merger inthe pulp and paper industry

• Evaluating the distribution system for crude stored in the National Petroleum Reserve

• Estimating ridership for a LaGuardia-Kennedy airport transit connection

• Outlining competitive pricing and marketing procedures in the cellular telephone industry

Dun & Bradstreet Technical Economic Services:General Manager, 1987-1988Responsible for sales, marketing, production, and client services for a Dun & Bradstreet divisionthat developed a set of computerized energy information products

• The Official Pipeline Guide (OPG), which provides transportation rate and minimum-costroute information

• The Major Industrial Plant Database (MIPD). which tracks final demand for gas

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• The Gas Supply Service (GSS), which monitors gas supply at the wellhead

Vice President, Product Development and Management, 1986-1987Responsible for:

• Telephone and mail surveys, as well as primary data collection from government records

• Database management systems to organize collected data and deliver it to clients

• Expert systems to quality check the data and to estimate missing values

• PC-based menu-driven software to provide easy access to occasional users

• Analytical models to add value to the raw data

Director of Client Services, 1983-1986Set up this division of the company, recruiting and managing a staff of professional economists.He also:

• Trained clients in basic computer skills and basic marketing strategies

• Completed special client projects, including pipeline corridor-based final demand studies andT*"*" estimates of market potential for coal-fired industrial boilers

• Was responsible for renewing and expanding client product use

Harvard University Schools of Government and DesignAssociate Professor, 1978-1984Assistant Professor, 1974-1978Developed and taught coursed in transportation economics, introductory economics, statistics,and computer systems, as part of a graduate program in planning, policy analysis, anadministration. He also directed admissions and the financial aid program for Harvard GraduateSchool of Design. He managed several large research projects that:

• Evaluated traffic engineering proposals for Cambridge (Massachusetts)

• Analyzed motor carrier tariff structure for the U.S. Department of Transportation

• Identified costs and benefits of reducing traffic congestion in Boston, for the Urban MassTransportation Administration (UMTA)

• Outlined costs and benefits of improving bus service between Boston's South Shore andDowntown, also for UMTA

Dr. Fauth consulted to a number of private- and public-sector clients on projects that included:

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• Public transit system design in Cleveland (Ohio), Singapore, and Tehran (Iran)

• Highway investments in Seoul, Korea

• An acquisition study of a western railroad

Director of Economics and Strategic Planning, Union Pacific Corporation, 1982-1983

• Prepared short- and long-term economic forecasts for corporate planning and budgetingcycles

• Prepared monthly economic update for senior management meetings

• Analyzed legislative proposals that potentially affected the company

• Completed merger and acquisition studies

• Managed a microcomputer-based information system for the economics and strategicplanning departments

,* , Assistant Deputy Director, Office of Policy and Analysis, Interstate Commerce Commission,f 1979-1980

• Designed a research program to explore the impacts of deregulation, and managed a team ofconsultants and academics to implement the program

• Helped revise ICC enforcement programs and policies

• Completed a detailed analysis of small community impacts of deregulation

• Prepared testimony for congressional hearings