new mexico

BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION

IN THE MATTER OF THE APPLICATION(:~F PUBLIC SERVICE COMPANY OF NEWMEXICO FOR A REVISION OF ITS RETAILELECTRIC RATES PURSUANT TO ADVICEN OTICE NOS. 397 AND 32 (FORMERTNMP SERVICES),

P UBLIC SERVICE COMPANY OF NEWIV[EXICO,

Applicant

))))))))))

Case No. 10-00086-UT

DIRECT TESTIMONY AND EXHIBITS

OF

JAMES A. MAYHEW

June 1, 2010

DIRECT TESTIMONY OFJAMES A. MAYHEW

NMPRC UTILITY CASE NO. 10-00086-UT

TABLE OF CONTENTS

I. OVERVIEW ...........................................................................................................................2

Il. DEVELOPMENT OF REVENUE REQUIREMENTS .........................................................8

A. TEST PERIOD ......................................................................................................................8B. SUMMARY OF OVERALL REVENUE REQUIREMENTS ............................................17C. REVENUES ........................................................................................................................26D. RATE BASE .......................................................................................................................30E. FUEL EXPENSES ...............................................................................................................32F. OPERATION AND MAINTENANCE ("O&M") EXPENSES ..........................................45G. PHASE-IN .̄...................... .....................̄ ......... ..............̄ ....... ........ ......̄ ......... ................. ....49

IX’. RATE DESIGN.................................................................................................................... 2

V iI. MISCELLANEOUS

LIST OF TABLES

T¢~,BLE JAM-1 TEST PERIOD REVENUE REQUIREMENTS ................................................19

T,,~LBLE JAM-2 TEST PERIOD FORECASTED REVENUES ...................................................26

TABLE JAM - 3 REVENUE DEFICIENCY ...............................................................................48

AI’FIDAVIT

I_IST OF EXHIBITS

PNM EXHIBIT JAM-1

PNM EXHIBIT JAM-2

PNM EXHIBIT JAM-3

PNM EXHIBIT JAM-4

PNM EXHIBIT JAM-5

P NM EXHIBIT JAM-6

P ~IM EXHIBIT JAM-7

P’~IM EXHIBIT JAM-8

PNM EXHIBIT JAM-9

PNM EXHIBIT JAM-10

PNM EXHIBIT JAM-11

PNM EXHIBIT JAM- 12

P~,JM EXHIBIT JAM- 13

PNM EXHIBIT JAM-14

PNM EXHIBIT JAM-15

P]~IM EXHIBIT JAM- 16

PI’IM EXHIBIT JAM- 17

PNM EXHIBIT JAM-18

PNM EXHIBIT JAM- 19

PI~’M EXHIBIT JAM-20

PB M EXHIBIT JAM-21



Resume of James A. Mayhew

List of 530 Schedules Sponsored

Requested Capital Additions

Comparison of Sales and Customers

Significant Revenue Impact

Rate Case Expenses

Explanation of Load Forecast

Permian Basin Gas Prices, Palo Verde Hub Market Prices

Embedded to Marginal Cost

Functional Comparison of Marginal Cost

Methods of Class Study Allocations

Summary of Revenue Increase and ROR by Class

Monthly Peak Load Trends

Time of Day Peak Load Trends

Tariffwith no change in Customer Charge

Development of Fixed Cost Recovery Rider

Decoupling Implementation

Decoupling Prior Year Example

Development of Fixed Cost Recovery for New Interconnected

Customers

Development of Distributed Generation Avoided Cost

Solar Peak Compared to PNM System Peak

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PLEASE STATE YOUR NAME, TITLE AND BUSINESS ADDRESS AND

RESPONSIBILITIES.

My name is James A. Mayhew. I am the Director of Pricing and Cost of Service for

Public Service Company of New Mexico ("PNM" or "Company"). My business address

is Public Service Company of New Mexico, Alvarado Square MS-0820, Albuquerque,

NM 87158. I am responsible for the preparation of PNM’s cost of service, pricing and

proposed tariff changes in the jurisdictions where the Company operates. I also have

responsibility for revenue and margin forecasts including sales and fuel.

PLEASE PROVIDE YOUR EDUCATIONAL BACKGROUND

EXPERIENCE.

My educational and work experience is described in PNM Exhibit JAM-1.

AND WORK

HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE NEW MEXICO PUBLIC

REGULATION COMMISSION ("COMMISSION")?

Yes I have. Listings of the cases are provided in PNM Exhibit JAM-1.

WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS CASE?

The purpose of my testimony is to:

1. provide an overview of the filing;

2. describe the development of the revenue requirements for PNM North and for PNM

South;

3. describe the phase-in proposed by PNM;

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4. describe how PNM proposes to handle cost recovery for renewables;

5. summarize the allocation of revenue requirements to customer classes;

6. describe how rates were designed to recover revenues while mitigating overall impact

on customers;

7. provide an explanation for rate design and rate making methods to comply with Rule

17.7.2.9K (7)(a).

8. describe how rates were designed to recover costs for new interconnected customers;

and

9. describe how this filing complies with previous orders of the Commission.

PLEASE LIST THE 530 SCHEDULES THAT YOU ARE SPONSORING.

The 530 Schedules I am sponsoring are included in PNM Exhibit JAM-2.

I. OVERVIEW

WHAT IS PNM REQUESTING IN THIS CASE?

As more fully described in my testimony, PNM is seeking to: (a) increase its base rates

in PNM North by $152,852,079 including base fuel revenues; (b) increase its base rates

in PNM South by $12,317,908 including base fuel revenues; (c) phase-in the base rate

increases in two increments, effective April 1,2011, and January 1, 2012, ifPNM’s rate

relief request is fully accepted; (d) provide the rationale for continuation of the separate

revenue requirement for PNM North and PNM South; (e) implement a fuel and

purchased power cost adjustment clause ("FPPCAC") for PNM South; (f) provide for

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separate tariff and rate design changes to PNM North and PNM South; (g) increase the

residential and small power customer charges for PNM North to recover a larger portion

of fixed costs unless the Commission adopts PNM’s decoupling proposal; (h) implement

a revised Time of Use ("TOU") pricing period; (i) implement a revised seasonal rate

period; (j) implement a proposed Fixed Cost Recovery Rider ("FCRR" or "Decoupling")

for the PNM North Residential and Small Power Rate Classes; and (k) implement a rider

for new interconnected customers for recovery of net costs to serve those customers.

WHAT DO YOU MEAN BY "PNM NORTH" AND "PNM SOUTH"?

The PNM North service territory consists of the areas PNM served prior to its acquisition

of the New Mexico assets of Texas New Mexico Power Company ("TNMP") on January

1, 2007, in accordance with the Commission’s Order approving a Stipulation in Case No.

04-00315-UT authorizing the acquisition of TNP Enterprises by PNM Resources Inc.

("TNP Stipulation"). PNM North essentially consists of the metropolitan area of

Albuquerque (including Rio Rancho, Bernalillo, Los Lunas and Belen), and the cities of

Santa Fe, Las Vegas, Deming and Clayton, and surrounding areas. PNM North consists

of approximately 460,000 customers, with forecasted calendar year 2011 kWh sales of

7,869,119,111 and forecasted calendar year 2011 base revenues including fuel of

$717,284,682 under existing rates. The PNM South service territory consists of the areas

formerly served by TNMP, which are essentially the cities of Silver City, Lordsburg,

Alamogordo, Tularosa, and Ruidoso. PNM South consists of approximately 50,000

customers, with forecasted calendar year 2011 kWh sales of 562,062,683 and forecasted

calendar year 2011 base revenues including fuel of $63,581,327 under existing rates. The

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system average cost (exclusive of miscellaneous service revenues) before the revenue

increase for PNM North is $0.0910 per kWh. The system average cost (exclusive of

miscellaneous service revenues) before the revenue increase for PNM South is $0.1084

per kWh. The predominant reason for the large cost disparity between the service areas is

how PNM’s generation and related fuel costs are assigned to PNM North and PNM

South.

WHY IS PNM REQUESTING A SEPARATE RATE INCREASE FOR PNM

NORTH AND PNM SOUTH?

In accordance with the TNP Stipulation, PNM may not consolidate cost of service for

PNM North and PNM South unless doing so involves a transfer of revenue requirement

from PNM South to PNM North of no more than $1.5 million. Under the Stipulation this

limitation will remain in place until July 2015. In addition, Stipulations in the Merchant

Plant phase of Case No. 3137 ("3137 Stipulation") and Case No. 05-00275-UT ("Alton

Stipulation") preclude PNM’s coal and nuclear base load generating plants from being

allocated to PNM South, and require a 50-50 sharing of the Afion-related costs between

PNM North and PNM South. These provisions also remain in place until the service areas

are combined.

The Total column in my exhibits and schedules which reflects the sum of the revenue

requirements for PNM North and PNM South should not be considered the revenue

requirement if PNM North and PNM South rates were consolidated. The jurisdictional

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allocations would change resulting in a different revenue requirement for the

consolidated cost of service than the sum of the separate revenue requirements.

PLEASE SUMMARIZE THE MAJOR COST AND RATE DIFFERENCES

BETWEEN PNM NORTH AND PNM SOUTH.

The cost of service and rate differences originate from the energy sources that PNM and

the then TNMP relied upon prior to the acquisition in 2007. Prior to the acquisition,

TNMP-NM was a vertically integrated utility that relied on long and short-term purchase

power contracts to meet its customers’ energy needs. Its supply costs, therefore, followed

natural gas prices closely. In contrast, PNM owned a generation fleet comprised of large

base load coal and nuclear generation facilities with some gas-fired peaking generation.

PNM’s supply costs were driven primarily by the prices of coal and nuclear power. The

three stipulations preserved these cost differences even after acquisition of the TNMP-

NM service territory by PNM. The higher per unit cost of natural gas-produced

electricity drives the higher price that PNM South customers currently pay. Given the

regulatory framework established over the years, this price disparity remains despite the

fact that PNM operates its generation and transmission system as a single system.

There are also significant differences between the rate structures of PNM North and PNM

South. For example, PNM North has more commercial and industrial rate classes, a

FPPCAC, TOU options for its customers, seasonal rate periods, and an inclining block

rate structure for its residential rate class. There are thirteen PNM North rate classes and

eight PNM South rate classes within each of the allocated class cost of services. It is

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important to note that PNM South does not have a FPPCAC despite its heavy reliance on

gas-fired generation. TNMP’s FPPCAC was eliminated as part of the TNP Stipulation

since PNM North did not have a FPPCAC at the time.

The majority of the large customers in the South are home improvement and general

merchandise stores, hospitals, educational and municipal facilities. The South also has a

limited number of residential customers who use an average in excess of 1,000 kWh per

month, which is typical of larger homes or homes that use refrigerated air conditioning.

Further, PNM North has ten times as many customers who have fourteen times as much

usage as the South. Thus small changes in the cost of service and rate design can and will

have a more significant impact on the South customers.

WITH THIS DISPARITY IN RATES

STRUCTURES FOR THE SOUTH THAT

NORTH IN THIS CASE?

IS PNM PROPOSING RATE

ARE MORE SIMILAR TO THE

No. As described later in my testimony, due to the different demographics for PNM

South, the separate cost of service and the specific pricing impact to the PNM South

customer groups makes it difficult to move toward common rate structures and rate

classes at this point. Significant changes in tariff structure on a stand alone basis can

cause a disproportionate change in the individual customer bills for the South’s

customers. For this reason PNM is also not requesting that the pilot decoupling tariff be

applied to the PNM South service area at this time. Instead PNM is recommending only

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specific changes to PNM South’s tariff structure to begin reasonable movement to

consolidated rates in the future.

WHAT TEST PERIOD DOES PNM PROPOSE TO USE IN THIS CASE?

PNM’s filing is based on a Test Period for the calendar year beginning January 1,2011,

with a rate base as of December 31, 2011, including Construction Work In Progress

("CWIP") in the Test Period associated with plant expected to be in service as of March

31, 2012, consistent with the provisions of Sections 62-3-3P and 62-6-14D and E ("SB

477") of the Public Utility Act ("PUA"). In accordance with the requirements of Rule

530, the Base Period is PNM’s actual experience as reflected on its book balance of

accounts for the twelve month period ended December 31, 2009.

Despite the fact that Rule 530 does not provide for a future test period as allowed by SB

477, PNM’s filing complies with the minimum data filing requirements contained in Rule

530. Through the Rule 530 Schedules and accompanying work papers, as well as the

testimony and exhibits of its witnesses, PNM has provided a "linkage" between the Base

Period and the Test Period and otherwise demonstrated the reliability of its Test Period.

The Test Period proposed by PNM best reflects the conditions to be experienced by PNM

during the period when new rates are expected to take effect.

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II. DEVELOPMENT OF REVENUE REQUIREMENTS

A. TEST PERIOD

Q. WHY WAS CALENDAR YEAR 2011 SELECTED AS THE TEST PERIOD?

A. As described by PNM witness Damell, calendar year 2011 captures the majority of the

costs that will be incurred during the first year of operation under the rates approved in

this case.

WHAT TYPES OF ADJUSTMENTS ARE TYPICALLY MADE WHEN

DEVELOPING THE TEST PERIOD REVENUE REQUIREMENTS?

The use of a "historical" or a "future" test period will dictate to a large extent the type

and nature of the adjustments being made. For example, a historical test period examines

investments and operating expenses as they existed in a past period and then has to

include specific adjustments to bring the historical test period closer in time to the

expected future conditions when rates are expected to go into effect. But, because the

concept of a historical test period is founded on the premise that the data must be "known

and measurable," there is a cut-off date for "updating" the historical test period that ends

before the case is even filed, or very shortly thereafter. Thus a historical test period is

never truly made completely current as of the time new rates take effect. And, it must be

remembered, that even though a historical test period is based on actual results, it is

nevertheless a forecast of the future when rates will take effect. Essentially it is founded

on the often incorrect assumption that the past relationship among revenues, expenses

and investments will largely repeat itself in the future.

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The future test period also forecasts the relationship of revenues, expenses and

investment for the period of time when new rates will take effect, but does so using well-

accepted forecasting tools and techniques generally used for business planning purposes.

Although for some categories of operations, historical perIbrmance may provide good

information for predicting the future, a future test period is not constrained by history

where more sophisticated forecasting tools can provide better information. Thus,

especially in times of changing economic conditions, a future test period will be more

representative of the future conditions when rates are expected to take effect and of the

relationship of expected sales, expenses and plant investment than is a forecast using only

historical information, i.e. a historical test period.

AJ

PLEASE DESCRIBE THE TYPES OF ADJUSTMENTS UTILIZED IN THE

DEVELOPMENT OF TEST PERIOD REVENUE REQUIREMENTS.

Adjustments utilized in the development of test period revenue requirements can be

generally classified into four types: annualization, normalization, amortization, and

stipulated. Annualization adjustments are traditionally associated with the use of a

historical test period while normalization adjustments are appropriate with both a

historical test period and a future test period. Amortization and stipulated adjustments to

a test period are typically reflective of past regulatory orders.

¯ Annualization adjustments serve to ensure that both costs and revenues are reflective

of a full twelve-month period. This type of adjustment is typically made to a

historical "per book" time period to capture a full twelve months of expense or

revenue. For example, if employees were given a pay raise four months into the

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historical test period, the payroll costs would be annualized as if the pay raise were in

effect for the entire twelve month period. This is done because the new level of pay

will be that forecasted to be in effect in the future period. Note that this approach,

designed to move the historical test period closer in time to the future period when

new rates will be in effect, then ignores pay raises that occur between the time of

filing the case and implementation of new rates. Typical annualization adjustments

made to a historical test period include annualized depreciation based on the booked

plant in service, payroll based on expected number of employees and customer

growth at year end. These types of adjustments were not made to either the Base

Period or to the Test Period cost of service.

Normalization adjustments ensure that revenue and cost levels in the test period are

representative of normal utility operations. Normalization reflects the timing of

operating expenses that are incurred during the normal operations of a utility over the

course of a year. Further, operations during any particular twelve month period

which constitutes a test period may be an anomaly or otherwise may not properly

reflect the operating conditions during the entire period when new rates will be

effective, which in New Mexico has generally been assumed to average about three

years. These adjustments, for example, adjust revenues or operating expenses existing

in the twelve month period constituting the test period that are not expected to re-

occur annually during the period the proposed rates will be in effect. Normalization

adjustments made to the Test Period cost of service as shown on 530 Schedule K-1

Test reflect the normal expenses expected on an average annual basis for the assumed

period of time when new rates will be effective.

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Amortization adjustments typically reflect expenses or regulatory items that the

Commission has previously determined should be recovered but not in a single year.

Such expenses are amortized over the period the proposed rates will be in effect or in

the alternative a period specified by the Commission. The amortization adjustments

made to the Test Period cost of service as shown on 530 Schedule H-16. The Test

Period includes an amortization of rate case expenses as well as prior approved

treatment of regulatory assets such as those associated with renewable energy credits

("REC").

¯ Stipulated adjustments are necessary to ensure that the company stays in compliance

with all previous regulatory orders and stipulations. These include adjustments such

as the Afion facility transmission costs as directed by the Afion stipulation.

The adjustments described above are shown in 530 Schedule H-16 along with supporting

work papers for each adjustment that has been made.

WHAT IS THE SIGNIFICANCE OF USING A HISTORICAL BASE PERIOD

WHEN USING A FUTURE TEST PERIOD?

In order to demonstrate that a future test period is reliable, utility commissions which

have used future test years have required a demonstration of a "link" between a historical

period and the future test year. This is different from relying on the historical period as

the test period for setting rates. In New Mexico, the Commission’s Rule 530 has

essentially required such a linkage for any type of test period, including a historical test

period. Rule 530 does this by requiring the filing of a base period (an unadjusted, recent

historical twelve-month period) and a test period, with information showing adjustments

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to the base period to arrive at the test period, i.e. the linkage between the two periods.

Rule 530 recognizes that "adjustments" can be "estimates based on projections". This

linkage can be different depending on the nature of the costs involved or the revenues

requested. For example, a forecast of labor costs can be developed to some extent using

inflation factors, cost of living adjustments or expected pay increases, with the historical

period serving as a starting point for the escalation. On the other hand, capital

investments are best forecast by analyzing the need and timing for plant additions, and

then providing an explanation for major variances from the historical period so that the

reasons for the forecasted amounts can be analyzed and their reasonableness and

reliability verified. This explanation then provides the linkage to the historical period. In

this case PNM has gone further in providing a linkage. In demonstrating that the Test

Period best represents the circumstances to be experienced by PNM at the time new rates

take effect, PNM has provided much more supporting information than is generally

provided when using a historical test period.

HAS PNM SHOWN THE LINKAGES FROM THE BASE PERIOD TO THE

TEST PERIOD IN THE RATE FILING?

Yes. My testimony and that of PNM witnesses Patrick Themig, Gary Stone, Shauna

Lovorn-Marriage, Jonathan Lesser, Kenneth Vogl and Earl Robinson, describe in detail

the underlying estimates and rationale for the major drivers in the requested revenue

increase. The Exhibits in my testimony and that of PNM’s other witnesses, the 530

Schedules in the rate filing, and associated work papers provide both the linkage and

rationale for the adjustments made in the filing from the Base Period to the Test Period.

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In addition, PNM has included a line item comparison of the Base and Test Period cost of

service calculation for Total PNM Electric (which includes the FERC jurisdiction), PNM

North, and PNM South in 530 Schedule H-16, including all supporting work papers.

HOW HAS PNM PROVIDED THE LINKAGE FROM BASE PERIOD TO THE

TEST PERIOD FOR NET PLANT?

As described by PNM witness Richard Starkweather, ScottMadden performed a capital

project review by specific project to validate the underlying investment and operational

justification for those capital investments initiated by PNM. Plant in service as of the end

of the Test Period is based on the capital investments projected to be in service by the end

of the Test Period. A listing of these plant additions, along with a project description and

rationale for the investment, is provided in PNM Exhibit JAM-3. Each of the capital

investments have been functionalized as production, transmission, distribution, or general

and intangible and then categorized into its appropriate plant utility FERC accounts based

on function. Accumulated Reserve was then calculated for these additions beginning with

project in service date through the end of the Test Period. In addition, PNM rolled

accumulated reserve forward to the end of the Test Period for plant balances as of

December 31, 2009. The Test Period calculation of Gross Plant, Accumulated Reserve,

and Net Plant utilizing this methodology is shown in 530 Schedule H-16 and the

supporting Net Plant work papers. A further description of these projects and the

rationale for the investment is included in the testimonies of PNM Witnesses Themig and

Stone.

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TEST PERIOD FOR OTHER RATE BASE ITEMS?

As shown in 530 Schedule H-16 and supporting work papers, PNM has rolled the

December 31, 2009 balance forward for all other rate base items to the end of the Test

Period. This includes items such as Accumulated Deferred Income Taxes as further

described by PNM witness Matthew Harland. PNM has calculated all required

adjustments to reflect prior orders and included additional rate base items as necessary,

such as rate case expenses and REC regulatory assets, as discussed later in my testimony.


TEST PERIOD FOR O&M?

As described by PNM witness Starkweather, ScottMadden performed a detailed review

of the individual cost centers and FERC primary account for operations and maintenance

expense for the rationale and justification for any non-fuel change in excess of $1

million. With ScottMadden’s assistance, PNM utilized historical financial and prospective

budget data to compare the Base Period costs with the 2010 and 2011 budgets for FERC

accounts 500 through 935 exclusive of fuel. PNM then researched any accounts with

variances greater than $1 million.

2010-2014 budget cycle the

As described by PNM witness Starkweather, for the

business areas developed additional supporting

documentation for O&M costs, including explanations by cost type for any significant

increases for 2010 and 2011. PNM first reviewed this budget documentation and then

conducted follow-up meetings with the Corporate Budget Department and business unit

representatives to document explanations, and obtain supporting information, for the

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FERC accounts with the $1 million variances. PNM has provided the variances between

Base and Test Period cost of service by primary FERC account in 530 Schedule H-16. In

addition, PNM has included a detailed explanation of all variances greater than $1 million

between Base Period and Test Period O&M utilizing the ScottMadden analysis. Fuel was

not included given the recent FPPCAC audit conducted by the Commission, the FPPCAC

factor adjustment that PNM has recently filed to implement in July, 2010 for PNM North

and since PNM is only requesting a base fuel adjustment to reclassify fuel and waste

handling and spinning reserves between non-fuel and base fuel revenues. PNM has

provided the variance between Base and Test Period cost of service by primary FERC

account in 530 Schedule H-16. Further, in PNM Exhibit JAM-4, I have detailed the

annualized kWh sales from the most recent rate case, Base Period kWh as of December

31, 2009, and the forecasted kWh for the Test Period.

DO YOU HAVE ANY OTHER OBSERVATIONS OR FINDINGS FROM YOUR

REVIEW OF THE PLANT ADDITIONS AND OPERATING EXPENSES?

Yes. PNM has conducted a more extensive analysis of the costs included in the Test

Period than what is typically required for a historical test period. As previously noted, a

historical test period reflects the actual operating experience of the Company as recorded

on its books with limited adjustments as I have described previously. The examination of

the historical test period is conducted to determine what adjustments must be made to

bring the historical operating experience closer in time to the expected conditions of the

Company when rates go into effect.

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Rarely is documentation or a review done for each cost center of the Company or each

underlying individual expense that was incurred in the historical test period. In contrast, a

future test period relies on the forecast and budgeting process of the Company. As

described by PNM witness Starkweather, this process provides underlying source

documents or estimates by each of the Company’s operating cost centers and for FERC

primary accounts that make up the operating expenses and plant additions shown in the

Test Period. It allows for a direct "line of sight" to exist between the cost of service and

the underlying home center budget documentation for the expense or plant addition in the

cost of service. Thus, unlike a historical test period, we developed a detailed

reconciliation of the cost of service forecasted results using PNM’s budget

documentation and other supporting records. This documentation provides a link between

the Base Period and the Test Period with the rationale for the major changes or

adjustments. Further, this documentation provides both the underlying development and

the rationale for the cost of service request by FERC primary account in the Test Period.

As a result, the documentation for the Test Period goes further in analysis and provides a

greater degree of underlying support than in prior cases relying on a historical test period.

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B. SUMMARY OF OVERALL REVENUE REOUIREMENTS

PLEASE IDENTIFY THE BUSINESS AREAS WITHIN PNM TO WHICH THE

TOTAL ELECTRIC COST OF SERVICE IS ALLOCATED.

Consistent with past rate cases, PNM’s total electric revenue requirements are allocated

as follows:

¯ PNM North;

¯ PNM South;

¯ FERC;

¯ Excluded, Merchant and Other which includes Palo Verde Nuclear Generating

Station ("PVNGS") Unit 3.

Again, as noted above,’the sum of PNM North and PNM South is not the revenue

requirement that would be requested if a consolidated cost of service was presented.

Because of changing the jurisdictional allocators, the revenue would be different.

PLEASE DESCRIBE THE JURISDICTIONAL ALLOCATORS USED IN THIS

CASE.

The 530 Schedule M-2 describes the jurisdictional allocators. PNM utilized the

forecasted kWh sales for the demand and energy allocators fi~r the Test Period. Demand

was prorated using 2009 peak demands. PNM has consistently used 12 Coincident Peak

(CP) allocation for the base load units of PNM North as well as the 12 CP method for the

allocation of the gas units except for Af~on. The fixed and non-fuel operating costs for

Aiton have been assigned 50% to PNM North and 50% to PNM South with no allocation

to the FERC firm wholesale customers as is done with the other generation units.

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Transmission costs were allocated to PNM North, South and FERC using a 12 CP

transmission peak allocation. The Afion transmission investment has been capped at $3.0

million for PNM North and at $2.9 million for PNM South per the Afion Stipulation.

The distribution investment and related costs as well as customer billing and customer

service costs have been directly assigned to each of the two retail service areas.

WHAT ARE THE BASE PERIOD REVENUE REQUIREMENTS?

The PNM North Base Period revenue requirements excluding revenue credits total

$809,327,398. PNM South Base Period revenue requirements excluding revenue credits

total $68,220,327. Both calculations are included in 530 Schedule K-1 Base for the Base

Period cost of service. These revenue requirements include $171,183,589 associated with

base fuel costs and $638,143,809 associated with non-fuel requirements for PNM North

and $15,437,860 associated with base fuel costs and $52,782,467 associated with non-

fuel requirements for PNM South. PNM calculated a base fuel expense for PNM South

based on the stipulated allocation of fuel expense for the Base and Test Periods used in

this case.

IS THE TEST PERIOD REVENUE REQUIREMENT INCREASE SIMPLY THE

DIFFERENCE BETWEEN THE BASE PERIOD REVENUE REQUIREMENT

AND THAT OF THE FUTURE TEST PERIOD?

No. The Base Period is the unadjusted O&M expenses and rate base as of December 31,

2009. Historical expenses have not been adjusted in the Base Period nor have sales been

adjusted to reflect changes in customer growth or use. The increase in revenue

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NMPRC UTILITY CASE NO. 10-00086oUT

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requirement is the difference between the Test Period cost of service and the revenues

applied to forecasted sales and billing determinants for that same forecasted period. This

is similar to what is done for a historical test period where annualized revenues are

forecasted using year-end customer growth and use, and the existing rates.

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WHAT ARE THE TEST PERIOD REVENUE REQUIREMENTS?

Table JAM-1 below provides a summary of the Test Period revenue requirement for

PNM North and PNM South. In addition to these revenue requirements, PNM is seeking

Commission approval of a FPPCAC for PNM South. For the Test Period revenue

requirements for PNM South, PNM has established the base fuel costs using projected

fuel costs for the twelve month period ending December 31, 2010.

Non’fuel Revenue Requirement (w/o I&S Fees)Base Fuel Revenue RequirementTotal Revenue Requirement as requested

PNM Noah PNM South675,145,091 51,527,861171,107,948 21,340,009846,253,038 72,867,870

Fue!Factor-july 2010 adjustment PNM North ............. 18,126,088I&S Fees ............................................. 4,282,046 ......... 368 712Miscelleneous ServiceCharges and Revenues............ 1,475 588 2,662,653T°talRetai!Revenue Requirement ...........................870136,76! ...... ..... 75,899,235 .....

Fuel Factor ’ July 201 i adjustment PNM South .................(subject to change)..................................... - ..... 4 687 285Miscellaneous Revenue Credits ........ 12 716,212 819,965Total Revenue Requirement (fuel and non-fuel) 882,852,973 81,406,486

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PLEASE EXPLAIN THE MAJOR ELEMENTS OF THE REVENUE

REQUIREMENTS DEMONSTRATED BY THE TEST PERIOD.

PNM Exhibit JAM-5 provides a summary of the major revenue requirement elements that

make up PNM’s request. Included in the Exhibit is a listing of the operating expense and

rate base items that PNM is requesting. On page 2 and page 6 of the Exhibit is a listing of

the significant changes in Plant in Service as well as CWIP. Gross plant additions plus

CWIP for Total Electric before allocations from the end of the Base Period to the end of

the Test Period total $444 million (PNM Exhibit JAM-3).

PNM North’s share of gross plant plus CWIP additions from December 31, 2009 through

the end of the Test Period total $316.3 million and is made up of $151.9 million for

generation, $52.5 million for transmission, $81.6 million for distribution and $30.3

million for general and intangible plant. PNM South’s share of gross plant plus CWIP

additions from December 31, 2009 through the end of the Test Period total $22.5 million

and are made up of $6.7 million for generation, $6.1 million for transmission, $7.0

million for distribution and $2.7 million for general and intangible plant. The plant

additions as well as the new depreciation study have also increased depreciation expense

and property taxes over the Base Period. A more detailed discussion of these projects is

provided by PNM witnesses Themig and Stone. In addition to plant additions, PNM’s

Benefits costs are increasing. Post retirement medical expenses have increased a total of

$6.2 million over the Base Period and pension expense is increasing $15.3 million over

the Base Period. PNM is required to make additional contributions to the Pension Trust

in accordance with the Pension Protection Act of 2006. As a result of these large

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contributions PNM’s pension expense is expected to increase. PNM witnesses Ken Vogl

and Shauna Lovorn-Marriage describe PNM’s pension costs in more detail. The Post-

Retirement Medical Costs increase is due to the fact that interest rates are projected to

decrease in the near term resulting in lower returns to the trust. This is compounded by

asset losses, particularly the large 2008 losses that are being recognized over a five year

period.

PNM’s plant scheduled maintenance costs also make up a significant portion of the

overall revenue requirement that PNM is requesting. Although comparable to the Base

Period, scheduled maintenance costs are significantly higher than prior years and as a

result these costs are not being adequately recovered in existing base rates. Plant

scheduled maintenance costs tend to vary from year to year with the timing of the

scheduled maintenance. As described by PNM witness Themig, PNM is proposing to

recover scheduled maintenance expenses on a normalized basis by averaging the annual

expenses for 2011 through 2013. The associated adjustment is included in 530 Schedule H-

16 and associated work papers.

The forecasted Distribution and Transmission O&M and Management Fee costs are

relatively flat when compared to Base Period amounts. A detailing of the variance is

explained in PNM Exhibit JAM-5 as well as 530 Schedule H-16 along with supporting

work papers.

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WHAT IS THE COST OF CAPITAL AND RETURN ON EQUITY THAT YOU

HAVE APPLIED TO THE RATE BASE IN THIS CASE?

PNM is using an overall weighted cost of capital of 9.43% as described further by PNM

witness Terry Horn. PNM’s requested return on equity is 11.75% as explained by PNM

witness Robert Hevert. As further described by PNM witness Horn, the weighted cost of

debt in the capital structure has been adjusted to reflect financings that will occur

between now and when rates are effective in 2011.

WHAT ADJUSTMENT TO RATE CASE EXPENSES IS PNM PROPOSING TO

RECOVER IN THIS PROCEEDING?

PNM is making an adjustment to rate case expenses to add projected rate case expenses

to be incurred in the present rate case. PNM is seeking recovery of $2.4 millior~ as is

detailed in PNM Exhibit JAM-6. Rate case expenses have been allocated $2,103,854 to

PNM North and $321,280 to PNM South. These expenses represent a special category of

expense that is recoverable as a part of a utility’s cost of service. It is a rate base

adjustment because the total amount of rate case expenses allowed for recovery is

amortized over a three year period, consistent with past treatment by the Commission. At

this time, I am providing a projection of rate case expenses in PNM Exhibit JAM-6, and

will update this projection in an exhibit which I will file prior to the commencement of

the hearing in this case. The new exhibit will reflect expenses incurred up through that

date and a projection of the costs to be incurred through the remainder of the case.

PNM’s goal is to provide the Commission with as timely and accurate a statement as we

can of the rate case expenses incurred in connection with this case. The total adjustment

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is an increase of $1.9 million over the Base Period deferred amount. PNM has included

one year of the three year amortization in O&M.

HOW WAS THE RATE CASE EXPENSE ESTIMATE DERIVED?

This case involves numerous complex issues including filing for a future test period for

the first time pursuant to SB 477. As a result, many of these issues will be reviewed for

the first time and therefore the costs of preparing and potentially litigating this rate case

are significant. Since this is the first time a future test period according to SB 477 is being

used, PNM has undertaken the significant effort to fully document and track to both the

FERC primary account and individual cost center the underlying rationale and cost

estimate for both the forecasted operating expense and plant investment. This has

required PNM to utilize outside expertise such as the ScottMadden firm. PNM has taken

action to control these costs to the extent possible consistent with the need for thorough

and effective presentation of PNM’s positions. A significant amount of preparation of the

case has been done by in-house PNM employees. Despite the requirements for the

preparation of the future test period, costs between this case and the last case are similar.

The proper handling of this case includes the assignment of qualified in-house counsel to

oversee and participate in proceedings, and qualified outside counsel with substantial

experience with the PUA, and with regulatory law in general, to efficiently and

effectively assist in this proceeding. PNM witness Carol Graebner describes in more

detail the steps PNM has undertaken to control legal costs generally. In addition, it is

both cost-effective and necessary to retain outside experts who have subject matter

expertise not available in-house on specific issues inherent in complex rate proceedings

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that involves as many issues as this case. Robert Hevert was hired to provide expert

financial evaluation and testimony concerning the cost of capital and the appropriate

capital structure for ratemaking purposes, which are the main components in a rate of

return determination. Earl Robinson was hired to provide testimony in support of the

new depreciation rates which PNM proposes to implement. PNM hired ScottMadden to

assist with the documentation and development of processes that are necessary to both

prepare and justify the use of a future test period. PNM retained Steven Fetter to provide

the benefit of his unique combination of experience as a state utility commissioner and

with a credit rating agency to help provide perspective surrounding PNM’s proposals in

this case. PNM hired Dr. Jonathan Lesser to provide an independent load forecast and

perform the required price elasticity study. Also, 17.9.530.1~3Q(6) NMAC requires that

PNM submit an opinion of an independent certified public accountant stating that an

independent examination of the book amounts and accounting adjustments of PNM’s

books and records has been made for the Base Period and that the results thereof are in all

material respects in compliance with the Uniform System of Accounts prescribed by the

Commission. The accounting firm of Deloitte & Touche provided this opinion. The

costs included in the projected rate case expenses for this case are necessary and

reasonable due to the number of expected parties and witnesses, the anticipated level of

discovery, the length of the hearing and the complexity of the issues. Combining the rate

cases for PNM North and PNM South has eliminated unnecessary duplication of time,

effort and resources that would have otherwise occurred had the rate cases been filed

separately.

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PLEASE EXPLAIN PNM’S TREATMENT OF RATE BASE COSTS FOR

RENEWABLE ENERGY.

Per the 3137 Stipulation, PNM has been allowed to treat RECs and other renewable

energy assets as a regulatory asset for recovery in general rate cases. PNM has continued

to do so in this filing. The regulatory asset in this filing amounts to $712,667 and includes

Renewable Portfolio Standard ("RPS") compliance costs incurred since 2009. These

costs include RECs purchased in PNM’s small and large photo-voltaic ("PV") programs

and REC purchases from Southwestern Public Service Company ("SPS"). PNM has not

included in the revenue requirement for this case resources or RECs associated with the

supplemental Renewable Energy Plan ("REP") pending Commission approval in Case

No. 10-00037-UT ("REP Case").

The treatment of renewable energy resources under the 3137 Stipulation may be changed

effective one year after conclusion of this case. It is expected that new rates as a result of

this case will go into effect April 1, 2011. PNM intends to book additional renewable

assets acquired as a result of the Commission’s decision in the REP Case as regulatory

assets pursuant to the 3137 Stipulation for recovery within 36 months after acquisition.

PNM further intends to make a separate filing seeking implementation of a renewable

energy rate rider to be effective April 1, 2012, as allowed by the 3137 Stipulation.

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c. REVENUES



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WHAT ARE THE TEST PERIOD REVENUES UNDER EXISTING RATES?

To derive Test Period revenues, revenues were forecasted to reflect Test Period

customers for both PNM North and PNM South. The Test Period revenues for PNM

North reflect base fuel revenue at the current system rate of $0.020123 per kWh. I have

also shown in both PNM Exhibit JAM-5 and 530 Schedule A-1 the FPPCAC factor

adjustment that PNM is proposing to implement in July, 2010. PNM has calculated a fuel

and purchased power cost in the existing rates of PNM South that is reflective of costs

forecasted for 2010. The fuel and non-fuel revenues for PNM South are based on the

calculated fuel and purchased power cost. The base fuel rate being proposed for PNM

South is $0.0379673/kWh. Table JAM-2 reflects forecasted revenues for PNM North

and PNM South.

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PNM NorthForecasted Non-Fuel Revenue (excluding I&S

Fees) 535,815,367Forecasted Fuel Revenue 158,355,132Total Forecasted Base Revenues at Existing Rates 694 170,499

PNM South

39,345,35021,266,62760,611,977

I&S FeesFL el Factor - effective July 2010 PNM NorthMiscellaneous Service Charges & RevenuesTctal Forecasted Base Revenues

3,512,50718,126,088

1,475,588717,284,682

306,697

2,662,65363,581,327

FLel Factor effective July 2011(subject to change)Mi=.;cellaneous Revenues CreditsTotal Forecasted Revenues

PNM South

12,716,212730,000,894

4,687,285819,965

69,088,578

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PLEASE PROVIDE AN EXPLANATION FOR PNM’S FORECASTED SALES

(KWH), REVENUES, AND REVENUE CREDITS FOR THE TEST PERIOD.

PNM’s forecasted energy sales for 2011 are described in PNM witness Lesser’s

testimony. Dr. Lesser prepared the detailed forecast for the Test Period for the

Residential, Irrigation, Small Power, General Power and Large Power (just Commercial)

classes. These classes represent approximately 80% of PNM retail kwh sales. For the

remaining classes, Dr. Lesser reviewed the internal forecast and found them to be

reasonable. Dr. Lesser’s study includes PNM’s projected energy savings from energy

efficiency programs. PNM Exhibit JAM-7 contains a summary of forecasted sales for the

Test Period. Column A of this Exhibit has Dr. Lesser’s forecast for the classes he

describes in his testimony. Dr. Lesser’s high-level forecast is split into PNM North’s rate

classes so proper revenues can be estimated (Column D) including the internal forecasts

reviewed by Dr. Lesser. Column E, "Energy Efficiency Reductions", are reductions in

energy sales due to PNM’s various energy efficiency programs. The last column of this

table (Column G) has the blended forecasts that are the basis of the Test Period forecast.

DID DR. LESSER FORECAST THE IMPACTSOF ENERGY EFFICIENCY

PROGRAMS?

As noted by Dr. Lesser in his testimony, he did notforecast the impacts of energy

efficiency programs but relied on PNM’s forecast ofthe energy savings from these

programs.

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HOW HAS PNM ESTIMATED THE IMPACTS OF THE ENERGY SAVINGS

FROM THE ENERGY EFFICIENCY PROGRAMS?

PNM forecasted energy savings for each of its energy efficiency programs. The forecast

for each program is based on past participation and on the actual energy savings achieved

in 2008 and participation in the programs during the first half of 2009. PNM determined

the historical savings per commercial rate class using account numbers of participating

customers. The geographic distribution for residential customers, those in the PNM North

and PNM South areas, was determined through analysis of participant account numbers

and addresses, and through retailer sales records. The historical distribution by rate class

was applied to the forecasted energy savings to determine the impacts by rate class in the

Test Period.

ARE THERE MATERIAL DIFFERENCES THAT HAVE OCCURRED IN PNM’S

RETAIL SALES SINCE THE LAST RATE CASE?

Yes. The retail sales amount between the unadjusted Base Period kWh sales and the Test

Period kwh forecast are within 1% of each other. However, there has been a significant

change since the test period used in the 2008 Rate Case. The test period used in that case

was the twelve month period ending March 31, 2008, a fully adjusted Historical Test

Year Period consistent with prior Commission practice. In PNM Exhibit JAM-4, I have

shown the differences in energy sales using: a) annualized sales for the 2008 Rate Case

(phase II); b) Base Period sales; and c) the forecasted sales for the Test Period. In the

Exhibit, the decline in residential and industrial sales can be readily seen from the 2008

Rate Case Historical Test Year Period to the Base Period in this case. The decline in

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sales can be attributed to the loss of significant industrial customers on PNM’s system,

changing average use in the Residential, Small Power, General Power and non-industrial

Large Power customers, including the impact of the recession, weather and energy

efficiency. The significant change from the Historical Test Year Period used in the 2008

Rate Case to the Base Period in this case, part of the time frame when rates set in the

2008 Rate Case were in effect, is an example of how the use of a historical test period,

even when fully adjusted, can fail to reasonably forecast future operating conditions

during a time of changing economic conditions due to the limited adjustments allowed in

a historical test period. A sales forecast such as was done by Dr. Lesser for this case,

does not suffer from the same constraints and so is better able to consider evolving

economic conditions that can have a significant impact on the accuracy of the forecast.

Further, the significant change in residential sales and average customer use as a result of

energy efficiency underscores the rationale for my later proposal to implement a

decoupling tariff.

HOW IS THE COMPANY TREATING PNM SOUTH RATE 9 - INDUSTRIAL

POWER SERVICE AND RATE 11 -ECONOMY SERVICE-INDUSTRIAL

POWER SERVICE IN THIS CASE?

The Company is treating the revenues associated with these tariffs as a credit to the cost

of service of the PNM South rate classes. This results in an offset to their revenue

requirement of $3.0 million in the Base Period, and $2.5 million in the Test Period. Both

of these tariffs provide indirect access service to a very large single customer, who is

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unique in that PNM does not provide either generation or energy service through its

jurisdictional assets. Generation and energy service is procured in the market by contract

on behalf of that customer. This unique "buy through" arrangement pre-dates PNM’s

acquisition of the TNMP service territory in New Mexico. The tariff costs are reflective

of billing, customer service, transmission and backup service as needed. PNM has seen

dramatic changes in the level of energy and demand actually purchased and delivered to

this customer over the last two years. This has reflected the significant change in the

economy and demand for the customer’s product. This relationship, coupled with the fact

that the current rate levels closely reflect the cost of service ~br this arrangement, are the

reasons that PNM has chosen to treat the revenues from this customer as a revenue credit

to the other PNM South customers. Given the unique nature of service and the fact that

the fixed costs dedicated to this customer to provide for the delivery of the third party

purchases are relatively unchanged, it is reasonable to leave the rate levels unchanged and

to treat those revenues as a credit to the PNM South cost of service.

D. RATE BASE

Q. PLEASE DESCRIBE THE ADJUSTMENTS THAT WERE MADE TO RATE

BASE TO ARRIVE AT THE TEST PERIOD COST OF SERVICE.

A. The rate base adjustments made to arrive at the Test Period cost of service include

adjustments to: Plant, Accumulated Deferred Income Taxes, Regulatory Assets and

Liabilities, Miscellaneous Deductions and Additions, CWIP, and Working Capital.

These adjustments are included in the 530 Schedule H-16 along with supporting work

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papers. Also, I have described and detailed in PNM Exhibit JAM-3 the individual list of

projects that are being requested as plant additions for the Test Period.

HOW HAS PNM TREATED CWIP IN THIS PROCEEDING?

PNM has included the December 31,2011 CWIP balances for those projects that will be

in-service by March 31, 2012. Plant that is expected to be placed in service during the

Test Period does not accrue Allowance for Funds Used During Construction ("AFUDC").

PNM Exhibit JAM-3 identifies the individual CWIP projects and amounts being

requested.

WHAT ADJUSTMENT IS PNM PROPOSING FOR RECS?

As mentioned previously in my testimony, PNM is including

associated with RPS compliance costs incurred since 2009.

purchased through PNM’s Large and Small PV programs

included carrying charges for this purchase at a rate of 8.64% and is amortizing the asset

over three years as provided in the Case 3137 Stipulation.

a regulatory asset

The costs include RECs

and from SPS. PNM has

ARE THERE OTHER CHANGES TO RATE BASE IN THE TEST PERIOD?

Yes. These adjustments are described in the testimony of PNM witnesses Lovorn-

Marriage and Harland.

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E. FUEL EXPENSES

FNM NORTH

WHAT IS PNM REQUESTING FOR PNM NORTH FUEL?

PNM is requesting one adjustment to the current base fuel costs - a reclassification of

costs associated with fuel and waste handling and purchase of spinning reserves from

non-fuel base revenues to fuel base revenues. For purposes of inclusion of total costs,

and to reflect the existing FPPCAC adjustment factor in rates, I have shown in 530

Schedule A-1 and PNM Exhibit JAM-5 the FPPCAC factor that PNM is proposing to

implement on July 1, 2010. This factor is based on the current annual update cycle that

will run from July 1, 2010 through June 30, 2011. The current annual update cycle

reflects over and under recoveries of fuel and purchased power costs as compared to the

existing base fuel rate of $.002303 per kwh for the period of July 1, 2009 through June

30, 2010, plus a reforecast of fuel and purchased power for the period of July 1, 2010

through June 30, 2011. Per the stipulation approved in the 2008 Rate Case, carrying

costs for monthly over-recoveries are based on the pre-tax weighted average cost of

capital of 11.66% approved in the 2007 Rate Case. The weighted average cost of debt of

3.02% from the 2007 Rate Case is used for monthly under recoveries.

WHAT TIME FRAME HAS BEEN USED TO DETERMINE BASE FUEL FOR

THE TEST PERIOD?

PNM used the July 1, 2010 through June 30, 2011, time frame to determine the

appropriate base fuel rate which is consistent with the period that will be used to reset the

FPPCAC factor on July 1, 2010.

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WHY IS PNM SEEKING TO RECLASSIFY FUEL HANDLING AND WASTE

DISPOSAL AS BASE FUEL COSTS FOR PNM NORTH RATES?

The costs for coal handling and ash disposal are direct costs associated with the use of

coal to produce power and vary directly with the quality and quantity of coal used in the

production of energy. Waste disposal associated with nuclear fuel is required by the

Nuclear Regulatory Commission to assure the safe handling of the waste products. These

costs vary directly with the quantity of fuel expended.

WHAT CHANGES IS PNM PROPOSING FOR SPINNING RESERVES?

The purchase of spinning reserves had historically been included in base fuel for PNM

North until the 2008 Rate Case, which implemented provisions from the Stipulation

approved in Case No. 08-00305-UT ("Resources Stipulation"). In that case it was agreed

that demand costs associated with long term purchased power contracts not be included

in the base fuel calculation except for two contracts that were to expire in the near term.

PNM then excluded the purchase of spinning reserves with other demand costs in that

case. However, the 2008 Rate Case reaffirmed that cost elements contained in FERC

Account 555 would be recovered through the FPPCAC. The purchase or use of on-line

generation for spinning reserves is an economic decision based on market and fuel prices

at the time. The source and cost of spinning reserves vary from month to month and, to

assure the customer pays the proper amount for reserves, all costs should flow through

the FPPCAC. Thus they should not be considered to be demand costs associated with

long term purchased power contracts. PNM is requesting that both PNM North and PNM

South’s base fuel costs reflect the addition of the cost for spinning reserves.

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DOES RULE 550 ALLOW FOR THE RECOVERY OF THESE COSTS AS FUEL

AND PURCHASED POWER COSTS?

Yes it does. 17.9.550.22 NMAC Appendix provides the FERC accounts that are allowed

in the fuel and purchased power cost calculation. These include FERC Accounts 501,

518 and 555. Fuel handling, fuel disposal and ash disposal are included in accounts 501

and 518. Purchase of spinning reserves is included in Account 555. Therefore, fuel

handling and ash disposal and purchases of spinning reserves are a portion of "the

amount actually expended for fuel and purchased power" and are appropriately a part of

base fuel rates. This was confirmed in the 2008 Rate Case Stipulation.

HOW HAS PNM CALCULATED THE NEW BASE FUEL COST FOR PNM

NORTH?

The current base fuel cost of $.020123/kWh has been increased to reflect the additional

cost of fuel and waste handling and spinning reserves included in the cost of service for

the Test Period. This results in a base fuel rate of $.021744/kWh.

IS PNM RECOMMENDING A NEW FPPCAC ADJUSTMENT FACTOR FOR

PNM NORTH IN THIS CASE?

No. PNM is recommending that the resetting of the annual FPPCAC factor continue on

the current schedule, i.e. each July 1. PNM has shown in its summary cost of service

revenue requirement as well as my summary revenue requirement in PNM Exhibit

JAM-5 what the proposed FPPCAC factor for July 1, 2010 to June 30, 2011 is for PNM

North. PNM will file for a new FPPCAC factor to be implemented on July 1,2011.

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HAS THERE RECENTLY BEEN AN AUDIT OF PNM NORTH’S FPPCAC?

Yes. In accordance with the Final Order in Case No. 08-00092-UT ("FPPCAC Order")

the Commission retained Schumaker & Co. to conduct an extensive audit of PNM’s fuel

costs and purchasing and operating practices to assure that PNM would collect only

reasonable and actual costs through the FPPCAC. The Audit Report has been filed in

Case No. 08-00030-UT and responses to the Audit have been filed by PNM and Staff.

IS PNM PROPOSING TO COLLECT THE COSTS ASSOCIATED WITH THIS

FPPCAC AUDIT?

Yes. As provided for in the FPPCAC Order, PNM has included the costs of the FPPCAC

audit in the amount of $394,757 in Test Period O&M expenses. Because the Audit was

ordered as a result of authorizing a FPPCAC for PNM North, all the costs were assigned

to PNM North.

PNM SOUTH

WHAT IS PNM REQUESTING FOR PNM SOUTH BASE FUEL COSTS?

Based on 2010 projected costs, PNM has calculated base fuel costs and a base fuel rate

per kWh for the forecasted 2011 sales using existing rates. Using this base fuel rate,

PNM is proposing also to implement a FPPCAC for PNM South customers using the

same methodology employed for PNM North customers with the exception that carrying

charges on over- and under-recoveries should be symmetrical using the pre-tax weighted

average cost of capital ("WACC") in this case.

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WHY HAS PNM CALCULATED A BASE FUEL RATE FOR PNM SOUTH?

To determine an appropriate allocation between base fuel costs and non-fuel base costs in

existing rates, PNM utilized the stipulated allocation of the gas generating units as well as

purchased power costs for calendar year 2010 to calculate what the fuel costs should be.

PNM South existing rates are based on the TNP Stipulation. The 3137 Stipulation, the

Alton Stipulation and the Resource Stipulation specifically allocate resources to PNM

South. The stipulated generation resources and their related energy costs are being used

to set the base fuel rate for PNM South.

PLEASE DESCRIBE THE METHODOLOGY CURRENTLY APPROVED FOR

PNM NORTH THAT WILL BE USED FOR THE CALCULATION OF PNM

SOUTH BASE FUEL COSTS.

Using hourly data after the fact, the energy from all resources are allocated each hour to

PNM North, PNM South, FERC and Other. The energy, by jurisdiction, is compared to

total load and losses for each jurisdiction. If there are excess resources, those resources

are assumed to be sold at market prices for that hour. If there is a shortfall of resources, it

is assumed that purchases are made from the market for that hour. So, if PNM North

resources are used to serve PNM South load in any hour, PNM North customers receive a

sales credit against the cost of fuel. PNM South customers pay for that energy as though

it was purchased from the market.

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DOES THIS MEAN PNM SOUTH RETAINS 50% OF THE ENERGY OUTPUT

OF THE AFTON STATION TO SERVE PNM SOUTH LOAD?

Yes, PNM South retains 50% of Afion Station’s energy output in terms of energy

allocation and accounting. Fifty percent of the output and the associated fuel cost for

Alton are allocated to PNM South. If that energy is not needed specifically to serve

PNM South load, then PNM accounts for the remainder of the energy as an intra-

company transaction where it is priced to PNM North at the prevailing market price or

sold into the market. PNM South fuel costs are then credited for this excess. That does

not mean, however, that 50% of the energy produced at Afion is necessarily physically

delivered to PNM South. When Afion is running, power is dispatched to the total system

load. Since PNM acquired the New Mexico assets of TNMP, PNM has been operating

both North and South as one system. For purposes of dispatching units to serve load,

planning for resources to serve the system, and in operating the system, PNM North and

PNM South, as well as PNM’s other loads, are treated as one system without distinction

to the resources that are utilized to serve customers.

HOW HAS PNM DETERMINED THE BASE FUEL COST FOR PNM SOUTH?

The base fuel rate for PNM South was based on the forecasted fuel cost for calendar year

2010. These costs include PNM South’s share of Afion, Luna, Lordsburg, Valencia and

other purchased power as well as a credit for off-system sales. The methodology to

determine the costs is consistent with the calculation of base fuel costs for PNM North as

determined in the 2008 Rate Case including the credit for off-system sales.

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WHY IS PNM USING CALENDAR YEAR 2010 TO SET ITS BASE FUEL COST

FOR PNM SOUTH RATHER THAN THE TEST PERIOD OF 2011?

Resources used to serve PNM South customers are either owned gas resources or market

purchases. The costs for these resources constantly fluctuate and are incapable of precise

determination into the future as recent events have shown, supporting the need for a

FPPCAC. Forward market prices are not necessarily a good indicator of future spot

prices and become less reliable further out in time. PNM is proposing to recover fuel and

purchased power costs for PNM South by using a base fuel rate and an annual FPPCAC

factor which will result in PNM collecting only actual costs of fuel and purchased power

through the use of a balancing account as is the case with PNM North. PNM is proposing

to set the initial FPPCAC factor to zero. The base fuel rate becomes the measurement by

which monthly over or under recoveries against actual fuel and purchased power costs

are determined. The annual FPPCAC factor that is implemented each July accounts for

any difference between projected and actual expenses. The base fuel rate should be set

using a reasonable number that is relatively stable and at a level that should not typically

result in a significant monthly over or under recovery. By setting the base fuel rate using

calendar year 2010, PNM has attempted to both capture the recent low historical gas

prices as well as to move closer to what the anticipated market prices for gas are in 2011.

The FPPCAC will adjust for any over or under recovery resulting from the setting of the

base fuel rate.

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WHY IS PNM PROPOSING A FPPCAC FOR PNM SOUTH?

Under current circumstances, the South is subject to even greater volatility in prices for

its fuel costs than that of the North. For ratemaking purposes, PNM South currently relies

on natural gas resources and power purchases at market rates for 100% of its energy

supply. The costs of gas and purchased power fluctuate frequently which means that the

costs of fuel and purchased power for PNM South cannot be precisely determined in a

general rate case. In addition, these costs represent a significant percentage of PNM

South’s total cost of service such that even slight variations in the kWh cost can have a

material effect on PNM South’s earnings. A FPPCAC is the most effective way to match

fuel and purchased power costs with revenues so that customers pay only for the actual

fuel and purchased power costs allocable to PNM South.

DOES PNM’S FPPCAC PROPOSAL SATISFY THE PURPOSES OUTLINED IN

RULE 550?

Yes, the FPPCAC proposed for PNM South is consistent with the objectives of Rule 550,

including providing for adequate regulatory review of a utility’s operations under the

FPPCAC; providing for the stability of utility earnings when electric fuel costs and

purchased power costs are rising and permitting prompt credits to customers when

electric fuel costs and purchased power costs are declining; assuring that PNM collects

through the FPPCAC the amount actually expended for fuel and purchased power; and

allowing the flow-through to electric customers of the increases or decreases in costs of

delivered energy above or below a base cost of fuel and purchased power.

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WHAT ARE THE FILING REQUIREMENTS UNDER RULE 550 WHEN A

UTILITY SEEKS APPROVAL OF A FPPCAC?

Rule 550, Section 17, provides that a utility seeking to have a FPPCAC included in its

tariff shall submit testimony showing that all the purposes stated in Rule 550, Section 6,

above, are met and that:

1. the cost of fuel and purchased power are a significant percentage of the total cost

of service;

2. the cost of fuel and purchased power contains costs which periodically fluctuate

and cannot be precisely determined in a rate case; and

3. the utility’s fuel and purchased power policies and practices are designed to

, assure that electric power is generated and purchased at the lowest reasonable

cost.

ARE PNM SOUTH’S COSTS OF FUEL AND PURCHASED POWER A

SIGNIFICANT PERCENTAGE OF ITS TOTAL COST OF SERVICE?

Yes. The cost of fuel and purchased power were over 29.9% of PNM South’s cost of

service during the Base Period. The cost of fuel and purchased power is projected to be

over 36.4% of PNM South’s total cost of service during the Test Period. These are

significant percentages. By comparison the Commission has previously found that 20%

is a significant percentage for these purposes. PNM South’s fuel and purchased power

costs are its largest single category of costs reflected in the Test Period.

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DOES PNM’S PROPOSAL TO INCLUDE A FPPC, AC IN PNM SOUTH’S

TARIFF MEET THE SECOND OF THE THREE REQUIREMENTS UNDER

RULE 550, SECTION 17 -NAMELY THAT THE COST

PURCHASED POWER CONTAINS COSTS WHICH

FLUCTUATE AND CANNOT BE

CASE?

OF FUEL AND

PERIODICALLY

PRECISELY DETERMINED IN A RATE

Yes. Prices for natural gas and power are generally accepted as being highly volatile such

that they can fluctuate to a great extent on a frequent basis. PNM Exhibit JAM-8 is a

chart showing daily natural gas prices at the Permian Basin tbr the period 2006 to 2010.

The volatility of the price of natural gas shown in the Exhibit is the result of a myriad of

factors affecting demand and supply, including political uncertainty throughout the

world, weather phenomena such as hurricanes in the Gulf of Mexico, and other external

and global factors. Additionally, speculation and trading activity can influence both the

natural gas and power markets. These factors make it very difficult to precisely determine

fuel and purchased power costs in a rate case. PNM Exhibit JAM-8 also shows the

average daily price for firm day-ahead energy at the Palo Verde Hub, which is a standard

for pricing in the Southwest wholesale electricity markets. This chart shows that the cost

of energy in the market is subject to significant daily fluctuations. Given the TNP

Stipulation and the 3137 Stipulation, PNM South’s energy costs are entirely dependent

on natural gas and purchased power prices.

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DOES PNM’S PROPOSAL TO INCLUDE A FPPCAC IN ITS TARIFF MEET

THE THIRD OF THE THREE REQUIREMENTS UNDER RULE 550, SECTION

17 - NAMELY THAT THE UTILITY’S FUEL AND PURCHASED POWER

POLICIES AND PRACTICES ARE DESIGNED TO ASSURE THAT ELECTRIC

POWER IS GENERATED AND PURCHASED AT THE LOWEST

REASONABLE COST?

Yes. PNM’s fuel and purchased power policies and practices are designed to assure that

electric power is generated and purchased at the lowest reasonable cost. This was

confirmed by the Commission’s Audit performed in Case No. 08-00330-UT for the

FPPCAC for PNM North. These policies and procedures include diversification of fuel

mix and generating technologies, the use of economic dispatch on an hourly basis to

supply jurisdictional needs from the lowest cost resources, and purchasing energy from

the spot market if it is less expensive than operating jurisdictional resources. PNM’s

overall fuel procurement strategy is to maintain an economical and reliable fuel supply

for all its generating stations to ensure that electric power is generated and purchased at

the lowest reasonable cost while considering fuel supply reliability, market conditions,

environmental impacts, and system reliability. In doing so, PNM regularly monitors and

aggressively administers its fuel contracts, and updates its fuel use plans to assure that its

fuel and purchased power costs are reasonable. Purchased power is acquired on a short-

term and long-term basis. Short-term purchases are made from suppliers in the wholesale

market at competitive prices on an hourly basis. With the development of electronic

trading platforms, the long-term power markets are now relatively transparent. Long-

term power can be acquired competitively through the Use of electronic trading platforms,

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requests for proposals or brokers. PNM may use a combination of these means to

procure long-term power. Given the constraints of the stipulations discussed earlier in

my testimony, PNM South is being served at the lowest reasonable cost of fuel and

purchased power.

WHAT CARRYING CHARGE IS PNM PROPOSING FOR ANY UNDER OR

OVER RECOVERIES FOR PNM SOUTH?

PNM is proposing that the recommended pre-tax WACC of 13.26% be used for both

monthly over and under recoveries in the South balancing account. Because of the time

value of money, appropriate carrying charges on under-recovered balances are necessary

to allow the Company to fully recover its actual costs of fuel and purchased power as

contemplated by Rule 550. In order to be compensatory, carrying charges on under-

recovered balances should be calculated at the pre-tax WACC determined in this case,

effective April 1,2011. In order to provide symmetry, the Company proposes that the

monthly carrying charge on over-recovered balances also be set at the pre-tax WACC

determined in this case, effective April 1,2011.

DOESN’T THE USE OF AN ASYMMETRICAL CARRYING CHARGE

PROVIDE AN INCENTIVE FOR THE COMPANY TO ACCURATELY

PREDICT ITS FUEL AND PURCHASED POWER COSTS?

No. On the contrary, it penalizes the Company when its base fuel rates plus any

FPPCAC factor happen to project those costs at too low a level. The Company attempts

to make accurate predictions of its fuel and purchased power costs so that it can recover

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those costs timely and not have to refund revenues to customers. The theory that

asymmetrical carrying charges provides an incentive for the Company to accurately

predict its fuel and purchased power costs is counterintuitive to one of the primary

reasons for a FPPCAC--that those costs cannot be precisely determined in a rate case.

Thus, as a fundamental matter of fairness in properly balancing the interests of investors

and customers, the Commission should apply symmetrical carrying charges to monthly

over and under recoveries at a compensatory rate, i.e. the pre-tax WACC determined in

this case.

DO YOU HAVE A PROJECTION OF WHAT THE REVENUES AND FACTOR

WOULD BE FOR PNM SOUTH USING CURRENT FORWARD MARKET

PRICES FOR THE PERIOD OF JULY 2011 TO JUNE 2012?

Yes. Using current forward market prices for gas and market purchases, PNM has

estimated the FPPCAC factor would be $.0083892/kWh for PNM South to recover

$4,687,285 for the period of July 2011 to June 2012. This would raise the fuel and

purchased power cost for PNM South from $0.0379673/kWh to approximately

$0.046357/kWh. This projection is subject to change and will be updated closer to the

implementation day. PNM is proposing an annual FPPCAC factor for the South to match

the methodology for the North. However, given the greater volatility in allocated fuel and

purchased power costs for PNM South due to the stipulations discussed previously, the

Commission may want to consider a FPPCAC for PNM South that adjusts more

frequently (such as quarterly or semi-annually or if the balancing account becomes too

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large in either direction) to prevent large adjustments to the FPPCAC factor at any one

time, until the cost of service for PNM North and South is consolidated.

IS PNM PLANNING TO UTILIZE A HEDGING PROGRAM TO MANAGE

FUEL COSTS?

Yes. PNM also intends to apply the hedging guidelines and requirements approved in

Case No. 09-00321-UT to the fuel and purchased power porttblio for PNM South.

F. OPERATION AND MAINTENANCE ("O&M") EXPENSES

Q, WHAT ARE THE SIGNIFICANT O&M EXPENSES IN THE TEST PERIOD?

A. In 530 Schedule H-16 and associated work papers, I have identified the O&M expenses

that differ from the Base Period by more than $1 million as a result of the ScottMadden

study. Major adjustments in the Test Period are included for:

a) Scheduled Plant Maintenance;

b) Pension Expenses;

d) Depreciation Expense;

e) removal of Corporate Retained Costs from Management Fee;

f) removal of earnings based incentive compensation from Management Fee; and

g) removal of non-operating expenses from Management Fee.

Scheduled Plant Maintenance is further explained by PNM witness Themig. The changes

in pension expenses are explained by PNM witness Vogl. PNM witness Robinson

explains the requested change in the depreciation rates for PNM. PNM witness Lovorn-

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Marriage discusses management fees. All of the O&M adjustments are summarized in

530 Schedule H-16 and supporting work papers.

IS PNM PROPOSING AN ADJUSTMENT TO FORECASTED PLANT

MAINTENANCE COSTS?

Yes. PNM is including an average of three years of forecasted plant maintenance costs

for the period of2011 through 2013 in order to normalize the Test Period in recognition

of the plant scheduled maintenance cycles. Since scheduled maintenance costs change

from year to year, PNM believes that including a three year average of these costs in rates

is the best reflection of costs for PNM’s normal operations. The Commission has

traditionally used a "rule of thumb" of three years to assume the average length of time

between rate changes, as is the case for the amortization period for rate case expenses.

This rule of thumb is also used for calculating costs and benefits associated with

customer distributed generation. PNM witness Themig describes the scheduled

maintenance cycles in more detail and provides the explanation for how these costs were

forecasted. The result of the three year average of scheduled maintenance costs is an

increase to production O&M in the amount of $2.6 million. Additionally, PNM included

an offsetting rate base reduction for the three year maintemmce average adjustment of

$2.6 million. The forecast of Test Period scheduled maintenance costs is outlined in 530

Schedule H-16 and scheduled maintenance supporting work papers.

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WHAT ADJUSTMENTS HAVE BEEN MADE TO THE MANAGEMENT FEE?

Please see the testimony of PNM witness Lovorn-Marriage for the adjustments to the

management fee, pension and retirement.

IS PNM PROPOSING NEW DEPRECIATION RATES WITH THIS FILING?

Yes. As testified to by PNM witness Robinson, PNM recently completed a new

depreciation study. PNM is filing this study with the Commission and is proposing that

new depreciation rates be adopted effective with the rates set in this case. PNM does not

intend to implement the new depreciation rates until they have been approved by the

Commission in this case. PNM has adjusted accumulated depreciation reserve and

depreciation expense in the Test Period to reflect new depreciation rates calculated in the

study effective April 1,2011.

Depreciation expense for new plant additions was included in the Test Period on a

normalized basis. This means that the additional depreciation expense was determined for

the period of time when the plant is forecasted to be in service during the Test Period. For

example, if a plant addition is forecasted to be in service in July 2011, then the additional

depreciation expense and related accumulated depreciation expense was determined for

the period of July through December 2011 rather than on a full year as is done with

annualizing a historical test period. This approach better represents the actual operations

and expenses of the Company during the period when rates go into effect.

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PLEASE SUMMARIZE THE REVENUE INCREASE REQUESTED FOR PNM

NORTH AND PNM SOUTH.

In PNM Exhibit JAM-5, I have shown a summary of the requested non-fuel increase for

PNM North and PNM South, the requested base fuel cost for PNM North and PNM

South, and the overall percentage increase for each area. Table JAM-3 summarizes the

revenue deficiency for PNM North and PNM South. As shown in Table JAM-3 the Test

Period revenue requirements are 21.3% higher than forecasted 2011 revenues for PNM

North, and 19.4% higher than forecasted 2011 revenues for PNM South.

PNM North PNM SouthNon-fuel Revenue Requirement 675,145,091 51,527,861Fuel Revenue Requirement 171,107,948 21,340,009Total Revenue Requirement as Requested 846,253,039 72,867,870

I&S FeesFuel Factor - July 2010 adjustment PNM NorthMiscellaneous Service Charges and RevenuesTotal Retail Revenue Requirement

4,282,046 368, 71218,126,088

1,475,588 2,662,653870,136,761 75,899,235

Non-fuel Forecasted Revenues (excluding I&S Fees)Fuel Forecasted RevenuesTotal Forecasted Base Revenues at Existing Rates

535,815,367 39,345,350158,355,132 21,266,627694,170,499 60,611,977

I&S FeesFuel Factor - effective July 2010 PNM NorthMiscellaneous Service Charges & RevenuesTotal Forecasted Base Revenues

3,512,507 306,69718,126,O88 -1,475,588 2,662,653

717,284,682 63,581,327

Total Non-Fuel Revenue DeficiencyTotal Fuel Revenue DeficiencyI&S Fees DeficiencyTotal Revenue Deficiency

(139,329,724) (12,182,511 )(12,752,816) (73,382)

(769,539) (62,015)(152,852,079) (12,317,908)

% non-fuel ~ncrease over total forecasted revenues 19.4% 19.2%% I&S fee increase over total forecasted revenues 0.1% 0.1%% fuel increase over total forecasted revenues 1.8%. " 0.1%% total increase over total forecasted revenues 21.3% 19.4%

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As noted, for comparison purposes and to provide an estimate of the total cost for PNM

North and South, I have included in PNM Exhibit JAM-5 and Table JAM-3 the FPPCAC

factor for the North that is pending before the Commission for implementation in July,

2010, and an estimate of what the FPPCAC factor may be in July, 2011, for PNM South.

G. PHASE-IN

Q. IS PNM PROPOSING TO IMPLEMENT THE FULL AMOUNT OF ITS

PROPOSED RATE INCREASES WITH THE COMMISSION DECISION IN

THIS CASE?

No. As explained by PNM witness Damell, if the Commission approves the full rate increase

requested by PNM, PNM is proposing the rate increase be implemented in two phases, as

shown in PNM Exhibit JAM-5, effective April 1, 2011, and January 1, 2012. PNM

Exhibit JAM-5 provides a summary of the proposed phase-in schedule. As part of the

proposed phase-in, PNM has included four sets of tariff sheets in its filings. These

include two sets of tariffs for PNM North and two sets of tariffs for PNM South,

representing the two phases. PNM is requesting that the Commission approve its

requested rate relief as filed, with the one exception being approval of the decoupling

proposal. PNM is submitting the decoupling proposal as an alternative to the increased

monthly customer service charge for residential and small commercial customers for

PNM North.

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HOW DOES PNM PROPOSE TO STRUCTURE THE ILX.TE PHASE-IN?

PNM proposes that the first phase-in for PNM North would be a total increase of

$111,142,671 of which $98,389,855 is attributable to non-fuel base rates and

$12,752,816 is attributable to base fuel. This would be an approximate 16% increase in

rates for PNM North. The second phase would be an approximate 6% increase consisting

of $41,709,408 attributable to non-fuel base rates. For PNM South, the first phase would

be a total increase of $8,672,550 consisting of $8,599,168 attributable to non-fuel base

rates; and $73,382 attributable to base fuel. This would be an approximate 14% increase

for PNM South. The second phase would be an approximate 6% increase consisting of

$3,645,358 attributable to non-fuel base rates. The non-fuel difference in percentage

increase between PNM North and PNM South is a function of the existing higher non-

fuel cost per kWh for the South as well as the significant fuel expense contained in the

South’s rates.

III. CUSTOMER CLASS COST-OF-SERVICE

530 SCHEDULE K-4 EMBEDDED CONTAINS FULLY ALLOCATED COST-OF-

SERVICE STUDIES FOR PNM NORTH AND PNM SOUTH. WHAT IS THE

PURPOSE OF THESE STUDIES?

Fully allocated embedded cost-of-service studies are used for a number of reasons in the

ratemaking process. PNM advocates the use of the cost-of-service studies provided in

530 Schedule K-4 Embedded to define customer class cost responsibility, allocate

revenue requirements to class based upon the relative performance of each class

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compared to system average, and provide cost-based pricing information (S/kWh,

S/customer, etc.) useful in the design of rates. Cost-of-service studies are provided for

both PNM North and PNM South.

IS THIS A CHANGE FROM WHAT PNM HAS DONE IN THE PAST?

Yes. In past cases PNM utilized a marginal cost study to assign revenue responsibility by

customer class. In this case we are using the fully allocated embedded cost-of-service

studies provided in 530 Schedule K-4 Embedded for this purpose. The marginal cost

study developed for this case is used as a tool in price signal determination and rate

design.

WHY IS PNM ADVOCATING THE MOVE FROM A MARGINAL COST STUDY

TO THE USE OF A FULLY ALLOCATED, EMBEDDED COST-OF-SERVICE

STUDY?

Fully allocated embedded cost-of-service studies can provide stable results over time

when allocation methodologies are consistent; such stability is a key reason why most

utilities (including those in New Mexico) employ such studies in the ratemaking process.

Embedded and marginal cost analyses each have rationales for their utilization.

An embedded study reflects the actual jurisdictional revenue requirement being requested

by the company including net plant-in-service and current operating costs. By contrast a

marginal cost study calculates the incremental cost of providing service to each customer

class. A marginal study uses the last investment or forecasted investment to calculate the

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costs of resources to be allocated to customer classes. Because true marginal cost

pricing is not tied to a revenue requirement as determined in utility rate proceedings,

marginal cost studies require adjustment mechanisms to bring marginal cost calculated

revenue requirements in line with actual revenue requirements. These adjustments

invariably introduce volatility in the results as marginal costs (and the necessary

adjustments) vary considerably from study to study. Such volatility can bring instability

in rate design especially when the marginal study is used as the primary basis for revenue

assignment to customer classes.

Because costs at the margin can be volatile, the marginal costs of service applied to class

billing determinants can also be very volatile over time. While this volatility is reflective

of the incremental costs of providing service, it is not necessarily reflective of the

underlying costs of service for a company’s non-fuel cost of service.

CAN YOU DESCRIBE THE VOLATILITY OF MARGINAL COSTS IN MORE

DETAIL?

Yes. Marginal cost studies are heavily influenced by the incremental investment cost

determination used for the marginal generation, transmission, or distribution plant. A

heavy emphasis on distribution system upgrades in one year can produce drastically

different marginal cost results from a year in which transmission investment is high. The

proportion of generation, transmission, and distribution costs to total costs in a marginal

cost study may be drastically different from the plant actually in place to serve customers.

Allocating revenue requirements to customer classes in a year in which transmission

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investment is the key driver will produce different results from a year in which the

primary driver is distribution or generation investment. The potential for such

differences brings a level of volatility to marginal cost results which are not inherent in a

fully allocated embedded cost study.

However, the marginal cost approach results in a revenue imbalance where the marginal

study shows that the marginal costs being used are either higher or lower than the

embedded study and some form of reallocation, such as Ramsey Pricing,~ must be made

to match the jurisdictional revenue requirement at the marginal class level. Ironically,

marginal cost theory dictates that the class customer charge should be adjusted to balance

the jurisdictional revenue requirement due to its inelastic nature. This charge may be the

most difficult to change, especially for residential customers, ibr a number of reasons.

PNM Exhibit JAM-9 illustrates the functional disparity between the marginal cost study

and the embedded cost-of-service studies filed in this case. Total costs by function

(generation, transmission, distribution, customer) in the marginal cost study are shown

alongside those found within the jurisdictional revenue requirement. PNM has a heavy

investment in nuclear and coal generation facilities which comprise the largest

component of costs in the jurisdictional revenue requirement ibr PNM North. However,

because the generation costs in the marginal cost study are based on a single-cycle gas

turbine, generation costs in the marginal cost study contribute significantly less to the

1 Ramsey Pricing means that price increases should be applied to the products or services with the most inelastic

den land because customers will buy them anyway.

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overall marginal cost study revenue requirement. Such disparity leads to differing

revenue requirement results if marginal cost studies are used as the basis for revenue

allocation.

The change in functional revenue requirements can also be seen in a comparison of the

marginal cost study prepared for the 2008 Rate Case and the study being filed in this

case. A review of PNM Exhibit JAM-10 indicates that marginal transmission costs are

the primary cost element in the marginal cost study filed in this case. Distribution costs

were the primary cost element in prior cases. Transmission cost incurrence is much

different from distribution cost incurrence and customer class contributions to each vary

considerably. Embedded cost-of-service studies serve to moderate the allocation changes

given the "average cost" nature of the studies. Marginal cost studies have no such

dampening mechanism and disparate impacts are the result.

DOES THE VOLATILITY OF MARGINAL COSTS INVALIDATE THEIR USE

IN RATE DESIGN?

No, marginal costs have value in rate design. Their primary value in this case is their use

as guides in developing the relationship among customer, energy and demand related rate

elements within individual rate classes. Cost differentials :for daily TOU periods and

seasonal price distinctions are of key importance to PNM. They provide guidance for

pricing on and off peak as well as for pricing the inclining blocks for the residential rates

for PNM North.

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PNM utilizes marginal cost information in this way. For example, in developing the on-

peak and off-peak rate elements for the TOU tariffs being proposed for PNM South,

PNM examined the relative on-peak and off-peak costs by season to determine the price

differential to charge for TOU energy rates.

PLEASE DESCRIBE THE DEVELOPMENT OF THE FULLY ALLOCATED

COST-OF-SERVICE STUDIES CONTAINED IN 530 SCHEDULE K-4

EMBEDDED.

The development of the fully allocated cost-of-service studies provided in K-4 Embedded

consisted of three major steps: 1) functionalization, 2) classification, and 3) allocation or

assignment. Functionalization is the process of categorizing embedded costs by the

operating function in which the costs are primarily associated such as production,

transmission, distribution, customer service, etc. Classification is the process of further

defining the functional costs into demand-related (i.e., costs associated with being able to

serve customers at the system and class peaks), energy-related (i.e., costs that vary

volumetrically with the amount of energy used by customers), an6 customer-related (i.e.,

costs that are directly related to the number of customers served). PNM followed

industry standard methods prescribed by the National Association of Regulatory Utility

Commissioners ("NARUC") for functionalizing, classifying, and allocating costs to

customer classes.

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WHAT CRITERIA DID PNM USE IN THE SELECTION AND DEVELOPMENT

OF THE VARIOUS ALLOCATION FACTORS USED TO ASSIGN COSTS TO

CUSTOMER CLASSES?

PNM used the following criteria, although not an exhaustive list, to judge the

appropriateness of an allocation methodology: 1) the method should reflect the operating

and planning characteristics of PNM’s utility system; 2) the method should recognize

various customer class characteristics such as peak demand, energy usage, load factor,

diversity characteristics, number and size of customers, points of delivery, etc.; 3) the

method should produce stable results from year-to-year; and 4) customers who benefit

from the use of plant and equipment should bear the costs.

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PLEASE DESCRIBE THE DEVELOPMENT OF THE ALLOCATION FACTORS

USED IN THE ASSIGNMENT OF COSTS.

As I mentioned previously, PNM very closely followed the NARUC prescribed methods

for cost functionalization, classification, and allocation. The 530 Schedule M-2 contains

a detailed list of the classification and allocation factors used in the development of the

PNM North and PNM South cost-of-service studies.

Production rate base costs were allocated to customer classes using a modified average

and excess ("AED") demand allocation methodology. Transmission costs were allocated

to customer classes using an average of PNM’s monthly coincident peaks ("12CP").

Distribution substations, primary lines, and secondary lines were allocated to customer

classes using the maximum non-coincident peak demands of each class (NCP) at either

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primary or secondary voltage levels. Other components of distribution were allocated to

class based upon detailed analysis specific to the cost type (meters, services, etc.) and

reflective of the number of customers served. General plant and other ancillary rate base

items were allocated to customer classes using industry standard methods which use the

results of prior allocations (production plant, total plant-in-service, labor, etc.) to allocate

such costs to customer classes.

Operating expenses, such as production O&M, are allocated to customer class on the

basis of the associated plant-in-service (e.g., production) or a combination of associated

investment. Fuel and other energy-related O&M expenses were allocated to customer

class using annual energy deliveries (kWh). All other expenses were allocated to

custonler class using a combination of allocation methods or results which underlie the

reason for the expense.

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WHAT ALLOCATION METHODOLOGY WAS USED BY PNM TO ALLOCATE

PLANT TO CUSTOMER CLASSES?

PNM is using a modified AED method using two summer and two winter coincident

peaks ("AED 2S2W 4CP" or "AED-PNM") for allocating fixed costs associated with

production plant to customer classes. AED allocation methodologies reflect the dual

nature of production plant investment; i.e. production or generation costs in the aggregate

are expended to meet both energy and demand requirements of customers. The

demand/energy classification of production plant is a key issue and one that underlies the

allocation of a large component of fixed costs to PNM’s customer classes. For

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distribution plant the predominant expenses were based on non-coincident peak demand

utilizing primary and secondary voltage differences. Customer and metering costs were

weighted for meter cost and meter size.

PLEASE DESCRIBE THE DEVELOPMENT OF THE AED-PNM ALLOCATION

FACTOR.

The AED-PNM method considers that average demand (or annual energy usage .’- 8760)

is a significant cost driver along with coincident peak demands. Under the AED-PNM

method, the average demand is considered to be equal to the system load factor and is

allocated using annual kWhs of each customer class at the generator level. The "excess"

portion is allocated to each class using the average of each class contribution to four

system coincident Feaks, the two highest in the summer months and the two highest in

the winter months. The use of coincident peak demands for allocation of the "excess" or

demand component of production plant is consistent with the principle that generation

resources are built to meet peak demands as well as to provide energy throughout the day.

The choice of both summer and winter peak demands reflects the fact that PNM is not

solely a, summer peaking utility since winter coincident peak demands are approaching

75% of those experienced in the summer. This is especially true for the PNM’s

Residential Rate Class which has in 2006, 2007 and 2008 experienced winter peaks

greater than the summer peak. For 2009 the residential winter peak was 79% of the

summer peak. The similarity of the peak demands in the winter and the summer is a

reflection of the PNM residential class use and that individual use is changing as a result

of the appliance mix being used by those customers.

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PLEASE DESCRIBE THE DEVELOPMENT OF THE TEST PERIOD PEAK

DEMAND AND ENERGY THAT ARE USED IN THE CLASS COST OF

SERVICE.

For both PNM North and PNM South, the Test Period energy deliveries were determined

by rate class using the load forecast described earlier in my testimony. The one exception

to this methodology relates to the PNM South unmetered lighting classes 4 and 14, where

the unmetered monthly energy deliveries were recalculated in a manner consistent with

flat energy deliveries calculated by light type used for PNM North.

DID PNM CONSIDER OTHER ALLOCATION METHODS FOR ALLOCATION

OF PRODUCTION PLANT?

Yes. PNM considered a number of other standard allocation methods which are used in

the industry. While each allocation method has merit depending on the utility’s specific

circumstances, the AED-PNM method best reflects the load characteristics of the PNM

system. The alternative allocation methods considered included the following:

1) 4 Coincident Peak (4CP) Method using an average of customer class contributions to

the four highest coincident peak demands during the Test Period; 2) 12CP Method using

an average of customer class contributions to all twelve of PNM’s coincident peak

demands during the Test Period; and 3) variants of the AED method including the

traditional method in which the "excess" portion is allocated using customer class NCP

demands.

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I have shown in PNM Exhibit JAM-11 the allocation percentages of the methods

described above to PNM North and PNM South rate classes as well the respective

revenue requirements under each of the methodologies. I have also traced in the Exhibit

the revenue allocation that would have resulted from using the marginal cost study

allocation approach.

WHY WERE THESE METHODS REJECTED IN FAVOR OF THE AED-PNM

ALLOCATION METHOD?

For PNM, the AED-PNM method best reflects cost causation and results in just and

reasonable allocations to customer classes. For production, or generation, resources cost

causation attempts to determine what influences a utility’s production plant decisions. For

most utilities, including PNM, a portion of generation costs is expended to meet the

Company’s energy requirements in a low cost, reliable manner. Similarly a portion of

generation costs are expended to meet peak demand requirements. PNM, along with

many other utilities, believes that production plant allocation methods which reflect both

the energy and the demand component of generation investment and usage best reflect

cost causation. As a customer’s load factor increases, the AED method recognizes the amount

of increasing capacity used to provide continuous service in the allocation of costs. Allocation

factors (CP, 4CP, 12CP) assume that all generation resources are built solely to meet

peak demands and do not adequately reflect the investment and usage decisions which

underlie base load generation investment. The AED-PNM allocation method does not

have this limitation and is believed to best reflect both the investment and load

characteristics of the PNM system.

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IV. RATE DESIGN

WHAT ARE PNM’S RATE DESIGN OBJECTIVES?

These objectives include: 1) understandability and applicability; 2) rate stability both in

terms of impact on customer and impact on revenues of the Company; 3) reflection of

actual costs to serve within a given season or time period coupled with the price elasticity

of New Mexico customers to rate changes; 4) effectiveness in recovering the targeted

revenue requirements within a given customer class; 5) encouragement of energy

efficiency, where warranted, through the use of design techniques such as inclining block

pricing (residential); and 6) mitigation of inter-class customer class subsidization through

appropriate revenue allocation mechanisms.

DID THE COMPANY CONDUCT A PRICE ELASTICITY STUDY AS

REQUIRED BY THE COMMISSION TO ASSIST IN DEFINING BASIC USAGE

FOR RESIDENTIAL CUSTOMERS?

PNM contracted with Dr. Jonathan Lesser of Continental Economics, Inc., to conduct a

price elasticity study to meet the requirements of the Stipulation in the 2008 Rate Case

which implemented a revised directive of the Commission from the 2007 Rate Case. Dr.

Lesser presents the price elasticity study in his testimony. The results of the study were

presented at a workshop conducted by PNM on January 15, 2010.

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PLEASE SUMMARIZE THE ELASTICITY STUDY RESULTS.

The elasticity study respondents were evaluated to ensure their energy consumption and

behavior and household income was representative of all PNM’s residential customers

and the results indicated they were representative. The elasticity study results indicated

that lower income customers are more sensitive to changes in electric prices than higher

income residents. Price elasticity was also estimated for customers along each block of

the existing Residential 1A rate and showed price elasticity is largest in the first block.

The elasticity study, however, could not identify the optimal size of the first block due to

the trade-offs made in rate design for economic efficiency, equity, affordability and

stability which could not be captured in the study. PNM witness Lesser discusses the

elasticity study and its findings in more detail. PNM’s rate design for the residential class

considered the results of the elasticity study.

WHAT FACTORS DID PNM CONSIDER IN THE ALLOCATION OF OVERALL

REVENUE DEFICIENCY TO CUSTOMER CLASS?

Once overall costs were determined for each class, the next step was to determine the

appropriate levels of revenues to be collected from each class. A number of cost-based

and other considerations were factored into the overall revenue allocation decision to

ensure each customer class received a fair apportionment of the overall revenue

requirement. These included:

a) Cost Causation - Class Rate of Return ("ROR") on rate base under present rates

depicting current cost recovery for each class relative to the system as a whole and

to each other;

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b) Equalized Rates-of-Return - Class ROR set equal to the system average for all

classes; revenue allocation based upon the under / over collection of revenues

necessary to earn an equalized return;

e) Gradualism - Revenue allocation is predicated upon equalized ROR but moderated

to ensure no class receives an increase (or a decrease) significantly below or greater

than the system av(rage; typically a "band" around the system average increase is

established and applied to all customer classes to moderate large increases (or

decreases);

d) Price and Tariff Relationships - Customer class unit price results from revenue

allocation compared with existing unit pricing, similar pricing of other classes, and

other rate design requirements; revenue allocation adjusted as needed to ensure

proportionality and other desired pricing designs are met; and

e) Other Non-Cost Ratemaking Factors - Other factors for considerations including:

conservation, social and environmental goals, affordability, market pricing, fairness,

and equity.

HOW WERE THESE FACTORS UTILIZED?

PNM followed the five considerations closely in the allocation of revenue requirements

for Phase I and Phase II. The initial step was a review of the results of the Company’s

embedded cost-of-service study contained in 530 Schedule K-4 to assess relative cost

causation and cost recovery. Class ROR under present rates, coupled with the class

relative ROR, were initial factors in revenue allocation. Classes with relative ROR close

to system average were assumed to receive an increase close to system average; classes

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with relative ROR above or below this range were flagged as requiring additional

analysis.

The next step was the development of equalized class ROR’s under the Test Period

revenue requirement. The proposed revenue increase for each class was developed in

such a way that the relative ROR for all classes under the proposed revenue requirement

equaled 1.00. The resulting percent increases for each class were compared to the system

average increase to determine the relative increase ratio.

Parallel with the development of the equalized class ROR revenue requirements was the

establishment of a 0.5-1.25 system average increase "band," or guideline, under which no

class was to receive an increase below 50% of system average and no class was to receive

an increase greater than 125% of system average. The 0.5-1.25 band was primarily

established as a means of moving all customer classes toward equalized ROR but doing

so gradually to moderate any significant increases or decreases based solely on an

equalized cost-of-service basis. Using this band, the overall revenue requirements of

seven of the eleven PNM North customer classes were slightly modified so that they

would meet the 0.5-1.25 guideline. Similarly the revenue requirements of six of the

eight PNM South customer classes were slightly modified to bring them in line with the

guideline. Any residual revenue requirements after application of the band were

reallocated to other retail classes with relative increases below system average. PNM

took this conservative approach given that it is presenting both an embedded class cost of

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service study for revenue allocation and a Test Period based on a future forecast for the

first time.

Once this preliminary revenue requirement allocation was complete, the final step was a

review of the resulting unit pricing after application of the increased revenues. Inter- and

intra-class pricing and tariff proportionality relationships were reviewed along with other

non-cost factors such as affordability, rate stability, etc. For example, the overall revenue

increase requirements for the PNM North Residential Service class were adjusted slightly

downward to maintain the current proportionality between residential pricing in PNM

North and PNM South. The resulting residual revenue requirements were again

reallocated to other retail classes with relative increases below system average.

PLEASE PROVIDE THE SUMMARY OF REVENUE INCREASES REQUESTED

AND ROR BY CLASS.

PNM Exhibit JAM-12 provides a summary of ROR for the classes from the embedded

class cost of service study as well as the requested revenue increase by rate class for

PNM North and PNM South.

WHAT SIGNIFICANT CHANGES ARE PROPOSED FOR PNM NORTH

TARIFFS?

For PNM North customers, PNM is proposing to expand the definition of the summer

season from June through August to May through September, an expansion of two

months; reduce the daily on-peak hours from twelve to ten (Monday through Friday);

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shift on peak hours by season; revise the Residential rate structure to include a higher

customer charge and add a fourth block to reflect the higher use on the system; and

expand the miscellaneous services tariff to move towards a common tariff structure with

PNM South. PNM also proposes to exclude Inspection and Supervision ("I&S") fees

from base rates and collect the fee as a separate line item on bills pursuant to PNM’s Tax

Adjustment Clause.

PNM is also proposing to implement a revenue decoupling pilot program applicable to

customers within the PNM North Residential Service (Schedules 1A and 1B) and Small

Power Service (Schedules 2A and 2B) customer classes. If the proposed decoupling

mechanism is approved, customer charges for PNM North residential and small power

customers will remain at current levels. For residential customers, Schedule 1A, the

customer service charge would remain at $4.00 instead of increasing to $7.00. For

Schedule 2A Small Power customer charges will remain at $7.75 instead of the proposed

$12.00.

WHAT SIGNIFICANT CHANGES ARE PROPOSED FOR PNM SOUTH

TARIFFS?

For PNM South customers, PNM is proposing to make TOU pricing available and add

seasonality to the rates to start standardizing tariff terms between PNM North and PNM

South and provide for the eventual consolidation of PNM North and South rates. The

standardization of tariff terms includes establishing a common definition of the summer

season to be the months May through September; create common daily on-peak periods

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of ten hours (a reduction from the twelve hour definitions used in PNM North); splitting

up the non-summer season on-peak hours into two groups; and providing for a common

tariff structure for miscellaneous service charges. PNM also proposes to exclude I&S fees

from base rates and collect the fee through a separate line item on bills pursuant to its Tax

Adjustment Clause.

WHY IS PNM NOT PROPOSING IDENTICAL TARIFF STRUCTURES FOR

PNM NORTH AND SOUTH AT THIS TIME?

As I have previously testified, the resulting rates that would occur to PNM South

customers by moving to a PNM North rate structure without consolidating the cost of

service would result in some PNM South customers suffering unnecessarily large rate

increases. For example, implementation of the four tier residential inclining block

structure for PNM South on a standalone basis could result in some customers receiving a

55% increase or more in their individual summer bills or an annual bill increase of 36%

or more. This would not occur under a consolidated basis.

WHY IS PNM PROPOSING TO EXTEND THE SUMMER SEASON?

Extending the summer season definition to include May and September will provide

customers with price signals that more accurately reflect the costs imposed on the

Company’s electric system. Customers can then make more informed decisions as to

when or how much electric service to use each month. Examination of Company load

characteristics over the last several years reveals that afternoon cooling loads set the monthly

maximum peak loads in both areas during the months of May through September. The current

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summer months of June to August do not fully capture this effect of cooling loads. PNM Exhibit

JAM-13 illustrates this trend. In PNM North, these cooling loads are driven primarily by the

Residential, Small Power, and General Power rate classes.

WHAT IS THE COMPANY’S PROPOSAL WITH RESPECT TO TOU

PERIODS?

The Company is proposing to change its TOU on-peak billing in the summer months for

PNM North to between 12 pm and 10 pm on weekdays, and in the non-summer months

to between 7 am and 12 pm and between 5 pm and 10 pm on weekdays. Off-peak hours

would consist of all remaining hours. For its PNM South customers, the Company

proposes to offer the same TOU billing periods and seasons as PNM North.

WHY IS THE COMPANY MAKING THIS CHANGE TO TOU BILLING

PERIODS IN THIS CASE?

In the examination of overall system load shapes by season, it was apparent that the

existing seasonal on-peak hours did not fully encompass the hours where peak loads were

most likely to occur. During the summer months, peak periods are later in the day, while

during non-summer months the peak period is divided into separate and distinct morning

and evening times. PNM Exhibit JAM-14 illustrates these peak periods.

PNM North has offered TOU rates to its customers since 19812, and has utilized an 8 am

to 8 pm on-peak billing period during weekdays since mid 1984.3 PNM has seen a

result of the final order in NMPUC Case 1693.

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change that supports a re-definition of its TOU billing periods for the last several years,

but has not proposed changing those periods in other rate cases primarily due to the time

and costs required to physically reprogram the existing TOU meters. It recently became

possible for meter readers to use new technology to reprogram TOU meters more quickly

and cheaply, thus making TOU time period changes economically practical.

WHAT ARE THE IMPACTS OF THE PROPOSED CHANGES TO TOU

BILLING PERIODS?

The most noticeable impact is the reduction of on-peak hours from 60 to 50 hours per

week, while off-peak hours will be increased from 108 to 118 hours per week. The

concentration of the recovery of peak period costs over fewer hours sends a stronger price

signal to customers. This in turn has the potential to improve the Company’s total load

shape.

Additionally, the shorter on-peak period has the potential to improve the economic

viability of some energy/demand management technologies (such as thermal energy

storage), thus improving their likelihood of adoption by customers.

Q, WHAT TYPES OF CUSTOMERS ARE LIKELY TO BENEFIT FROM THE

PROPOSED TOU BILLING PERIOD CHANGES?

A. Short term, the customers most likely to benefit from the proposed TOU billing period

changes are those whose load profiles are not highly correlated with the newly proposed

3 A~ a result of the final order in NMPUC Case 1835.

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peak periods. This is appropriate since these customers’ peak loads do not contribute to

the system peak. Longer term, customers who can shift usage/demand to off-peak periods

will benefit.

WHAT HAS THE COMPANY DONE TO MITIGATE POTENTIAL IMPACTS

OF THE PROPOSED TOU BILLING PERIOD CHANGES?

For PNM Schedules 1, 2 and 10 (the three rate classes where TOU rates are an option),

the Company endeavored to maintain the relative economics between the TOU and the

non-TOU options for these tariffs. For the remaining PNM North tariffs where TOU is

the only option (Schedules 3, 4, 5, 11, 15, and 30), the Company examined the relative

bill impacts of each tariff with respect to other tariffs that a customer might choose.

PLEASE SUMMARIZE THE PROPOSED CHANGE IN THE RESIDENTIAL

RATE STRUCTURE.

PNM is proposing a number of changes to the residential rate slructure for both PNM North and

PNM South. Residential customer-related fixed costs are currently only partially collected

through the monthly customer charge. Although the monthly customer charge is intended

to recover customer-related fixed costs, i.e. costs that do not vary with usage except over

long periods of time, PNM’s residential rate structure is currently structured so that the

great majority of PNM’s fixed costs are actually recovered in the variable rates. PNM is

proposing to change the customer charge to $7.00 per month for PNM North (unless a

decoupling proposal is adopted) and PNM South. The objective of this change is to have

the customer charge cover a reasonable amount of customer-related fixed costs, while

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protecting low-use customers from experiencing an inordinately large bill impact. The

fully allocated embedded cost of service study indicated the customer charge should be

$13.00 for PNM North residential customers and about $8.00 for PNM South customers.

While the proposed increase in the customer charge improves the recovery of customer-

related costs, it does not address the residential class demand-related fixed costs which,

when combined with customer-related fixed costs, are over $55.00 per residential

customer.

PNM North is also increasing the number of blocks in the PNM North residential tariff from

three to four to provide a better match to residential usage. The first block, 0-200 kWh, is

a low usage block. The second block, 201-700 kWh, is for typical usage and includes the

average monthly usage of PNM residential customers. The third block, 701-1,700 kWh,

reflects higher usage levels and the fourth block reflects extremely high usage customers.

The fourth block, 1,701 kWh and more, is priced at the cost of long term energy.

Finally, the Company is introducing seasonality in the energy rates for PNM South to

better reflect the costs associated with providing service. Adding seasonality also moves

the rate structure towards the PNM North residential rate structure in anticipation of the

future combination of the rate structures, As I discuss in my testimony, PNM is proposing

to substantially keep the South rate structures in place with minor modifications for this

filing.

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WHY IS PNM MAINTAINING THE 0-200 KWH BLOCK IN THE

RESIDENTIAL TARIFF?

PNM proposes to maintain the 0-200 kWh block for PNM North residential customers

for a number of reasons. The 0-200 kWh block better matches the cost to serve than a

block that combines the first two blocks. Maintaining the 0-200 kWh block reduces the

amount of fixed costs that are unrecovered from low usage customers as compared to

enlarging the first block’s usage. Similarly, PNM’s ability to recover its costs for cut-in

and cut-out customers is more easily addressed with the 0-200 kWh block structure than a

larger block. Retirees, tourists, and other energy users with usage patterns that are higher

in some seasons than others can receive appropriate price signals for the costs they

impose on the system with the existence of the 0-200 kWh block. The Afion Stipulation,

combined with expansion of the first block, would require concentration of all future

revenue increases across fewer kWh in the remaining blocks.

PNM is also continuing the 0-200 kWh block in the inclining block design as it provides

some reduction in rate impact to low usage customers and lower income customers who

have higher price elasticity as discussed by PNM witness Lesser. Price elasticity is only

one element of many to be considered in setting block size in rate design. Finally,

keeping the first block sized at 200 kWh avoids an increase of 1.69 cents per kWh for the

first 200 kWh of usage.

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WHAT IS THE PURPOSE OF ADDING A FOURTH TIER FOR THE

RESIDENTIAL CLASS?

The four tiers better match PNM’s customer consumption patterns with the marginal cost

of serving customers. A fourth block at a higher rate, i.e. one that reflects the long term

costs of more expensive energy, sends a stronger price signal to customers to conserve.

The price of the fourth block in an inclining block structure also reflects tile higher costs

imposed by customers with higher usage. Customers at the proposed 1,701 kWh fourth

block level are likely users of refrigerated air conditioning, increased appliance use or

electric heating which is a significant driver of peak loads. An incidental benefit is that

the fourth block lowers prices in the first three blocks where about 98% of customer

usage occurs. A bill analysis showed the addition of the fourth tier lowered the energy

rate to the first three blocks approximately 0.043 cents per kWh and lowered average

bills about $0.23 per month compared to maintaining a three block rate structure. Low

income customers will be better served by the proposed rate structure - low income

customers generally have lower average annual bills than higher income customers.

PNM’s proposed four block rate structure and proposed pricing will result in generally

lower bills for low income customers in a manner that better reflects cost causation rather

than social ratemaking.

PLEASE DISCUSS THE CHANGES TO SCHEDULE 4B-LARGE POWER

SERVICE TOU RATE.

A contract is only required now when a line extension is revenue justified. Other changes

to Schedule 4B are for clarification of administration.

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PLEASE DISCUSS THE CHANGES TO LIGHTING SCHEDULES.

PNM retained an outside consulting firm, Management Applications Consulting, Inc.

("MAC") to prepare an analysis of its street lighting rates (schedule 6 and schedule 20 for

PNM North, schedule 4 and schedule 14 for PNM South) based on an accounting cost of

service approach using 2009 investment. The findings indicate that the current pricing

for PNM North Schedule 06 - Private Area Lighting and PNM South Rate 4 - Outdoor

Lighting Services are somewhat above actual accounting costs when the age/vintage of

the fixtures, bulbs, and poles is considered. This finding was confirmed in the class-

cost-of-service study in this case. In keeping with PNM’s revenue allocation approach,

the overall increase for this class was established to bring prices in line with existing

costs but was capped at 1.25 x system average increase to mitigate the overall customer

impa~t.

PLEASE SUMMARIZE KEY POINTS ABOUT DEMAND CHARGES AND

CUSTOMER CHAR(JES.

PNM has proposed appropriate increases in demand charges and customer charges that

improve the recovery of fixed costs based on the fully allocated embedded cost of service

study for each rate class. While the proposed increases better match demand charges and

customer charges and costs, they do not achieve full recovery for the allocated fixed costs

as shown in the embedded study. Consequently, some fixed costs will continue to be

collected in energy charges. The decoupling proposal is intended to address this issue for

residential and small power customers. These two rate classes account for nearly 60% of

PNM North’s revenue requirement.

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WHAT IS PNM DOING TO STRUCTURE A COMMON MISCELLANEOUS

SERVICES TARIFF?

PNM is proposing to standardize most of the charges contained within the current PNM

North Rate 16 and the PNM South Rate 20 tariffs. To implement this, PNM made two

administrative adjustments to the Test Period determinants to support the implementation

of a common miscellaneous services tariff.

The first adjustment was to estimate the Late Payment Charges to reflect the revenues to

be collected under the newly proposed Late Payment Fee rate for PNM South. This

adjusts the total company late payment charge credits by $46,557 (Please see 530

Schedule 0-4).

The second adjustment was to estimate the Meter Tampering Charges which would be

collected under PNM’s newly proposed Meter Tampering Fee rate for PNM North. This

adjusts the total company miscellaneous charge by $46,000.

WHY ARE THE REVENUES ASSOCIATED WITH THE OTHER SPECIAL

CHARGES BEING REDUCED IN THIS CASE?

An analysis of the transaction costs supports a reduction of the Connection and Field

Collection charges in PNM North Rate 16 and a reduction in the Connection and

Reconnection Charges in PNM South Rate 20. (Please see 530 Schedule 0-4).

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IS THE COMPANY PROPOSING TO ADD ANY CHARGES TO PNM’S RATE

16 - MISCELLANEOUS SERVICE CHARGES?

Yes, the Company proposes to institute a Meter Tampering Fee for PNM North to mirror

the fee that is utilized in PNM South. Additionally, the Company is proposing to add

language to the tariff explaining the current Late Payment Charge (this is currently in

each of PNM North’s base tariffs).

IS THE COMPANY PROPOSING TO ADD ANY CHARGES TO PNM SOUTH

RATE 20 - SPECIAL CHARGES TARIFF?

Yes, the Company proposes to institute a Late Payment Charge of 0.667% per month for

PNM South to mirror the fee that is utilized in PNM North.

IS THE COMPANY PROPOSING TO REMOVE ANY CHARGES TO THE PNM

SOUTH RATE 20 - MISCELLANEOUS SERVICE CHARGES TARIFF?

Yes, PNM proposes to remove the following charges from Rate 20 - Miscellaneous

Service Charges Tariff:

1. Meter Socket Purchase Charge: There have been no instances where customers

have utilized this charge.

2. Internet Access to Interval usage data: This service is now obsolete with the

advent of the PNM Profiler product, which provides customers with access to

interval usage data via the internet, and is provided free of charge to customers

who have interval data recording meters.

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Broken!tampered meter seal: Although there are instances where meter readers

find broken!damaged meter seals, in no instance in 2009 was this fee assessed.

Until a standardized policy for assessing this fee is developed, the Company

proposes to remove this charge.

Deny Access to Meter Reading: Although there are instances where meter readers

cannot access meters for reading/billing, in no instance in 2009 was this fee

assessed. Until a standardized policy for assessing this fee is developed, the

Company proposes to remove this charge.

PLEASE PROVIDE THE PROOF OF REVENUES FOR PNM NORTH AND PNM

SOUTH.

530 Schedule 0-2 shows the revenues by rate class for the Test Period under proposed

rates and under current rates. This Exhibit applies the projected Test Period billing units

to determine the total revenue for each rate class for Phase I and II. This calculation

demonstrates how the revenue requirement for each rate class for both PNM North and

PNM South will be collected.

V. DECOUPLING FIXED COSTS

PLEASE DESCRIBE THE RATE DESIGN AND RATEMAKING METHODS

THAT PNM PROPOSES TO COMPLY WITH NMAC 17.7.2.9K(7)(a).

The Commission’s rule adopting the disincentive/incentive mechanism requires that the

New Mexico utilities file in either a general rate case or by July 1, 2010, rate design and

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rate making methods to remove regulatory disincentives or barriers for that utility to

achieve energy efficiency savings. It is generally accepted that, for long term incentives

for energy efficiency measures to be effective, the utility must be made to a large extent

indifferent to changes in customer average use. To do this the rate design must allow it to

recover its non-variable or fixed costs. This means that: a) the customer charge for

residential and small power customers should be reflective of the fixed costs incurred by

each customer and demand charges for larger commercial and industrial customers

should be reflective of the allocated fixed charges; or b) fixed charge cost recovery

should otherwise be "decoupled" from energy sales.

PLEASE DESCRIBE HOW PNM HAS ADDRESSED EACH OF THESE

METHODS IN THIS FILING. :

In this filing, with the use of the embedded cost study, decoupling and other fixed charge

changes, PNM has begun to move towards the long-term solution. PNM is proposing to

change the customer charge for its rate classes to better reflect the allocated costs for

customer costs determined for the cost study as well as moving to a "straight fixed-

variable" approach for its larger customers through the use of higher demand and

customer charges. Also, as I will address below, PNM is proposing a revenue decoupling

pilot program for the Residential and Small Power Service classes in PNM North. Given

the rate disparity between the PNM North and PNM South classes and the volatility of

fuel costs for PNM South, which comprise a more significant portion of its cost of

service, PNM is not proposing revenue decoupling for PNM South at this time.

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HAVE YOU PRESENTED A RATE SCHEDULE FOR RESIDENTIAL

CUSTOMERS THAT ADJUSTS FIXED CHARGES FOR CUSTOMERS OTHER

THAN LOW-USE CUSTOMERS?

Yes. Pursuant to NMAC ¶17.7.2.gK(7)(a), provided in PNM Exhibit JAM-15, for

informational purposes only, is a rate schedule showing the effects of customer charges

remaining at $4.00 and $4.02 for only residential low-use customers for PNM North and

South, respectively. This illustrative schedule does not reflect the proposed fourth tier

pricing block for PNM North.

PLEASE DESCRIBE THE REVENUE DECOUPLING PILOT PROGRAM

PROPOSAL.

As discussed by PNM witnesses Darnell and Cavanagh, PNM is proposing to implement

a revenue decoupling pilot program applicable to customers within the Residential

Service (Schedules 1A and 1B) and Small Power Service (Schedules 2A and 2B)

customer classesfor PNM North. The revenue decoupling program consists of the

establishment of a Fixed Cost Recovery ("FCR") tariff that allows PNM to separate or

"decouple" collection of its fixed costs from its volumetric energy sales and provides

symmetry through a surcharge or credit when fixed cost recovery per customer varies

above or below a Commission-established base. In other words, the FCR will reconcile

the authorized fixed costs that PNM should be collecting from the small power and

residential customers and the fixed costs per kWh that it is actually collecting from sales

to those customers.

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The primary purpose of the FCR is the establishment of a tariff to track or "decouple" the

energy sales from fixed cost collection in order to remove the disincentive that exists as

customers reduce their energy usage. The FCR is designed to address the requirements of

the energy efficiency rule for a ratemaking methodology to remove regulatory barriers

necessary to achieve energy efficiency savings. In PNM’s decoupling proposal, the fixed

cost portion of PNM’s overall revenue requirement will be established in this case for the

two customer classes. Thereafter, the FCR will provide for the collection of the approved

fixed costs per individual customer regardless of the amount of actual sales to residential

and small power customers. Under this approach, the Company becomes largely

indifferent to changes in average customer use for residential and small power customers.

PNM’s proposal is similar to that which has been used for several years by Idaho Power.

WHY ARE YOU LIMITING THE FCR REVENUE DECOUPLING PILOT

PROGRAM TO CUSTOMERS IN THE RESIDENTIAL SERVICE AND SMALL

POWER SERVICE CLASSES?

PNM wants to take a gradual approach to the introduction of the FCR tariff in order to

gain experience and avoid unintended consequences. Residential Service and Small

Power Service customer classes represent the highest fixed cost exposure (on a

percentage basis) given the nature of their current rate designs. Average energy use

within these classes has a high correlation to the number of customers within these two

rate classes. Therefore the FCR tariff is initially better suited for application to rate

classes with large numbers of customers and low average use as compared to other high

use customer classes with smaller numbers of customers.

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PLEASE DESCRIBE THE FIXED COST RECOVERY TARIFF.

The FCR works identically for both the residential and small power customer classes.

The formula to determine the monthly FCR amount is:

FCR

Where:

FCR =

CUST =

FCC =

SALES =

FCE =

= (CUST X FCC) - (SALES X FCE)

Fixed Cost Recovery on an annual basis

Number of residential or small power customers at the end of each month

Test Period Fixed Individual Cost per Customer (S/Customer) for

residential or small power customers

Actual monthly energy sales to residential or small power

customers (kWh) ’

Test Period Fixed Cost per Energy (S/kWh) for residential

or small power customers

The first term in the equation (CUST x FCC) represents the fixed costs approved for

recovery. The second term (SALES x FCE) represents the fixed costs actually collected.

For each class, the actual number of customers in the Test Period (CUST) is multiplied

by the fixed cost per customer factor (FCC) calculated as a part of this case. This product

represents the "allowed fixed cost per customer recovery" amount. At the same time the

FCC is developed, a corresponding factor is developed on a per kWh basis (FCE). This

number, when multiplied by actual energy sales (SALES) during the following year

provides the "actual fixed costs recovered per kwh sales" amount. The FCR annual reset

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is the difference between the Company’s "allowed fixed cost recovery" and the "actual fixed

cost recovered".

PNM proposes that the FCR be in effect for approximately three years following the effective

date of new rates set in this case.

PLEASE DESCRIBE THE DEVELOPMENT OF THE FCC AND FCE FACTORS

FOR PHASE I AND PHASE II.

The development of the base level FCC and FCE factors for Phase ! and Phase II for the

Residential Service and Small Power Service has been provided on PNM Exhibit JAM-

16. As shown on this Exhibit, the development of the FCC and FCE factors for each

phase-in period consists of three steps. The first step is identification of the total fixed

costs for each customer class. Fixed costs for the residential and small power customer

classes consist of all production, transmission, and distribution demand allocated costs

and customer allocated costs. The identification of these costs and the associated revenue

requirements are calculated within the Company’s filed cost-of-service study (530

Schedule K-4 Embedded) and reproduced on PNM Exhibit JAM-16.

Once the total fixed cost revenue requirements are determined, the next step is to subtract

the portion of fixed costs that will be recovered through the customer charges embedded

in the rate tariffs for both classes (currently $4.00 for Residential Service and $7.75 for

Small Power Service). The remainder represents the total amount of fixed costs to be

recovered through volumetric energy charges, and represents the authorized fixed

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recovery amount. The authorized fixed cost recovery amount is shown on lines 15 (Phase

I) and 30 (Phase II) of PNM Exhibit JAM-16. The Phase I authorized fixed recovery

amounts are $253,854,383 for Residential customer classes and $73,699,476 for Small

Power customer classes. Dividing these amounts by the Test Period’s annualized monthly

customers produces Phase I FCC factors of $51.22/customer tbr the Residential customer

classes and $138.50/customer for the Small Power customer classes, as shown on Line

16, PNM Exhibit JAM-16. Similarly, taking the authorized fixed recovery amounts and

dividing them by each customer class’s respective Test Period energy sales produces

Phase I FCE factors of $0.0880790/kWh for the Residential customer classes and

$0.0857376/kWh for the Small Power customer classes, as shown on line 17, PNM

Exhibit JAM-16. The development of the Phase II FCE and FCC factors are shown on

lines 18-32 of PNM Exhibit JAM- 16.

PLEASE DESCRIBE THE PROCESS FOR IMPLEMENTATION OF THE FCR

TARIFF.

Once the base level FCC and FCE factors for each customer class are determined, a

monthly deferral balancing account would be established to accumulate the over/under

fixed cost recoveries to be used for resetting the FCR on an annual basis. At the end of

each month the number of residential and small power customers is multiplied by the

respective FCC factor. This product represents the "allowed fixed cost recovery"

amount. To determine the "actual fixed cost recovered" amount, PNM will take the

actual monthly energy sales for customers in each of the two classes for the month and

multiply that by the respective FCE factor. The difference between these two numbers

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(allowed fixed cost recovery amount minus the actual fixed costs recovered amount) for

each of the two classes represents the FCR that will be booked to the deferral balancing

account. Annually the FCR will be reset in a Commission proceeding, as described

below. PNM Exhibit JAM-17 provides a time line for the proposed decoupling pilot. The

FCR factor will be set to recover or refund the accumulated balancing account on an

annual basis. The annual amount to be refunded or collected would be limited to no more

than 3% of the FCE revenue with any deferred amount carried over to the next year. The

FCR is the collection of fixed costs per customer to allow recovery of the difference

between the fixed costs actually recovered through rates and the fixed costs per customer

authorized for recovery in this case. The total amount of fixed cost dollars recovered will

change with the addition of customers on the system.

CAN THE FCR RESET AMOUNT BE EITHER POSITIVE OR NEGATIVE?

Yes. The FCR can be either positive or negative. In years where customer growth is

greater than energy growth, an under-collection of authorized fixed costs will occur

triggering a positive FCR to collect the "lost" fixed costs from the residential and small

power customers in the following year. Conversely when energy growth is greater than

customer growth, an over-collection of fixed costs will be returned to the customers

through a rate reduction caused by a negative FCR.

WHEN IS PNM EXPECTED TO FILE THE ANNUAL FCR?

PNM will annually file with the Commission the FCR for the prior twelve months of

actual fixed cost recovery. The first filing would be for nine months. For example, with

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rates effective April 1,2011, PNM would file for the period from April 1,2011 through

December 31, 2011, by May 1, 2012, and request the FCR be implemented by July 1,

2012. The next two years of the decoupling pilot would be filed by May 1 using twelve

months of data and request implementation for the following twelve months beginning

July 1. PNM will also make a filing no later than May 1, 2014, with its recommendation

as to whether the FCR pilot should be continued, terminated or revised.

WILL A HEARING BE NECESSARY TO APPROVE THE FCR ANNUAL

FILING?

The Commission could schedule a heating to investig.ate if the calculations have been

performed correctly, but any hearings should be conducted so as to allow the factor to be

implemented by July 1. Because the Commission will have already established the

formula and the fixed costs per customer and per kWh costs to be recovered, only a

review of the calculation is necessary. The Commission could direct Staff and parties to

identify any disagreements with PNM’s application of the approved formula within ten

days of PNM’s filing so that the Commission can determine if a heating is necessary. If

no challenges are filed within the ten day period, the Commission can approve the factor

for implementation by July 1. If a hearing is determined to be necessary, the Commission

can then schedule it in time for the appropriate FCR factor to be implemented by July 1.

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HAVE YOU PREPARED AN EXAMPLE SHOWING THE EFFECT OF THE

FCR FOR THE PERIOD OF 2005 TO 2009?

Yes. I have prepared an example using the fixed cost calculation from the last two rate

cases to show what the FCR would have been if it had been in effect for the 2005-2009

time period using the fixed costs from the last two rate cases. As shown in PNM Exhibit

JAM-18, if an FCR tariff had been in place, the armual FCR calculated for the combined

residential and small power customers would have resulted in rate reductions to

customers due to over-collection of fixed costs from energy charges for the 2005-2008

period and a surcharge to customers due to under-collection of fixed costs from energy

charges for 2009. On an individual basis each customer class has years in which the

balance is positive (over-collection resulting in a refund) and negative (under-collection

resulting in an adder).

HOW DO YOU PROPOSE TO IMPLEMENT THE POSITIVE OR NEGATIVE

FCR?

The positive or negative balance for the FCR will be allocated to the Residential and

Small Power classes using forecasted sales for the twelve months of the FCR

implementation. I previously described PNM’s inclining block residential tariff design

and the addition of a fourth pricing tier. As an added energy efficiency incentive, we

propose that any negative FCR balance allocated to the Residential Class (indicating the

need for an FCR collection) be applied directly to the two higher usage blocks of the

Residential Service tariff to make up for the fixed cost under-recovery. Conversely, we

propose that any positive FCR balance (indicating the need for an FCR refund) be applied

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directly to the two lower usage blocks to refund a fixed cost over-recovery. This

approach significantly mitigates the impacts on low-use customers and those customers

who have implemented energy efficiency measures. It would also provide a greater

incentive to higher usage customers to participate in energy efficiency programs. Any

over or under recovery allocated to the Small Power customers will be applied on a

uniform per kwh basis using forecasted kWh.

We are also proposing that net revenues from the proposed new interconnected customer

rider be credited to the deferral balancing account. I describe this tariff and approach in

more detail in the next section of my testimony.

SHOULD THE COMMISSION CONSIDER A DECOUPLING TARIFF THAT

WOULD ALLOW THE COMPANY TO RECOVER WEATHER-ADJUSTED

FIXED COSTS THAT ARE LOST AS A RESULT OF ITS ENERGY

EFFICIENCY PROGRAMS?

No. PNM’s proposal does not include a weather adjustment to its actual sales, primarily

because weather effects balance out over the long run. This alleviates the need for annual

adjustments to sales that may be contentious. It also stabilizes customer bills by reducing

the ability to over or under recover due to weather variations.

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WHAT DISINCENTIVES TO CUSTOMER CONSERVATION MAY BE

CAUSED BY VIRTUE OF ADOPTING YOUR PROPOSED FCR?

Every unit of energy the customer avoids consuming will result in a savings to their

individual energy costs. Even if the opportunity for fixed cost recovery is improved

through a decoupling tariff (resulting in a possible FCR adder), the customer conserving

energy will siill see a net savings for every kWh they avoid. For example, the average

Phase I price/kWh for residential is $0.1227; the Phase I FCE price/kWh is $0.08808.

Even if fixed cost recovery is 100% under-recovered, the customer will still see a

minimum savings of $0.0346 per kWh for every kWh they don’t use. More than likely

they will see savings much closer to the full retail price. Any customer interested in

energy efficiency will still realize a savings and should therefore continue to be

encouraged to conserve.

The proposed FCR will further encourage energy efficiency in that additional recovery of

costs resulting from decoupling-related adjustments will be allocated to the higher usage,

higher priced tiers, and any credits will be allocated to the lower usage, lower priced tiers.

This approach encourages residential customers to reduce usage.

WHAT RATE DESIGN CHANGES WOULD BE APPROPRIATE IF THE

COMMISSION DOES NOT ADOPT THE FCR AS PROPOSED?

As I mentioned previously in my testimony, the Company is proposing to maintain the

current customer charges for Residential Service and Small Power Service of

$4.00/month and $7.75/month if its decoupling proposal is approved. PNM’s actual

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customer fixed costs for residential customers are approximately $13.00/month and

similar costs for small power service customers are nearing $28.00/month. If the

decoupling proposal is not approved, PNM would recommend that the Residential

Service customer charge be increased to $7.00/month and the Small Power Service

customer charge be increased to $12.00/month.

VI. NEW INTERCONNECTED CUSTOMERS

IS THE COMPANY PROPOSING TARIFFS TO RECOVER THE COSTS OF

ANCILLARY AND STANDBY SERVICES TO NEW INTERCONNECTED

CUSTOMERS AS PROVIDED FOR IN HB 181?

Yes. The Company is proposing Rider 34 in PNM North and Rider 4 in PNM South to

recover the cost of service to new interconnected customers.

WHAT DO YOU MEAN BY "NEW INTERCONNECTED CUSTOMER"?

PNM’s proposed tariffs define "new interconnected customer" consistently with the

definition contained in Section 2 of HB 181. Thus a "new interconnected customer" is a

utility customer who became interconnected with non-utility distributed generation

facilities after December 31, 2010, or whose REC purchase agreement entered into prior

to January 1,2011, is no longer effective after December 31, 2010.

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HOW HAS THE COMPANY DETERMINED THE COSTS TO BE COLLECTED

UNDER THESE RIDERS?

PNM is obligated to serve all customers on its system and as such must design its systems

to meet that obligation. Therefore, the class allocated fixed costs associated with the

service to these customers is no different from all other customers within the same rate

class. PNM has a significant portion of its fixed costs recovered through its variable

energy rate.

HOW DID PNM DETERMINE THE FIXED COSTS IN THE VARIABLE

ENERGY RATE?

Using the embedded class cost of service study, PNM calculated the total demand and

customer related charges, subtracted the revenue forecasted to be recovered through the

customer charges and divided the remaining costs by the forecasted energy. PNM

Exhibit JAM-19 shows the development of the fixed costs contained in the variable

energy rate. In order to reduce the number of different rates applicable to new

interconnected customers, customer classes were combined as appropriate to reflect

similar fixed costs per kWh.

WHAT DO THESE COSTS REPRESENT?

The fixed costs to be recovered by this Rider reflect the reasonably determinable

embedded and incremental costs of PNM to serve these customers and have them

interconnected to PNM system. As such they are costs associated with services that are

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essential to maintain electric system reliability and are required by, or are a consequence

of, interconnecting distributed generation facilities to PNM’s system.

ARE

REGULATION AND

VOLTAGE SUPPORT,

RESERVES?

THERE ADDITIONAL COSTS AT THIS TIME ASSOCIATED WITH

FREQUENCY RESPONSE, REGULATION AND

SPINNING RESERVES AND SUPPLEMENTAL

No. The costs for these services are included in the embedded cost study used to

calculate the fixed cost recovery associated with this Rider and so they represent the

reasonably determinable embedded and incremental costs to serve new interconnected

customers during the three-year period after the Rider is proposed to take effect.

ARE THE COSTS TO BE RECOVERED THROUGH THIS RIDER

DUPLICATIVE OF COSTS TO BE RECOVERED IN UNDERLYING RATES?

No. Although the costs identified for recovery in this Rider are included in the embedded

cost study, they will not be recovered in underlying rates due to the reduced usage

associated with customers interconnected to non-utility distributed generation facilities.

DO THE NON-UTILITY DISTRIBUTED GENERATION FACILITIES THAT

INTERCONNECT TO THE PNM SYSTEM PROVIDE ANY BENEFITS?

Yes, they do. Short-term benefits of distributed generation facilities include lower fuel

and purchased power costs and reduced losses. Long-term benefits include capacity

savings for generation and cost deferral savings for transmission.

92

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3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23



HAS PNM CALCULATED THE ANTICIPATED BENEFITS IN THE FIRST

THREE YEARS AFTER THIS RIDER GOES INTO EFFECT AS REQUIRED BY

HB 181?

Yes. PNM calculated the projected fuel and purchased power savings using the avoided

energy cost used in the 2009 PNM Energy Efficiency Program Annual Report adjusted

for current gas prices. PNM Exhibit JAM-20 summarizes the avoided cost. The average

overall system fuel and purchased power rates were reduced $.001119/kWh.

OTHER THAN THE AVOIDED FUEL COSTS, ARE THERE ANY OTHER

BENEFITS ATTRIBUTABLE TO THE NEW INTERCONNECTED

CUSTOMERS THAT ARE ACHIEVABLE IN THE THREE YEAR PERIOD

AFTER NEW RATES TAKE EFFECT?

Yes. If the energy from the distributed generation occurs at the time of peak, there is

some potential reduction in the cost of PNM’s demand response programs. As can be

seen on the graph in PNM Exhibit JAM-21, solar energy does not peak at the same time

as PNM’s peak and therefore has less of an impact on demand response programs. While

PNM does not expect distributed generation to fully offset the variable cost of the

demand response programs, PNM Exhibit JAM-20 provides the quantification of the

impact on the variable costs of the program based on the 2009 PNM Energy Efficiency

Program Annual Report. This is the first year PNM has claimed any demand response

from the load management programs. This potential benefit has been included in the

determination of the avoided costs for the reduction of the fixed cost component of the

rate.

93

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4

5

6

7

8

9

10

ll

12

13

14

15

16

17

18

19



HAS PNM QUANTIFIED OTHER SAVINGS DURING THE THREE YEAR

PERIOD?

No.

DOES THE COMPANY’S DECOUPLING PROPOSAL FOR PNM NORTH

RESIDENTIAL AND SMALL POWER CUSTOMERS ELIMINATE THE NEED

FOR THIS CHARGE TO THESE CUSTOMERS?

No. The charge to new interconnected customers reflects the specific fixed costs that the

Company is not recovering from these customers. Absent this charge, the Company has

only two ways to recover the fixed costs associated with serving these customers and

maintaining system reliability. These two methods are: a) by recovering the lost fixed

costs from other customers through increased customer or energy charges; or b) through

adding the unrecovered fixed costs to the FCR to the detriment of other customers. In

both cases, they represent a subsidy to the new interconnected customers by other

customers on the system. The legislation is specifically aimed at preventing this and

allowing the utility to collect its costs for serving these customers less reasonably

determinable benefits to the system achievable within the three year period during which

the Rider is expected to be effective. The Rider that PNM is proposing does this and

prevents subsidizing new interconnected customers by the other customers on the system.

94

1 Q.

2

3 A..

4

5

6

7

8

9

10

11

12 Q,

13

14 A.

15

16 Q.

17

19 A.

20



IS THE COMPANY DUPLICATING RECOVERY OF THESE COSTS

THROUGH THE RATE RIDER AS WELL AS THE FCR?

No. PNM is proposing that the net revenues from the Rider be applied to the annual

balance for the FCR. In this manner, the revenues from the Rider will either decrease any

under recovery or increase any over recovery that will be applied to the small power and

residential customers. This approach ensures that no duplication of cost recovery occurs

and provides the system benefit of collecting these fixed charges to all customers in the

small power and residential classes.

VII. MISCELLANEOUS

DOES THE COST OF SERVICE REFLECT THE TERMS OF STIPULATIONS

APPROVED BY THE COMMISSION?

Yes, as I have described in my testimony.

PLEASE IDENTIFY HOW PNM HAS COMPLIED WITH THE 2008 RATE

CASE ORDER AND RULE REQUIREMENTS WITH RESPECT TO COST OF

SERVICE.

PNM conducted workshops on cost allocation and rate design methodologies and is filing

both an embedded class (530 Schedule K-4 Embedded) and marginal class cost of service

(530 Schedule K-4 Marginal) and an elasticity study.

95

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3

4 51~3179



DOES THIS CONCLUDE YOUR TESTIMONY?

Yes.

96

PNM Exhibit JAM-1Page 1 of 2

Resume of James A. MayhewEducation and Regulatory Work Experience

Education

Master of Science Degree (Administration) from Central Michigan University

MBA Studies (Finance) University of Texas at El Paso

Bachelor of Business Administration Degree (Accounting) from the University ofTexas at El Paso

Industry Groups and Board RepresentationPrior Industry Representative Midwest ISO Advisory Board

Prior Industry Board Member representing the Wholesale Electric Quadrant forthe North American Energy Standards Board (NAESB)

Former Industry Board Member, Stakeholder Committee North American ElectricReliability Council (NERC)

Member EEl, EPSA and APPA Rate Committees

Si.qnificant Work Experience

Present Public Service Company of New MexicoDirector Pricing and Cost of ServiceResponsible for the direction and preparation of jurisdictional revenuerequirements and pricing for the regulatory filings of the Company.

2000 to 2008 Merchant Power Companies (Mirant and NRG Energy)Executive Regulatory Director responsible for regulatory requirements, advocacyand commercial analysis related to wholesale power trading within the organizedpower markets. Represented companies in the advocacy of business ruledevelopment for the wholesale power markets (PJM, CAISO, NYISO, MISO,ISO-New England, and ERCOT) and in rulemaking and tariff changes before theFERC. Responsible for developing regulatory changes to enhance commercialoptimization for existing and new generation assets.

1998 to 2000 Duke Solutions, Duke PowerRegulatory and Billing Director for Energy Service Company of Duke Power.Responsible for regulatory compliance and filings for Energy Service Company invarious retail jurisdictions where company sold natural gas, retail electricity and


energy services. Developed and created back office billing, invoicing andregulatory reporting functions and department for Energy Service Company.

1995 to 1998 Municipal Electric Authority of GeorgiaSenior Director/Executive responsible for billings, operating budget, energyservices and regulatory requirements for a Municipal Joint Action Agency thatprovided energy sales and services to 50 municipal cities in Georgia.

1980 to 1995 El Paso Electric CompanyVarious positions including Senior Manager/Executive responsible for thedevelopment of the revenue requirements of the company including rate designcost of service, energy efficiency, and regulatory compliance with state andfederal regulatory authorities.

Re.qulatory ExperienceHave provided expert testimony or comments before the following regulatory oradvisory bodies:

Federal Energy Regulatory Commission (FERC)New York State Public Service Commission (NYDPS)California Public Utility Commission (CPUC)Georgia Public Service Commission (GPSC)New Mexico Public Utility Commission (predecessor to New Mexico PublicRegulation Commission)New Mexico Public Regulation Commission

Case No. 08-000273-UTCase No. 08-000024-UTCase No. 09-00008-UTCase No. 10-00078-UTCase No. 10-00106-UTCase No. 10-00127-UT

Public Utility Commission of Texas (PUCT)City of El Paso, Texas Energy Advisory BoardNew York City Energy Policy Task ForceGeorgia Electric Cities Energy Policy GroupCartersville, Georgia City CouncilMarietta, Georgia Energy Advisory BoardWashington, Georgia City CouncilDoerun, Georgia City Council

Public Service Company of New Mexico2010 New Mexico Rate Case No. 10-00086-UTPNM Exhibit JAM-2


List of 530 Schedules Sponsored by James A. Mayhew

Schedule A Series: Summaries of the Proposed Cost of ServiceA-1 Summary of the Overall Cost of Service and the Claimed Revenue DeficiencyA-2 Summary of the revenue increase or decrease at the proposed rates by rate classes.A-3 Summary of the Cost of Service Adjustments by Functional Classification:A-4 Summaryof Rate Base CaseA-5 Summary of Total Capitalization and the Weighted Average Cost of Capital

Schedule B Series: Original Cost of Plant in ServiceB-1 Original Cost of Plant in Service by Primary AccountB-2 Original Cost of Plant in Service by Detail AccountB-3 Original Cost of Plant in Service by Monthly BalancesB-4 Construction Work in ProgressB-5 Allowance for funds used during construction transferred to plant in serviceB-6 Plant Held for future UseB-7 Nuclear fuel in process

Sche :tule C Series: Accumulated Provision for Depreciation and AmortizationC-1 Accumulated provision for depreciation and amortization by functional classification

and detailed plant accountC-2 Depreciation rate studyC-3 Depreciation and amortization methods

Sche,:~ule D Series: Original cost of plant in service adjusted to the cost of reproductionas a going concern and other elements of value- Optional

D-1 Original cost of plant in service adjusted to the cost of reproduction as a goingconcern and other elements of value- Optional

D-2 Cost of reproduction as a going concern and other elements of value adjustedfor age and condition- Optional

Schedule E Series: Working Capital AllowanceE-2 Materials and supplies, prepayments, and deferred chargesE-3 Fuel inventories by plant locationE-4 Amounts of working capital items charged to operating and maintenance expense

Schedule F Series: Other Property and InvestmentsF-1 Other property and investments

Public Service Company of New Mexico201(~ New Mexico Rate Case No. 10-00086-UTPNI~I Exhibit JAM-2



Schedule H Series: Expenses of Operation

H-7

H-14H-15H-I~;

Operation and maintenance expensesCost of fuelRevenue generated through the fuel adjustment clausePayroll distribution and associated payroll taxesExpenses associated with advertising, contributions, donations,lobbying and political activities, memberships, and outside servicesOther administrative and general expensesDepreciation and amortization expenseTaxes other than on incomeExpenses associated with affiliated interestsExpenses associated with nonutility servicesExplanation of the adjustments to expenses of operation.

Schedule I Series: Balance Sheet, Income Statement, Statement of Changes in Financial PositionI-1 Balance sheetI-2 Income statementI-3 Statement of changes in financial position

Sche.*lule J Series: Construction Program and Sources of Construction FundsJ-1 Construction program

Sche,Jule K Series: Fully Allocated Cost of Service StudyK-1 Allocation of Rate Base--jurisdictionalK-2 Allocation of Rate Base--functional classificationK-3 Allocation of Rate Base--demand, energy, and customerK-4 Allocation of Rate Base to rate classesK-5 Allocation of total expenses--jurisdictionalK-6 Allocation of total expenses--functional classificationK-7 Allocation of total expenses--demand, energy, and customerK-8 Allocation of total expenses to rate classes

Sche~tule L Series: Allocated Cost of Service per Billing Unit of Demand, Energy and CustomerL-1 Allocated cost per billing unit of demand, energy and customer

Schedule M Series: Allocation Factors

M-1M-2

Allocation factors used to assign items of plant and expenses to the various rate classes

Classification factors used to assign items of plant and expensesto demand, energy, and customer

Public Service Company of New Mexico201~) New Mexico Rate Case No. 10-00086-UTPNI~I Exhibit JAM-2



M-3 Demand and Energy Loss Factors

Sch~,dule N Series: Rate of Return by Rate ClassificationN-1 Rate of return by rate classification

Schedule 0 Series: Rate DesignO-I Total revenue requirements by rate classification0-:2 Proof of revenue analysis

0-3 Comparison of rates for service under the present and proposed schedules0-4 Explanation of proposed changes to existing rate schedules

Schedule P Series: Key Operating StatisticsPeak Demand InformationPlant in serviceProperty retirements and property investments informationOperation and maintenance expense informationCustomer informationWeather dataPower plant maintenance informationFuel statistics information

Sch~ dule Q Series: Required ReportsQ-" Load research programQ-.~’. Description of companyQ-,’-; Annual Report to stockholdersQ-z. Reports to the Securities and Exchange CommissionQ-[ Form 1 reportsQ-t~ Opinion of independent public accountants


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Publi,:: Services Company of New Mexico2010 ~lew Mexico Rate Case No. 10-00086-UTPNM :!xhibit JAM-4 PNM North


Comr,arison Sales and CustomersPNM qorth: Case 08-00273-UT to 2009 Base Year to 2011 Future Test Year

A B CLineNo. Rate Class Case 08-00273-UT Change

D

2009 Base Year

E

Change

FFTY 2011

(Including EnergyEfficiency)

123456789

101112131415161718192O212223242526272829303132

Customers1 - Residential 4,872,780 (71,105) 4,801,675 154,215 4,955,890

2 - Small Power 537,552 (16,389) 521,163 10,956 532,1193B/3C - General Power 46,932 509 47,441 15 47,456

4B - Large Power 2,832 58 2,890 39 2,9295B - Mines 46/115 kV 12 12 24 0 24

10 - Irrigation 3,264 94 3,358 (34) 3,32411B - Wtr/Swg Pumping 1,893 8 1,901 25 1,926

14B - Mines 115 kV 12 0 12 (12) 015B - Universities 115 kV 12 0 12 0 1217B - Manuf. (8 MW) 0 0 0 0 030B - Manuf. (30 MW) 12 0 12 0 12

6 - Private Lighting 0 0 0 0 020 - Streetli£1htin£ 0 1,352 1,352 16 1,368

Total 5,465,301 (85,461) 5,379,840 165,220 5,545,060

kW~h1 - Residential 3,007,671,240 (46,828,108) 2,960,843,132 (78,722,038) 2,882,121,094

2 - Small Power 910,748,432 (61,061,469) 849,686,963 9,906,022 859,592,9853B/3C - General Power 1,864,258,602 (106,977,085) 1,757,281,517 (23 356,735) 1,733,924,7824B - Large Power 1,534,153,331 (110,610,920) 1,423,542,412 (393,148) 1,423,149,2645B - Mines 46/115 kV 55,977,600 32,049,920 88,027,520 (27,520) 88,000,00010 - Irrigation 17,692,825 2,951,295 20,644,120 (3,831,906) 16,812,21311B - Wtr/Swg Pumping 196,259,329 (20,549,876) 175,709,453 40,502,133 216,211,586

14B - Mines 115 kV 38,449,837 (2,413,352) 36,036,485 (36,036,485) 015B - Universities 115 kV 117,072,716 (11,527,860) 105,544,856 12,859,468 118,404,32417B - Manuf. (8 MW) 0 0 0 0 0

30B - Manuf. (30 MW) 516,727,363 (49 815.955) 466,911,408 5,088,592 472,000,0006 - Private Lighting 12,475,224 (304,212) 12,171,012 32,652 12,203,66420 - Streetlightin9 45,798,888 717,152 46, 516,040 183,160 46,699,200Total 8,317,285,387 (374,370,470) 7,942,914,917 (73,795,806) 7,869,119,111

P~,blic Services Company of New Mexico2( 10 New Mexico Rate Case No. 10-00086-UTPHM Exhibit JAM-4 PNM South


C~mparison Sales and CustomersPHM South: Case 04-00315-UT to 2009 Base Year to 2011 Future Test Year

A B C D E

L ine Case 04-00315- 2009 Baserio. Rate Class

UT ChangeYear Change

F

F’rY 2011(Including Energy

Efficiency)

1 Customers2 Residential - Rate 1 502,080 27,5313 General Service - Rate 2 71,364 1,9054 Large General Service - Rate 3 732 1315 School Service - Rate 5 2,220 1006 Irrigation - Rate 6 288 (24)7 Municipal Power - Rate 12 & 13 1,488 838 4 - Outdoor Lighting Svc 0 09 14 - Street Li~htin~ Svc 732 671l0 Total 578,904 30,397I112 kW.~h

13 Residential - Rate 1 245,504,904 33,437,41514 General Service - Rate 2 150,520,202 (11,200,130)15 Large General Service - Rate 3 61,474,711 16,885,269!6 School Service - Rate 5 25,344,019 1,623,231’ 7 Irrigation - Rate 6 801,849 (435,671)’ 8 Municipal Power- Rate 12 & 13 12,835,110 7,886’ 9 4 - Outdoor Lighting Svc 5,474,306 (614,635)20 14 - Street Li~lhtin~ Svc 4,740,061 38,582:!1 Total 506,695,162 39,741,947:t2

529,61173,269

8632,320264

1,5710

1,403609,301

9,811232

1700101

10,116

539,42273,501

8642,390264

1,5720

1,404619,417

278,942,319139,320,07278,359,98026,967,250

366,17812,842,9964,859,6714,778,643

546,437,108

9,184,4616,426,897(1,708,976)1,545,290

71,774(172,667)96,053182,741

15,625,575

288,126,780145,746,96976,651,00428,512,540

437,95212,670,3294,955,7244,961,384

562,062,683


Public Services Company of New Mexico2010 New Mexico Rate Case No. 10-00086-UTTest ’(ear Ending 12/31/11PNM Exhibit JAM-5

LineNo. Significant Revenue Impact

Forecasted Revenues at existing rates1 Non-Fuel (w/o I&S Fees1)2 Base Fuel Revenue3 Forecasted Revenues at existing rates4 I&S Fees15 Fuel Factor- Effective July 20106 Miscellaneous Service Charges & Revenues7 Total Forecasted Base Revenues at Existing Rates

8 Fuel Factor- Effective July 2011 (Subject to Change)9 Miscellaneous Revenue Credits10 Total Forecasted Revenues

Deficiency11 ~Jon-Fuel Deficiency- As Requested12 ~ase Fuel Deficiency- As Requested13 vliscellaneous Service Charges14 &S Fees,15 Rate Deficiency- As Requested

APNM North

BPNM South

CTotal

161718

19202122

Revenue Requirement RequestedIqon-Fuel Revenue Requirement (w/o I&S Fees, )I~ase Fuel’otal Revenue Requirement as Requested before FAC and I&S Fees

Fuel Factor - Effective July 2010I&S Fees,I~liscellaneous Service Charges & Revenues’otal Retail Revenue Requirement

23 Fuel Factor- Effective July 2011 (Subject to Change)24 I/liscellaneous Revenue Credits25 Total Revenue Requirements

26

27

! ~ercent Increase (Line 15 divided by Line 7)

$ 535,815,367158,355,132

$ 694,170,4993,512,507

18,126,0881 475 588

717,284,682

012,716,212

$ 730,000,894

$ 139,329,72412,752,816

0769 539

$ 152,852,079

$ 675,145,091171,107,948846,253,038

18,126,0884,282,0461 475 588

870,136,761

012,716,212

$ 882,852,973

21.3%

$ 39,345,35021,266,627

$ 60,611,977306,697

02 662 653

63,581,327

4,687,285819 965

$ 69,088,578

$ 12,182,51173,382

0

$ 12,317,908

$ 51,527,86121,340,00972,867,870

0368,712

2 662 65375,899,235

4,687,285819 965

$ 81,406,486

19.4%

$ 575,160,716179,621,760

$ 754,782,4763,819,204

18,126,0884 138 241

780,866,009

4,687,28513,536,177

$ 799,089,472

$ 151,512,23512,826,198

0831 554

$ 165,169,987

$ 726,672,952192,447,957919,120,909

18,126,0884,650,7584 138 241

946,035,996

4,687,28513,536,177

$ 964,259,459

21.2%

Phase-In

28 Phase 1 - April 1, 2011 o December 31, 201129 Hon-Fuel30 F uel31 F’.ate Deficiency- Per Phase 1

32 F ercent Increase - Per Phase 1 (Line 31 divided by Line 7)

33 F base 2 - January 1, 201234 I~ on-Fuel Deficiency

35 F ercent Increase - Per Phase 2 (Line 34 divided by Line 7)

36 Total Phase.In37 Fate Deficiency - Total Phase-In

38 Percent Increase - Total Phase-In (Line 37 divided by Line 7)

PNM North$ 98,389,855

12,752,816$ 111,142,671

15.5%

$ 41,709,408

5.8%

$ 152,852,079

21.3%

1. Due to the nature of I&S Fees PNM is proposing a tax adj clause treatment similar to gross receipts2. Total is not reflective of the revenue requirement ff PNM North and South were consolidated.

PNM South$ 8,599,168

73,382$ 8,672,550

13.6%

$ 3,645,358

5.7%

$ 12,317,908

19.4%

Total$ 106,989,024

12,826,198$ 119,815,221

15.3%

$ 45,354,766

5.8%

$ 165,169,987

21.2%

PNM Exihbit JAM-5Page 2 of 9

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Publ ic Service Company of New Mexico201( New Mexico Rate Case No. 10-00086-UTTest Year Ending 12/31/11PNI~ Exhibit JAM 6Rate Case Expenses

Li=~eN,~. Description

A B CTotal Allocated Allocated

Electric PNM North1 PNM South,

Estimated Rate Case Expenses:

1,’;

17

18

Outside ConsultantsCase Preparation & Budget Process Testimony (ScottMadden)Pricewaterhouse CoopersGlobal Energy PartnersEffect of Regulatory Lag (Fetter Unlimited)Towers WatsonCognizantConcentricLoad Forecast (Continental Economics)Deloitte and ToucheMACDoug Gegax & Larry BlankAUS consultantsOutside Counsel (Cuddy & McCarthy, Miller Stratvert)Research & Polling, Inc.

Total Consultants

Other Costs (Reproduction, Postage, Etc.)

Total Estimated Rate Case Expenses

Estimated Rate Base(line 17 / 3 years)

521,45080,00041,54875,00080,45070,64075,000

192,63275,00074,31933,13392,000

700,0007,803

452 36969 40236 04465 06469 79261 28265 064

167,11265,06464,47328,74379,812

607,2646,770

69,08110,5985,5049,936

10,6589,3589,936

25,5209,9369,8464,389

12,18892,736

1,034

2,118,975 1,838,255 280,721

306,159 265,599 40,560

2,425,134 2,103,854 321,280

1,616,756 1,402,569 214,187

19 Estimated 2010 Rate Case Amortization ExpenseThree Year Amortization (line 17 / 3 years)

808,378 701,285 107,093

20

NOTE: In-house Legal Services are no.._jt included in the Rate Case Expensesfor this case.

Test Period Adjustment Calculation - Rate BaseEstimate Rate Base (line 18) 1,616,756 1,402,569 214,187

21 Total Test Period Adjustment 1,616,756 1,402,569 214,187

Test Period Adjustment Calculation - A & G Expense22 Estimated Amortization Expense (Line 19) 808,378 701,285 107,09323 Actual FPPCAC Audit Expenses 394,757 394,75724 Test Period A & G adjustment 1,203,135 1,096,041 107,093

Notes:1. PNM North allocated at 86. 75% and PNM South allocated at 13.25% based on Distribution W&S allocator from 530 Schedule K-1


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P~Jblic Services Company of New Mexico2010 New Mexico Rate Case No. 10-00086-UTT=.=st Year Ending 12/31/11PNM Exhibit JAM-8


Permian Basin Gas Prices

I.ineNo. Date $/mmBtu

1 3/1/2006 5.542 5/1/2006 5.363 7/1/2006 5.274 9/1/2006 5.335 11/1/2006 6.136 1/1/2007 5.277 3/1/2007 6.618 5/1/2007 7.109 7/1/2007 5.9810 9/1/2007 5.0311 11/1/2007 6.5912 1/1/2008 6.4313 3/1/2008 8.1014 5/1/2008 9.8115 7/1/2008 12.15’16 9/1/2008 6.92’17 11/1/2008 2.47’18 1/1/2009 4.46’19 3/1/2009 2.5220 5/1/2009 2.8021 7/1/2009 3.3722 9/1/2009 2.4823 11/1/2009 4.0224 1/1/2010 5.6225 3/1/2010 4.69


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Public Services Company of New Mexico2010 New Mexico Rate Case No. 10-00086-UTTest Year Ending 12/31/11PNM Exhibit JAM-8


Palo Verde Hub Market Prices (Firm Day-Ahead)

Off-Pk On-Pkl.ine No. Date $/MWh $/MWh

1 3/1/2006 37.89 47.592 5/1/2006 27.16 50.783 7/1/2006 35.61 55.704 9/1/2006 39.92 57.095 11/1/2006 46.73 53.976 1/1/2007 40.81 47.457 3/1/2007 43.68 56.958 5/1/2007 44.90 67.789 7/1/2007 50.03 76.5110 9/1/2007 43.38 64.6511 11/1/2007 46.44 60.5012 1 / 1/2008 51.92 60.0013 3/1/2008 57.51 68.0914 5/1/2008 65.89 84.2215 7/1/2008 72.79 133.1416 9/1/2008 48.40 68.2517 11/1/2008 29.72 34.4818 1/1/2009 39.85 39.4319 3/1/2009 20.49 27.0020 5/1/2009 20.28 28.1221 7/1/2009 22.27 36.2422 9/1/2009 18.74 31.0323 1111/2009 32.36 38.6424 1/1/2010 35.27 52.3225 3/1/2010 31.93 42.70


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For Informational Purposes Only

PUBLIC SERVICE COMPANY OF NEW MEXICO

PNM Exhibit JAM-15PNM NorthPage 1 of 6

RATE NO. 1A

RESIDENTIAL SERVICE

EXHIBIT JAM-15 PNM NORTH RESIDENTIAL 1A- PHASE I

Page X of X

APPLICABILITY: The rates on this Schedule are available for single-family houses, individual farmu=-=its, individual apartments, or separate living quarters ordinarily designated and recognized assingle-family living quarters for primarily domestic or home use. Service under this Schedule is nota, zailable for commercial rooming houses, multiple trailer parks, commercial, professional, orbusiness establishments and the like, which shall be served under another applicable commercialRate Schedule. All service shall be delivered at a single service location to be designated by theC3mpany.

S,~=rvice will be furnished subject to the Company’s Rules and Regulations and any subsequentrevisions. These Rules and Regulations are available at the Company’s office and are on file withthe New Mexico Public Regulation Commission. These Rules and Regulations are a part of thisS~;hedule as if fully written herein.

TERRITORY: All territory served by the Company in New Mexico.

T’(PE OF SERVICE: Service available under this Schedule will normally be 120/240 volt or1 ;10/208 volt single-phase service with single-phase motor operation being permitted where the sizeof individual motors does not exceed 5 HP. The following conditions of service also apply and arem :)re fully defined in the Company’s Rules and Regulations.

Three-phase service will be furnished under this Residential Rate Schedule only from existing linesor a 12-month continuous and non-seasonal basis.

NET RATE PER MONTH OR PART THEREOF FOR EACH SERVICE LOCATION: The rate forel,~ctric service provided shall be the sum of A, B, C, D, and E:

IN THE BILLING MONTHS OF: May-September October-April

(A) CUSTOMER CHARGE:(Per Metered Account)

$4.00/Bill $4.00/Bill

Advice Notice No. XX

Gerard OrtizDirector, Regulatory Policy & CaseManagement

GCG #XXXX

F or Informational Purposes Only


RATE NO. 1A


RESIDENTIAL SERVICEPage X of X

(B) ENERGY CHARGE:

First 200 kWh per MonthNext 500 kWh per MonthAll Additional kWh per Month

$0.0851206/kWh$0.1358579/kW h$0.1679010/kWh

$0.0851206/kWh$0.1172265/kWh$0.1206590/kW h

(C:) FUEL AND PURCHASED POWER COST ADJUSTMENT: The above rates are based upon abase fuel cost for energy approved in NMPRC Case No. 10-00086-UT. For this tariff, the baserate is $0.0217225 per kWh, effective for fuel and purchased power expenses incurredbeginning April 1,2011.

All kWh usage under this tariff will be subject to a Fuel and Purchase Power Cost AdjustmentClause ("FPPCAC") factor calculated according to the provisions in PNM’s Rider 23.

The appropriate FPPCAC factor will be applied to all kWh appearing on bills rendered underthis tariff.

(1"~) OTHER APPLICABLE RIDERS: Any other PNM riders that may apply to this tariff shall bebilled in accordance with the terms of those riders.

(E) SPECIAL TAX AND ASSESSMENT ADJUSTMENT: Billings under this Schedule may beincreased by an amount equal to the sum of the taxes payable under the Gross Receipts andCompensating Tax Act and of all other taxes, fees, or charges (exclusive of ad valorem, stateand federal income taxes) payable by the utility and levied or assessed by any governmentalauthority on the public utility service rendered, or on the right or privilege of rendering theservice, or on any object or event incidental to the rendition of the service.

M 9NTHLY MINIMUM CHARGE: The monthly minimum charge under this Schedule is the customercl" ,arge.

INTERRUPTION OF SERVICE: The Company will use reasonable diligence to furnish a regulararid uninterrupted supply of energy. However, interruptions or partial interruptions may occur ors~ rvice may be curtailed, become irregular, or fail as a result of circumstances beyond the control of



GCG #XXXX



RATE NO. 1A



tl" e Company, public enemies, accidents, strikes, legal processes, governmental restrictions, fuelshortages, breakdown or damages to generation, transmission, or distribution facilities of theCompany, repairs or changes in the Company’s generation, transmission, or distribution facilities,a~d in any such case the Company will not be liable in damages. Customers whose reliabilityr~quirements exceed those normally provided should advise the Company and contract foradditional facilities and increased reliability as may be required. The Company will not, under anycircumstances, contract to provide 100 percent reliability.

A’CCESSIBILITY: Equipment used to provide electric service must be physically accessible. Themeter socket must be installed on each service location at a point accessible from a public right-of-w.]y without any intervening wall, fence or other obstruction.

TERMS OF PAYMENT: All bills are net and payable within twenty (20) days from the date of bill. Ifpayment for any or all electric service rendered is not made within thirty (30) days from the date thebi I is rendered, the Company shall apply an additional late payment charge as defined in Rate 16Special Charges.

LIMITATION OF RATE: Electric service under this Schedule is not available for standby service,arid shall not be resold or shared with others.



GCG #XXXX



RATE NO. 1A



EXHIBIT JAM-15 PNM NORTH RESIDENTIAL 1A-PHASE II

Af~PLICABILITY: The rates on this Schedule are available for single-family houses, individual farmu~its, individual apartments, or separate living quarters ordinarily designated and recognized assingle-family living quarters for primarily domestic or home use. Service under this Schedule is nota,~ailable for commercial rooming houses, multiple trailer parks, commercial, professional, orbusiness establishments and the like, which shall be served under another applicable commercialRate Schedule. All service shall be delivered at a single service location to be designated by theC .~mpany.

S,~.rvice will be furnished subject to the Company’s Rules and Regulations and any subsequentrevisions. These Rules and Regulations are available at the Company’s office and are on file withthe. New Mexico Public Regulation Commission. These Rules and Regulations are a part of thisS~.hedule as if fully written herein.

TERRITORY: All territory served by the Company in New Mexico.

T’~’PE OF SERVICE: Service available under this Schedule will normally be 120/240 volt or1 ,’10/208 volt single-phase service with single-phase motor operation being permitted where the sizeof individual motors does not exceed 5 HP. The following conditions of service also apply and arem :)re fully defined in the Company’s Rules and Regulations.

Three-phase service will be furnished under this Residential Rate Schedule only from existing linesor a 12-month continuous and nonseasonal basis.

NET RATE PER MONTH OR PART THEREOF FOR EACH SERVICE LOCATION: The rate forel~ctric service provided shall be the sum of A, B, C, D, and E:

IN THE BILLING MONTHS OF: May-September October-April

(A), CUSTOMER CHARGE: $4.00/Bill $4.00/Bill



GCG #XXXX

F or Informational Purposes Only


RATE NO. 1A


(Per Metered Account)


([~) ENERGY CHARGE:

First 200 kWh per MonthNext 500 kWh per MonthAll Additional kWh per Month

$0.0905338/kWh$0.1444977/kW h$0.1785786/kW h

$0.0905338/kWh$0.1246815/kWh$0.1283323/kW h

(c:) FUEL AND PURCHASED POWER COST ADJUSTMENT: The above rates are based upon abase fuel cost for energy approved in NMPRC Case No. 10-00086-UT. For this tariff, the baserate is $0.0217225 per kWh, effective for fuel and purchased power expenses incurredbeginning April 1,2011.

All kWh usage under this tariff will be subject to a Fuel and Purchase Power Cost AdjustmentClause ("FPPCAC") factor calculated according to the provisions in PNM’s Rider 23.

The appropriate FPPCAC factor will be applied to all kWh appearing on bills rendered underthis tariff.

(D) OTHER APPLICABLE RIDERS: Any other PNM riders that may apply to this tariff shall bebilled in accordance with the terms of those riders.

(E.) SPECIAL TAX AND ASSESSMENT ADJUSTMENT: Billings under this Schedule may beincreased by an amount equal to the sum of the taxes payable under the Gross Receipts andCompensating Tax Act and of all other taxes, fees, or charges (exclusive of ad valorem, stateand federal income taxes) payable by the utility and levied or assessed by any governmentalauthority on the public utility service rendered, or on the right or privilege of rendering theservice, or on any object or event incidental to the rendition of the service.

MONTHLY MINIMUM CHARGE: The monthly minimum charge under this Schedule is the customercKarge.

II~TERRUPTION OF SERVICE: The Company will use reasonable diligence to furnish a regulararid uninterrupted supply of energy. However, interruptions or partial interruptions may occur or



GCG #XXXX

For Informational Purposes OnlyPNM Exhibit JAM-15

PNM NorthPage 6 of 6


RATE NO. 1A


service may be curtailed, become irregular, or fail as a result of circumstances beyond the control oftl-e Company, public enemies, accidents, strikes, legal processes, governmental restrictions, fuelshortages, breakdown or damages to generation, transmission, or distribution facilities of theCompany, repairs or changes in the Company’s generation, transmission, or distribution facilities,and in any such case the Company will not be liable in damages. Customers whose reliabilityr~quirements exceed those normally provided should advise the Company and contract fora~Iditional facilities and increased reliability as may be required. The Company will not, under anycircumstances, contract to provide 100 percent reliability.

A.3CESSIBILITY: Equipment used to provide electric service must be physically accessible. Themeter socket must be installed on each service location at a point accessible from a public right-of-way without any intervening wall, fence or other obstruction.

TERMS OF PAYMENT: All bills are net and payable within twenty (20) days from the date of bill. Ifpayment for any or all electric service rendered is not made within thirty (30) days from the date thebil is rendered, the Company shall apply an additional late payment charge as defined in Rate 16Special Charges.

LIMITATION OF RATE: Electric service under this Schedule is not available for standby service,arid shall not be resold or shared with others.



GCG #XXXX


PUBLIC SERVICE COMPANY OF NEW MEXICOTNMP SERVICES

PNM Exhibit JAM-15PNM SouthPage 1 of 6

ORIGINAL RATE NO, 1A

SCHEDULE RSRESIDENTIAL SERVICE

Page X of X

EXHIBIT JAM-15 PNM SOUTH RESIDENTIAL 1A - PHASE I

APPLICABILITY:

Residential customers in single family dwellings or apartments, which are separately metered by theCompany for single or three phase (where three phase facilities are adjacent to property served),60-hertz, 120/240-volt alternating current.

Not available for resale, temporary, breakdown, stand-by or seasonal service, nor to single phasen’otors in excess of 7 1/2 horsepower individual capacity, hotels or apartment houses where moretl’an one apartment is measured through one meter or any location where business is regularlyc(~nducted.

T,!-’RRITORY:

A :)plies to all service area of the Company in New Mexico.

MONTHLY RATE:

Tl~e rate for electric service provided shall be the sum of A, B, C, D and E below.

Ilk THE BILLING MONTHS OF: May-September October-April

(,a) Customer Charge: $4.02/Bill $4.02/Bill(Per Metered Account)

(El)

(c)

Energy Charge: $0.1198564/kWh $0.1141489/kW h

Fuel and Purchased Power Cost Adjustment: The above rates are based upon a basefuel cost for energy approved in NMPRC Case No. 10-00086-UT. For this tariff, the baserate is $0.0379673 per kWh, effective for fuel and purchased power expenses incurredbeginning April 1,2011.



GCG #XXXXX




ORIGINAL RATE NO. 1A


Page X of X

All kWh usage under this tariff will be subject to a Fuel and Purchase Power CostAdjustment Clause ("FPPCAC") factor calculated according to the provisions in PNM -TNMP Services Rider 3.

The appropriate FPPCAC factor will be applied to all kWh appearing on bills renderedunder this tariff.

Other Applicable Riders: Any other PNM TNMP Services riders that may apply to thistariff shall be billed in accordance with the terms of those riders.

(E) Tax Adjustment: Billings under this schedule may be increased by an amount equal tothe sum of the taxes payable under the Gross Receipts, Franchise Fees andCompensating Tax Act and of all other taxes, fees, or charges (exclusive of ad valorem,state and federal income taxes) payable by the utility and levied or assessed by anygovernmental authority on the public utility service rendered, or on the right or privilege ofrendering the service, or on any object or event incidental to the rendition of the service.

MINIMUM BILL

The minimum bill under this rate is the Customer Charge.

SPECIAL TERMS AND CONDITIONS:

This tariff schedule governs and supersedes all contracts or agreements between the Company andany of its customers served under this tariff schedule. Any service provided under this schedule isfu "[her subject to the Company’s rules and regulations on file with the New Mexico Public RegulationCommission. A contract may be required for extension of service under the Company’s extensionpolicy.

TERMS OF PAYMENT

AI bills are net and payable within twenty (20) days from the date of the bill. If payment for any or allel~:~ctric service rendered is not made within thirty (30) days from the date the bill is rendered, the



GCG #XXXXX






Page X of X

Company shall apply an additional late payment charge as defined in Rate 20 MiscellaneousS ~.=rvice Charges.



GCG #XXXXX






Page X of X

EXHIBIT JAM-15 PNM SOUTH RESIDENTIAL 1A - PHASE II

APPLICABILITY:

Residential customers in single family dwellings or apartments, which are separately metered by theCompany for single or three phase (where three phase facilities are adjacent to property served),60-hertz, 120/240-volt alternating current.

Not available for resale, temporary, breakdown, stand-by or seasonal service, nor to single phasen’otors in excess of 7 1/2 horsepower individual capacity, hotels or apartment houses where moretitan one apartment is measured through one meter or any location where business is regularlyc(}.nducted.

TI-.ERRITORY:

A;.~plies to all service area of the Company in New Mexico.

MONTHLY RATE:

The rate for electric service provided shall be the sum of A, B, C, D and E below.

Ilk THE BILLING MONTHS OF:

(,~) Customer Charge:(Per Metered Account)

May-September

$4.02/Bill

October-April

$4.02/Bill

(El)

(c)

Energy Charge: $0.1280018/kWh $0.1219065/kWh

Fuel and Purchased Power Cost Adjustment: The above rates are based upon a basefuel cost for energy approved in NMPRC Case No. 10-00086-UT. For this tariff, the baserate is $0.0379673 per kWh, effective for fuel and purchased power expenses incurredbeginning April 1,2011.



GCG #XXXXX

F,,~r Informational Purposes Only





Page X of X

All kWh usage under this tariff will be subject to a Fuel and Purchase Power CostAdjustment Clause ("FPPCAC") factor calculated according to the provisions in PNM -TNMP Services Rider 3.

The appropriate FPPCAC factor will be applied to all kWh appearing on bills renderedunder this tariff.

Other Applicable Riders: Any other PNM - TNMP Services riders that may apply to thistariff shall be billed in accordance with the terms of those riders.

(E) Tax Adjustment: Billings under this schedule may be increased by an amount equal tothe sum of the taxes payable under the Gross Receipts, Franchise Fees andCompensating Tax Act and of all other taxes, fees, or charges (exclusive of ad valorem,state and federal income taxes) payable by the utility and levied or assessed by anygovernmental authority on the public utility service rendered, or on the right or privilege ofrendering the service, or on any object or event incidental to the rendition of the service.

MINIMUM BILL

Tt" e minimum bill under this rate is the Customer Charge.

SPECIAL TERMS AND CONDITIONS:

Tt- is tariff schedule governs and supersedes all contracts or agreements between the Company andany of its customers served under this tariff schedule. Any service provided under this schedule isfurther subject to the Company’s rules and regulations on file with the New Mexico Public RegulationCommission. A contract may be required for extension of service under the Company’s extensionpolicy,

TERMS OF PAYMENT

All bills are net and payable within twenty (20) days from the date of the bill. If payment for any or allelectric service rendered is not made within thirty (30) days from the date the bill is rendered, the



GCG #XXXXX






Page X of X

Company shall apply an additional late payment charge as defined in Rate 20 MiscellaneousService Charges.



GCG #XXXXX

Public Services Company of New Mexico2010 N .=w Mexico Rate Case No. 10-00086-UTTest Y~ar Ending 12/31111PNM E ~hibit JAM-16 PNM North

Develo ~ment of Fixed Cost Recovery (FCR) Rider

LineNo.

12

3456789

1011121314

15

1617

DescriptionT, ,~st Period UnitsA lnual Number of CustomersA ~nual Energy Sales

P ~ase I Revenue Requirements by Cost Component (1)Customer Revenue Requirements (Fixed)Demand Revenue Requirements (Fixed)

Total Fixed Cost RequirementsEnergy (Non-Fuel) Revenue Requirements (Variable)Base Fuel Requirements (Variable)

1"otal Variable Cost RequirementsT=~Ial Phase I Revenue Requirements

PItase I Pricing by Revenue Component (t)::ustomer Charge Revenues (2):)emand Charge Revenues=’!nergy Charge Revenues

T(,tal Phase I Revenues:ixed Cost Recovery: Customer and Demand Charges:ixed Cost Recovery: Variable Energy Charges (3)

PIIASE I FCC AND FCE FACTOR SUMMARIES:ixed Cost per Customer Factor (FCC)

:ixed Cost per Energy Factor (FCE)

A B C DResidential Service Small Power Service

Schedules 1A and 1B Schedules 2A and 2BRev Reqmts - $ Unit Costs Rev Reqmts - $ Unit Costs

4,955,8902,882,121,094

60,382,657 12.18 14,494,292213,349,757 43.05 63,492,418273,732,414 55.23 77,986,709

17,225,725 0.0059768 5,460,30362,606,981 0.0217225 18,672,54079,832,706 0.0276993 24,132,844

353,565,120 0.1226753 102,119,553

19,878,031 4.01 4,287,233

333,687,089 0.1157783 97,832,320353,565,120 0.1226753 102,119,553

19,878,031 4,287,233253,854,383 73,699,476

253,854,383 $ 51.22 73,699,476 $253,854,383 $ 0.0880790 73,699,476 $

Pt,ase II Revenue Requirements by Cost Component (t)18 Customer Revenue Requirements (Fixed)19 I)emand Revenue Requirements (Fixed)20 Total Fixed Cost Requirements21 Energy (Non-Fuel) Revenue Requirements (Variable)22 I~ase Fuel Requirements (Variable)23 Tctal Variable Cost Requirements24 Tclal Phase II Revenue Requirements

64,786,594 13.07 15,063,584228,910,166 46.19 65,986,212293,696,760 59.26 81,049,796

18,482,062 0.0064127 5,674,76862,606,981 0.0217225 18,672,54081,089,043 0.0281352 24,347,308

374,785,803 0.1300382 105,397,104

PI-ase II Pricing by Revenue Component (1)25 ( ~ustomer Charge Revenues (2) 19,878,031 4.01 4,287,23326 [)emand Charge Revenues27 Einergy Charge Revenues 354,907,772 0.1231412 101,109,87128 To :al Phase I Revenues 374,785,803 0,1300382 105,397,10429 Fixed Cost Recovery: Customer and Demand Charges 19,878,031 4,287,23330 Fixed Cost Recovery: Variable Energy Charges (3) 273,818,729 76,762,563


Notes

532,119 CUST859,592,985 kWh SALES

27.24 S/CUST119.32 $/CUST146.56 L3 + L4

0.0063522 S/kWh SALES0.0217225 S/kWh SALES0.0280747 L6 + L70.1187999 L5 + L8

8.06 S/CUST

o. 1138124 S/kWh SALES0.1187999 L10+L11+L12

L10+L11

L5-L14

138.50 L15/CUST0.0857376 L15/SALES

28.31 S/CUST124.01 S/CUST152.32 L18 + L19

0.0066017 S/kWhSALES0.0217225 S/kWh SALES0.0283242 L21 + L220.1226128 L22 + L23

8.06 $/CUST

0.1176253 S/kWhSALES0.1226128 L25+L26+L27

L25 + L26

L20- L29

3132

PI’ASE II FCC AND FCE FACTOR SUMMARIESf ixed Cost per Customer Factor (FCC) 273,818,729 $ 55.25 76,762,563 $ 144.26f ixed Cost per Energy Factor (FCE) 273,818,729 $ 0.0950060 76,762,503 $ 0.0893011

(~) ~evenue requirements without revenue tax(2){’ixed metering costs in Schedules 1B and 2B raise the average S/customer above the $4.00 and $7.75 for Residential 1A and Small Power 1A(3), ~llowed fixed cost recovery" amount

L30/CUST

L30/SALES

PNM Exhibit JAM 17

~3z

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Public Services Company of New Mexico2010 I~ew Mexico Rate Case No. 10-00086-UTTest Y .~ar Ending 12/31111PNM Exhibit JAM-19 PNM NorthDevelc pment of Fixed Cost Recovery Requirements for New Interconnected Customers

ASchedules 1-2

Line Residential SrvNo. Description Small Pwr Srv

1 ,~nnual Number of Customers 5,488,0092 ,~nnual Energy Sales 3,741,714,079

F hase I Revenue Requirements by Cost Component (t)3 Customer Revenue Requirements (Fixed)4 Demand Revenue Requirements (Fixed)5 Total Fixed Cost Requirements6 Energy (Non-Fuel) Revenue Requirements (Variable)7 Base Fuel Requirements (Variable)8 Total Variable Cost Requirements9 T:~tal Phase I Revenue Requirements

Phase I Pricing by Revenue Component(t)

10 Customer Charge Revenues

11 Demand Charge Revenues12 !--nergy Charge Revenues13 T~tal Phase I Revenues14 Fixed Cost Recovery: Customer and Demand Charges15 Fixed Cost Recovery: Variable Energy Charges

BSchedules 3-4-11Gen Pwr Sty, LrgPwr Srv, Wtr/Swr

52,3113,373,285,631

CSchedules 15-30

Industrial PwrUniv - Mfg

24590,404,324

74,876,949 5,120,497 312,029276,842,175 193,617,260 22,688,916351,719,124 198,737,757 23,000,946

22,686,028 20,719,032 3,352,92981,279,522 72,944,111 12,519,273

103,965,549 93,663,143 15,872,201455,684,673 292,400,900 38,873,147

41,289,603 61,191,546 5,252,18952,707,333 5,172,522

414,395,070 178,502,022 28,448,437455,684,673 292,400,901 38,873,147

41,289,603 113,898,879 10,424,710310,429,521 84,838,879 12,576,235

Notes

L3 + L4

L6 + L7L5 + L8

L10+L11+L12L10 + Lll

L5- L14

P ~ase I - DG Fixed Cost Recovery Requirements16 Fixed Cost Recovery on kWh Basis17 Less: Avoided Fuel Cost!8 Avoided Energy Losses19 Avoided Load Management20 Phase I - Fixed Cost Recovery Charge - $1kW11

Pilase II Revenue Requirements by Cost Component (t)

21 Customer Revenue Requirements (Fixed)22 Demand Revenue Requirements (Fixed)23 Total Fixed Cost Requirements24 Energy (Non-Fuel) Revenue Requirements (Variable)25 Base Fuel Requirements (Variable)26 [oral Variable Cost Requirements27 T(,tal Phase II Revenue Requirements

Please II Pricing by Revenue Component (t)28 ~;ustomer Charge Revenues29 .)emand Charge Revenues30 ~!nergy Charge Revenues31 T(tal Phase II Revenues32 :ixed Cost Recovery: Customer and Demand Charges33 :ixed Cost Recovery: Variable Energy Charges

$ 0.082965 $ 0.025150$ 0.001112 $ 0.001095$ 0.000078 $ 0.000076$ 0.000007 $ 0.000007$ 0.0817676 $ 0.0239721

$$$$$

0.0213010.0010810.0000750.000007

0.0201376

L15/L2

L16-L17-L18-L19

79,850,178 5,441,314 339,376294,896,378 205,818,416 24,672,932374,746,556 211,259,731 25,012,308 L21 + L22

24,156,830 22,043,352 3,648,05581,279,522 72,944,111 12,519,273

105,436,351 94,987,463 16,167,328 L24 + L25480,182,908 306,247,193 41,179,636 L23 + L26

41,289,603 63,753,226 5,551,30755,241,236 5,468,350

438,893,305 187,252,731 30,159,979480,182,908 306,247,194 41,179,636

41,289,603 118,994,463 11,019,657333,456,953 92,265,268 13,992,651

Please II - DG Fixed Cost Recovery Requirements34 i-ixed Cost Recovery on kWh Basis $ 0.089119 $ 0.027352 $ 0.02370035 Less: Avoided Fuel Cost $ 0.001112 $ 0.001095 $ 0.00108136 Avoided Energy Losses $ 0.000078 $ 0.000076 $ 0.00007537 Avoided Load Management $ 0.000007 $ 0.000007 $ 0.00000738 Phase II - Fixed Cost Recovery Charge - $/klNh $ 0.0879215 $ 0.0261736 $ 0.022536639 Protypical 1 kW AC Output Solar Installation (195 kWh/Mo) $ 17.14 $ 5.10 $ 4.39

L28+29+230L28+ L29L23-L32

L34/L2

L34o35-36-37L38"195

Revenue requirements without revenue tax( ~Assumes 1 kW AC output on the customer’s side of the meter and average insolation hours / month (195)

Public ~ervices Company of New Mexico2010 N .~.w Mexico Rate Case No. 10-00086-UTTest Y~,ar Ending 12/31111PNM E (hiblt JAM-19 PNM SouthDevelo ~ment of Fixed Cost Recovery Requirements for New Interconnected Customers

LineNo.1 A~lnual Number of Customers2 A~nual Energy Sales

Description

A BSchedules 1,2,5 Schedule 3

Residential, General, LargeSchool General

615,313 864462,386,289 76,651,004


Notes

Pllase I Revenue Requirements by Cost Component (1)3 Customer Revenue Requirements (Fixed)4 Demand Revenue Requirements (Fixed)5 l’otal Fixed Cost Requirements6 Energy (Non-Fuel) Revenue Requirements (Variable)7 Base Fuel Requirements (Variable)8 i"otal Variable Cost Requirements9 T(,tal Phase I Revenue Requirements

6,209,146 63,05032,355,795 4,373,53038,564,941 4,436,580 L3 + L4

2,282,012 366,68817,467,181 2,895,58119,749,193 3,262,269 L6 + L758,314,134 7,698,848 L5 + L8

Please I Pricing by Revenue Component (1)

! 0 , ~;ustomer Charge Revenues11 Oemand Charge Revenues12 I~inergy Charge Revenues13 Total Phase I Revenues14 I:ixed Cost Recovery: Customer and Demand Charges15 I-ixed Cost Recovery: Variable Energy Charges

4,686,648 1,255,0682,095,604

53,627,485 4,348,17758,314,134 7,698,848

4,686,648 3,350,67133,878,292 1,085,909

L10+11+12

L10 + LliL5- L14

Pf ase I - Interconnected Customer Fixed Cost Recovery Requirements16 Fixed Cost Recovery on kWh Basis17 Less: Avoided Fuel Cost18 Avoided Energy Losses19 Avoided Load Management20 Phase I - Fixed Cost Recovery Charge - S/kWh

0.0732684 0.01416690.0011121 0.00111210.0000776 0.00007760.0000072 0.00000720.0720714 $ 0.0129700

L15 ! L2Exhibit JAM-20Exhibit JAM-20Exhibit JAM-20

L16-L17-L18-L19

PI, ase II Revenue Requirements by Cost Component (i)

22 Customer Revenue Requirements (Fixed)23 Demand Revenue Requirements (Fixed)24 ~’otal Fixed Cost Requirements25 Energy (Non-Fuel) Revenue Requirements (Variable)26 Base Fuel Requirements (Variable)27 1Oral Variable Cost Requirements28 To al Phase II Revenue Requirements

Ph ase II Pricing by Revenue Component (1)29 (~ ustomer Charge Revenues30 [~emand Charge Revenues31 Energy Charge Revenues32 Toal Phase II Revenues33 Fixed Cost Recovery: Customer and Demand Charges34 Fixed Cost Recovery: Variable Energy Charges

Ph ~se II - Interconnected Customer Fixed Cost Recovery Requirements35 Fi×ed Cost Recovery on kwh Basis36 Less: Avoided Fuel Cost37 Avoided Energy Losses38 Avoided Load Management39 P hase II - Fixed Cost Recovery Charge - $1kWh

6,687,079 68,85034,769,753 4,775,85441,456,832 4,844,704 L22 + L:23

2,449,829 400,41917,467,181 2,895,58119,917,010 3,296,000 L25 + L2661,373,842 8,140,704 L24+L27

4,686,648 1,325,4312,216,418

56,687,194 4,598,85561,373,842 8,140,704

4,686,648 3,541,84936,770,184 1,302,855

40

L29+L30_L31L29 + L30L24- L33

E’.xample: Protypical 1 kW AC Output Solar Installation (2) $

Revenue requirements without revenue tax{2)Assumes 1 kW AC output from the inverter and average insolation hours / month (200)

15.27 $ 3.08

0.0795227 0.0169972 L34 / L20.0011121 0.0011121 Exhibit JAM-200.0000776 0.0000776 Exhibit JAM-200.0000072 0.0000072 Exhibit JAM-200.07R~7 $ 0.0158003 L35-36-37-38

PNM Exhibit JAM-21Pa.qe 1 of 2

Watts per Square Meter

| I | |

/I I

|

PNM Exhibit JAM-21Paqe 1 of 2

Watts per Square Meter

BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION

IN THE MATTER OF THE APPLICATIONOF PUBLIC SERVICE COMPANY OF NEWNEXICO FOR REVISION OF ITS RETAILELECTRIC RATES PURSUANT TO ADVICEN I)TICE NOS. 397 AND 32 (FORMERT~MP SERVICES),

P13BLIC SERVICE COMPANY OF NEWM IEXICO,

Applicant.

))))))))))

Case No. 10-00086-UT

AFFIDAVIT OF JAMES A. MAYHEW

STATE OF NEW MEXICO )) ss

COUNTY OF BERNALILLO )

James A. Mayhew, Director of Pricing and Cost of Service for PNM, upon being duly

s~om according to law, under oath, deposes and states: I have read the foregoing Direct

Testimony, including Exhibits, and it is true and accurate based on my own personal knowledge

an,] belief.

SIGNED this ~ day of May, 2010.

A. MAYHE ~/ ~

S[ IBSCRIBED AND SWORN to before me this day of May, 2010.~..._~

~AI~Y PUBLIC IN AND FORTHE STATE OF NEW MEXICO

My CommissionExpires:

GCG # 503047

new mexico

Documents

piim exhibit jam

jm exhibit jam

p nm exhibit jam

table jam

lble jam

pnm north

pnm south

pnm direct testimony