V )/media/Files/P/PNM... · PNM Exhibit PJ0-6 AFFIDAVIT Resume of Patrick J. O'Connell Current Load and Resource Projections Summary of Regional Haze Compliant Portfolios Revised

BJi:FORE THE NE\V l\;IEXICO PUBLIC REGULATION COl\;lMISSION

IN THE MATTER OF THE APPLICATION ) OF PUBLIC SERVICE COMPANY OF NEW ) l\IIEXICO FOR APPROVAL TO ABANDON ) SAN JUAN GENERATING STATION UNITS ) 2 AND 3, ISSUANCE OF CERTIFICATES ) OF PUBLIC CONVENIENCE AND ) NECESSITY FOR REPLACEl\;IENT PO\VER ) RESOURCES, ISSUANCE OF ACCOUNTING ) ORDERS AND DETERMINATION OF ) RELATED RATEMAKING PRINCIPLES AND) TREATMENT, )

) PlJBLIC SERVICE COMPANY OF NE\V ) l\IIEXICO, )

)

Applicant ) ______________________________ )

Case No.13-00 _____ -UT

DIRECT TESTil\;10NY AND EXHIBITS

OF

PATRICK J, O'CONNELL

December 20, 2013

NMPRC CASE NO. 13-00 -UT INDEX TO THE DIRECT TESTIMONY OF PATRICK J, O'CONNELL

WITNESS FOR PUBLIC SERVICE COMPANY OF NEW MEXICO

I. INTRODUCTION, PURPOSE AND KEY CONCLUSIONS ................................ l

U. PNM'S EXISTING RESOURCES .......................................................................... 5

III. COMPARISON OF POTENTIAL RESOURCE PORTFOLIOS TO COMPLY WITH THE REGIONAL HAZE RULE ................................................ 9

IV. RELATIONSHIP TO 2014-2033 IRP ................................................................... 23

V. CONCLUSIONS ................................................................................................... 25

PNM Exhibit PJ0-1

PNM Exhibit PJ0-2

PNM Exhibit PJ0-3

PNM Exhibit PJ0-4

PNM Exhibit PJ0-5

PNM Exhibit PJ0-6

AFFIDAVIT

Resume of Patrick J. O'Connell

Current Load and Resource Projections

Summary of Regional Haze Compliant Portfolios

Revised SIP Load and Resource Projections

Resource Modeling Assumptions

SJGS Unit 4 Additional Capacity Portfolio Comparison

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DIRECT TESTIMONY OF PATRICK J. O'CONNELL

NMPRC CASE NO. 13-00 -UT

I. INTRODUCTION, PURPOSE AND KEY CONCLUSIONS

PLEASE STATE YOUR NA~IE, POSITION AND BUSINESS ADDRESS.

My name is Patrick J. O'Connell. I am Director, Planning and Resources, for

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

414 Silver Avenue, S\V, Albuquerque, New Mexico 87102.

PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR,

PLANNING AND RESOURCES.

I oversee PNM' s Integrated Resource Planning <md Energy Efficiency Design teams.

The Integrated Resource Planning team is resporL.;;ible for developing PNM' s resource

plans and the regulatory filings to support those resource plans, including PNM's

Integrated Resource Pl<:m ("IRP") that is required to be filed every three years with the

New Mexico Public Regulation Commission ("Commission" or ''NMPRC") tmder

17.7.3 NMAC ("IRP Rule"). The Energy Efficiency Design team develops PNM's

energy efficiency and load management program plans and the regulatory filings to

support them.

HAVE YOU PREVIOUSLY TESTIFIED IN UTILITY REGULATORY

PROCEEDINGS?

Yes. A list of the NMPRC proceedings in which I have either testified or filed

testimony is included in the statement of my expe1ience and qualifications that 1s

attached to my testimony as PNM Exhibit PJ0-1.

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'WH.A.T IS THE PURPOSE OJ<"' YOUR DIRECT TESTIMONY?

My testimony demonstrates that the most cost-effective means of complying with the

Regional Haze Rule adopted by the Environmental Protection Agency ("'EPA")

pursuant to the Clean Air Act is to retire Units 2 and 3 at the San Juan Generating

Station ("SJGS") and install selective non-catalytic reduction technology ("SNCR'') on

the remaining two units in accordance with the Revised State Implementation Plan

("Revised SIP"), and replace the capacity of the retired units with a portfolio of

resources that includes nuclear, natural gas, renewable generation and additional

capacity in SJGS Unit 4. Specifically, I will:

• Describe the costo;; and benefit-> to PNM's customers of complying with the Revised

SIP as opposed to complying with the Federal Implementation Plan ("FIP") adopted

by the U.S. Environmental Protection Agency ("EPA'');

• Describe how PN'M used the IRP process to obtain public input on the plant

retirements and additions proposed in this filing and how it will use the ongoing IRP

process to help refine the selection of resource additions for which PNM will seek

Commission approval in the future: and

• Describe why it is in the public interest to approve the plant retirements and

certificates of public convenience and necessity ("CCN") for plant additions that

PNM is requesting in this case.

In the course of developing these points, I will also describe how complying with the

Revised SIP will affect PNM's existing generation resource pmtfolio and identify and

compare alternative generation resource po1tfolios that could comply with the Regional

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NJ\!IPRC CASE NO. 13-00 -UT

Haze Rule requirements at SJGS, but at higher cost than what PNM is proposing in this

proceeding.

DO YOU HAVE ADDITIONAL EXHIBITS?

Y cs. They are as follows:

• PNM Exhibit PJ0-2: Cunent Load and Resource Projections

• PNM Exhibit PJ0-3: Summary of Regional Haze Compliant Portfolios

• PNN1 Exhibit PJ0-4: Revised SIP Load and Resource Projections

• PNM Exhibit PJ0-5: Resource Modeling Assumptions

• PNM Exhibit PJ0-6: SJGS Unit 4 Additional Capacity Portfolio

Comparison

PLEASE EXI>LAIN THE DIFFERENCE BETWEEN THE REVISED SIP 1\i~D

THE FIP.

Both the Revised SIP and the FIP are implementation plans requiring SJGS to take

specified actions in order to comply with the Regional Haze Rule. Both require

investment in Pl\TM's generation fleet. The Revised SIP, in comparison to the FIP.

allows PNM to invest in a more balanced resource portfolio that will reduce overall

costs to PNM's customers and will reduce the environmental impact of the service PN11

provides. The requirements at SJGS tmder the Revised SIP and the FIP are summmized

as follows:

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NMPRC CASE NO. 13-00 -GT

• The Revised SIP requires installation of SNCR technology on SJGS Units 1 <md 4

by the later of J <muary 31, 2016, or 15 months after the Revised SIP is approved by

EPA, and retirement of SJGS Units 2 and 3 by December 31, 2017.

• The FIP requires installation of selective catalytic reduction ("SCR") teclmology on

all four units of SJGS by September 21, 2016.

The Revised SIP must be approved by the EPA before it will replace the FIP. The

process that led to the two implementation plans is described in Mr. Dam ell· s

testimony.

\VHAT ARE THE PRINCIPAL CONCLUSIONS OF YOUR TESTIMONY?

First, retiring SJGS Units 2 and 3 and installing SNCR teclmology on Units l and 4 in

accordance with the Revised SIP, and replacing the retired capacity by adding nuclear,

natural gas, renewable resources and additional capacity in SJGS Unit 4, is in PNM's

customers' best interest because these actions are less costly over the 20-year planning

period th<m installing SCR technology at SJGS, as required by the FIP. Second, the

most cost-effective portfolio of resources to replace the retired coal capacity at SJGS

includes the addition of 134 MW of capacity in Palo Verde Nuclear Generating Station

("'PVNGS'') Unit 3 at a cost of $2,500/kW. Third, this most cost-effective portfolio of

resources is less risky compared to either the FIP or a portfolio that relies more heavily

on gas-fired generation rather than using PVNGS Unit 3. The Revised SIP allows PNM

to invest money that would be spent on SCR tmder the FIP on generation additions that

will reduce costs in the futme, reduce the risk associated with coal generation in PNM' s

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DIRECT TESTlMONY OF PATRICK J. O'CONNELL

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supply portfolio and reduce the emissions associated with generating electricity to meet

customers' needs. The most cost-effective portfolio of new resources to replace Units 2

and 3 includes nuclear, solar, gas peaking resources and additional capacity in SJGS

Unit 4. TI1e investment in these replacement resources will produce lower fuel and

operation and maintenance costs going fmward, which reduces future costs to customers

compared to compliance with the FIP. The resulting replacement resources will reduce

greenhouse gas emissions without a significant increase in reliance upon natural gas

generation so as to reduce the risk of cost increases associated with future environmental

regulations affecting greenhouse ga<; emitting sources and the risk associated with price

volatility of natural gas. These conclusions are based on a comprehensive analysis of

various resource pmtfolio options using the Strategist® modeling software and other

quantitative <md qualitative analytic tools.

II. PNl\tl'S EXISTING RESOURCES

PLEASE DESCRIBE Pl\M'S EXISTING PORTFOLIO OF GENERATION

RESOURCES.

PNM provides service to its half million customers by generating electricity at PNM-

owned power plants and by purchasing capacity and energy tmder long tenn power

purchase agreements ("PP A"), a..s well as by making short term market purcha.<;es as

needed. Electricity is delivered from generation resources to PNM' s customers through

a system of elecuic transmission and distribution lines. The current mix of generation

resources that provides NMPRC-regulated electric service includes resources

fueled by coal, nuclear and natural gas and wind and solar pO\vered resources as

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shown on Table PJ0-1. In addition to the supply-side resources shown on this

table, PNM reduces the need for electric generation using demand-side resources

such as energy efficiency and load management programs. Other PNM programs

and tariffs encourage PNM customers to install solar photovoltaic (''PV") systems

behind their meters, which reduce the amount of electricity PNM generates to

serve its customers. Presently, over 3,800 PV systems are in place.

Table PJ0-1 PNM' E . f G ti R 1 s .XIS mg en era on esources

PNM Share Operating In-Service

Resources Fuel Ty[!e PNM Share ofCapaciti Agent Date

OVIW's2

San Juan Coal 46.4 o/c 783 1973-1982 PNM

Palo Verde Units Nuclear 10.2% 268 1985-1986 APS

1&2 Four Comers Coal 13% 200 1969-1970 APS Units 4 & 5

Afton Natural Gas 100% 230 ' 2002 PNM

Reeves Natural Gas lOO% 154 1958-1962 PNM

Lordsburg Natural Gas 100% 80 2002 PNM

Luna Energy Natural Gas 33.3% 185 2006 PNM Facility

Delta (PPA) Natural Gas N/A 138 2001 Delta-Person LP

Valencia (PPA) I Natural Gas N/A 14:"i 2008 SWG

Valencia Power LLC

NMWEC (PPA) Wind N/A 204 2003 I Next Era Resources

PNM Solar PV Solar I 00 r;1c, 22.5 2011 PNM

PNM Solar PV Solar 100 0{; 21.5 2013 PNM

Lightning Dock Geothermal 100% 10 2014 Cyrc LLC

TOTAL 2,441

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DOES Pl\M HAVE APPLICATIONS PEl'iTIING AT THE COJ\it\DSSION TO

ACQUIRE GE~'ERATION RESOURCES L'J ADDITION TO THE

RESOURCES REQUESTED IN TillS CASE?

Yes. PNM has requested approval to construct an additional 23 MW of solar PV

capacity at various New Mexico locations and to purchase the full output of the Red

Mesa Wind facility, a 102 MW wind facility located in Cibola County, New Mexico. If

approved, these resources will provide electricity to PNM's customers by January 1,

2015. Also pending before the Commission is PNM's request for a CCN for the La Luz

Energy Center, a 40 MW natural gas peaking plant that PNM intends to constmct in

Valencia County, New Mexico, and bring on line before the 2016 summer peak. For

resource planning purposes I have a'>sumed that these applications will be granted. The

need for these resources is not related to or affected by the retirement of SJGS Units 2

and 3.

EXCEPT FOR THE RETIREMENT OF SJGS UNITS 2 Al~U 3 AS

REQl!'ESTED IN TillS CASE, DID PNM A._'iSUJ\!IE THAT ALL EXISTING

RESOURCES WILL BE AVAILABLE THROUGH THE 20-YEAR

PLAl'JNING PERIOD?

Yes. As discussed in Mr. Hom's testimony, PNNl will renew or purchase ownership of

the leased portions of its interest in PVNGS Units 1 and 2 at the end of the initial or

extended lea-;e terms, which will occur dUling the 20-year plamling period. PNM has

obtained Connnission approval to purchase Delta, so that resource is modeled as an

owned resomce that remains in PNM' s portfolio through the planning period. The New

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Mexico Wi11d Energy Center PP A and the Valencia PPA both expire in 2028, within the

20-year planning period, but, for resource modeling, I am assuming in all scenarios that

these resources remain in PNM's pmtfolio. Sin1ilarly, PNM's demand response

program contracts expire prior to the summer peak in2017, but I am assmning the DR

resources remain or are replaced with something similar in PNM' s portfolio. However,

before the PPAs and demand response contracts expire, PNM will evaluate the most

cost effective alternative and will only renew a PP A if the tenns and conditions are

better than any available altemative.

PLEASE DESCRffiE S.JGS'S CONTRffiUTION TO PNM'S EXISTING

GENERATION PORTFOLIO.

SJGS provides the most capacity and energy of any of PNM's supply resources. It

provides approximately 34% of PNM's capacity to meet summer peak demand as

shown in PNM Exhibit PJ0-2, PNM's current load and resource table. SJGS

supplies approximately 50.1% of the energy to serve PNM' s retail customers.

PNM's next largest jurisdictional resources, PVNGS Units 1 and 2, provide

approximately 12% of PNM's capacity and 20% of the energy to serve PNM's retail

customers. SJGS is an economic base load generation resource providing both capacity

and energy used to provide reliable, cost-effective customer service.

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III. CO.MPARISON OF POTENTIAL RESOURCE PORTFOLIOS TO

COMPLY WITH THE REGIONAl. HAZE RULE

PLEA.'-;E DESCRIBE THE PURPOSE OF THIS PART OF YOUR

TESTIMONY.

In this pmt of my testimony I will show that the Revised SIP and a combination of

nuclear, gas, renewable resources and additional capacity in SJGS Unit 4 results in the

most cost-effective resource portfolio for PNM's customers. The analysis is based on a

compmison of estimated utility costs over a twenty year period. Another consideration

in the analysis is the risk that actual costs over the planning period will vary significantly

from the projections used in the modeling. Consequently, I will compare different

resource po1tfolios to show their potential to minimize the risk that future costs could he

significm1tly different than estimated today due to volatile natural gas prices m1d a range

of future costs associated with m1ticipated environmental regulation. I will compare four

resource portfolios that would meet the requirements of the Regional Haze Rule and

enable PNM to maintain reliable electric service. The four portfolios are presented in

PNM Exhibit PJ0-3 m1d are described as follows:

• Comply with the Regional Haze Rule as required by the Revised SIP by installing

SNCR on SJGS Units 1 and 4, retiring Units 2 m1d 3, and replacing the retired

capacity with a mix of resources including PVNGS Unit 3, new solar generation, a

gas peaking plant m1d additional capacity in SJGS Unit 4;

• Comply with the Regional Haze Rule as required by the Revised SIP by installing

SNCR on SJGS Units l and 4, retiring Units 2 and 3, <.md replacing the retired

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capacity with new solar generation, gas peaking capacity and additional capacity in

SJGS Unit4;

• Comply with the Regional Haze Rule as required by the FIP by installing SCR on

all four units at SJGS (no replacement capacity is needed in this case); and

• Comply with the Regional Haze Rule by retiring all fom units at SJGS and

replacing the retired capacity with PVNGS Unit 3 and a combination of natural gas

and renewable energy resources.

HO\V DID PNNI IDENTIFY THE 1\-IOST COST -EI<'FECTIVE

REPLACEMENT PO\VER PORTFOLIOS?

PNM used an integrated planning approach to detennine the most cost-effective

portfolios for each of the Regional Haze Rule compliance strategies. This involved

assessing the costs and production impacts of installing SNCR or SCR at SJGS as well

as evaluating potential replacement resources for tmit retirements at SJGS. Resources

were analyzed not just as stand-alone resources, but also considering their effect on

overall system costs. In addition to PVNGS Unit 3, gas peaking, solar generation and

additional capacity in SJGS Unit 4, Pm1 considered other types of natural gas capacity

and wind resources while a.;;smning continued growth of PNM's energy efficiency

resources and distributed generation.

VVHAT DOES YOUR A.~ALYSIS SHO\V AS THE lVIOST COST-EFFECTIVE

REGIONAL HAZE CO.MPLIA.1"JCE PORTFOLIO?

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TI1e most cost-effective of the four portfolios is the first- meeting the Regional Haze

Rule requirements through the Revised SIP and replacing the retired SJGS capacity with

PVNGS Unit 3. solar generation, a gas peaking unit and additional capacity in SJGS

Unit 4. rD1is portfolio is the lowest in cost and provides the best protection against the

risks of future cost increases due to volatile natural ga-. prices and anticipated

environmental regulation.

PLEASE DESCRIBE PVNGS.

PVNGS is located west of Phoenix, Arizona, and is the nation's largest nuclear

generating station. The three units at PVNGS came on line between 1986 and 1988

and have operating licenses that extend through 2047. PNM owns 10.2% of each

of the units at PYNGS. but only Unit 1 and Unit 2 have CCNs to serve PNM's

NMPRC jurisdictional customers. As discussed by PNM witnesses Mr. Sategna,

Mr. Ortiz and Mr. Hom, PYNGS Unit 3 is a resource that is currently "excluded"

from PNM' s jurisdictional generating resources.

WHAT COST DID YOU ASSUl\'IE FOR PALO VERDE lJNIT 3 IN YOUR

A.1"'Al. YSIS?

I assumed that PNM would add Palo Verde Unit 3 at a cost of $2,500/kW, or $335

million. This is the value at which PNNI is willing to offer this resource for use as

certificated plant to serve NMPRC jurisdictional customers, as explained in Mr.

Dan1ell's testimony. I will show that PVNGS Unit 3 is the most cost effective SJGS

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replacement option for PNM' s customers at a cost significantly higher than the

$2,500/kW proposed by PNM.

HO\V DID PNM DETElli'VIL~TE PORTFOLIO COSTS?

For this analysis, PNM used the Strategist® modeling software. Strategist® is a

comprehensive long-range resource planning tool for electric utilities. The Strategist®

model utilizes a proprietary, dynanlic programming algorithm to conduct a rigorous

evaluation of up to 5,000 mlique resource portfolios and selects and ranks the resource

pmtfolios based on various user-specified criteria. Strategist® is capable of modeling a

wide range of resource alternatives such as energy efficiency <md demand side

alternatives. storage technologies, renewable <.md thennal generating units, various types

of power purchase and sales agreements and the electric market. Strategist® identifies the

least-cost resource portfolio according to the net present value ("NPV") of total utility

cost that meets user-designated constraints such as reserve margin. loss of load hours,

emissions mandates, constmction lin1itations and renewable portfolio standards.

Strategis{9 input data includes fuel price projections, new resource construction costs,

demand <md energy forecasts and shapes, energy efficiency projectiom, resource

petfonnance characteristics such a-; dispatchability, transmission capacity attributes,

resomce retirements, planned outages and others. Strategist@ optimizes portfolio

selection by calculating capital requirements, fuel costs and O&M costs using economic

dispatch to meet demand and energy requirements for each of the thousands of portfolio

options and ranking each by the net present value of total utility cost. Strategist@

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considers both the existing resource portfolio and new resource options when

detennining the most cost effective portfolio for a given scenmio.

The model output, as summarized in PNM Exhibit PJ0-3, includes the NPV of the

portfolio over the 20-year analysis period, study period loss of load probability, which is

a mea<;ure of the portfolio's reliability, and the range of the risk that the cost of the

po11folio over the 20-year period will be higher or lower due to fluctuations in electricity

energy and demand requirements, natural gas prices and environmental regulations.

Additionally, Strategist® provides a summary of resource type and capacity utilization of

existing and new resource additions by year over the 20-year plmming period.

·wiLL RESOURCES IN ADDITION TO PVNGS UNIT 3 Al'ID ADDITIONAL

CAP A CITY IN SJGS UNIT 4 BE REQuiRED IF lJNITS 2 Ml> 3 ARE

RETIRED?

Yes. Although our analysis to identify those resources is on-going as pmt of the IRP

evaluation process, the analysis conducted to date indicates that in addition to PVNGS

Unit 3 and additional capacity in SJGS Unit 4 the near-term resource additions that

would most economically replace the generation capacity of the retired units at SJGS are

solar photovoitaic generation and a gas-fired peaking facility. PNM ha<; not made its

final selection of these new resources and additional information important to resomce

selection will be obtained in future requests for proposals. Fu11hem1ore, the need for

replacement resources for which PNM would request approval m the future depends

tl.mdmnentally on whether the Commission approves PNM' s requested abandonment of

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SJGS Units 2 and 3 and CCNs for the inclusion of PVNGS Unit 3 as a jurisdictional

resource and additional capacity in SJGS Unit 4. PNM will request Commission

approval of the additional solar, gas-fired or other replacement resources in future

proceedings.

PLEA_~E COl\tlPARE THE COST OF EACH OF THE FOUR PORTFOLIOS

DESCRIBED ABOVE.

PNM Exhibit PJ0-3 provides a detailed comparison of the four pmtfolios I have

described above. In summary, the exhibit shows the net present value of revenue

requirements ("NPVRR") for each of the four portfolios. NPVRR is calculated by

discounting the annual revenue requirements for the cost of the new resource additions

and the system operation and maintenance costs for each portfolio over the 20-year

planning period using a discount rate equal to a weighted average cost of capital

("WACC") of 8.18%. The NPVRR methodology allows a comparison of the cost of

each portfolio on a comparable basis over the entire 20-year planning period, since the

revenue requirements of each pmtfolio will differ from year to year over the planning

period. The NPVRR of each of the four comparison portfolios is as follows:

1) Install SNCR on Units 1 and 4 and retire Units 2 and 3 consistent with the

Revised SIP and include PV3 in the portfolio for replacement capacity

(Revised SIP with PV Unit 3). This is the lea~t cost portfolio over the twenty year

planning horizon. The net present value over twenty years of the revenue

requirements associated with this pmtfolio is $780 million less than the portfolio in

which SCR is installed on all four SJGS tmits and the capacity in SJGS Unilo;; 2 and

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3 is retained. PNM Exhibit PJ0-4 provides a Load and Resomce Table illustration

of this portfolio.

2) Install SNCR on Units 1 and 4 and retire Units 2 and 3 consistent with the

Re\ised SIP and replace the capacity with gas-fired generation instead of PV

Unit 3 (Revised SIP with gas instead of PV Unit 3). The net present value over

twenty years of the revenue requirements associated with this portfolio is $56.8

million more than the NPVRR of Revised SIP with Palo Verde Unit 3 portfolio.

The higher cost is due to the need to rely more heavily on gas-fired generation when

PVNGS Unit 3 is not included in the portfolio.

3) Install SCR on all four generation units at SJGS consistent with the FIP. This

portfolio is the most expensive of the options and, as noted above, is $780 million

more expensive than the Revised SIP with Palo Verde Unit 3 portfolio. 'The higher

cost ret1ects the very near-tenn upfront capital cost of installing SCR at SJGS and

the ongoing cost of fuel and operation and maintenance expense for the SJGS

capacity that, under the Revised SIP portfolios, would be retired.

4) Retire all four unit-, at SJGS. This pmtfolio is $558 million more expensive over

twenty years than the Revised SIP with PV Unit 3 portfolio. In addition to replacing

the retired SJGS capacity with Palo Verde Unit 3 and renewables, this portfolio

requires the inclusion of a significantly greater amotmt of new natural gas generation

than the Revised SIP portfolio and, as I address below, is the riskiest of the four

portfolios due to volatile natural gas prices and a range of future cost'> associated

with anticipated environmental regulation.

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PLEASE CO.MP ARE THE "RISKINESS" OF THE FOUR PORTFOLIOS IN

TERl'fS OF SENSITIVITY TO DEl\tlAND ~'ill E~'ERGY VARIATIONS,

NATURAL GAS PRICE INCREASES A1"1> THE COST OF A.~TICIPATED

ENvlRONWfENT AL REGlJLATION.

It is impmtant to quantify the potential risk of cost increases a~sociated with each

portfolio because it is impossible to know the future with certainty, so pmdent plmming

involves choosing a course of action that leads to acceptable results tmder a wide range

of circumstances. Table PJ0-2 shows the cost risk measure for each of the four

portfolios. The cost risk measure is a statistical measure of the range of potential cost

variation over twenty years. When comparing portfolios, a higher cost risk measure

means that the portfolio is more susceptible to futme cost increases due to natural gas

price volatility, anticipated environmental regulations, variations in system demand and

energy requirements and other variables.

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TablePJ0-2 Portfolio Cost Summary

Portfolio

Revised SIP with PV Unit 3

Revised SIP without PV Unit 3

FIP

Retire SJGS

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$194

$247

$225

$349

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4

5

6 Q.

7 A.

8

9

10

11

12

13

14

15

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17

18 Q.

19

20 A.

21

22

23



Note that the Revised SIP portfolio that includes Palo Verde Unit 3 is the least risky.

The portfolio that includes the complete retirement of all SJGS w1its is the most risky,

with the risk mea•mre that is 80% higher than the risk mea-;ure for the Revised SIP

pmtfolio with Palo Verde Unit 3.

\VHAT DRIVES THE MAGNITlJDE OF THE RISK MEASURE?

TI1ree variables have the most impact on the risk measurement calculation: the demand

and energy forecast, natural gas prices and estimates of a future cost associated with

carbon dioxide emissions. 111e magnitude of the risk mem;ure is primarily driven by the

estimated arnow1t'i of natural gas burned and carbon dioxide emitted over twenty years

by each of the portfolios in the comparison. In addition, variations in the demand m1d

energy foreca'lt have a more pronounced effect on the volatility of the total costs in

portfolios with the greatest exposure to natural gas and carbon dioxide emission price

char1ges. The Revised SIP portfolio that includes Palo Verde Unit 3 is the lea'lt risky

because there are no carbon dioxide emissions from Palo Verde Unit 3 and its inclusion

in the portfolio reduces the need to rely on carbon-emitting natural gaq generation.

\VHY DID YOU INCLUDE FUTURE COSTS OF CARBON DIOXIDE

EMISSIONS TO CALCuLATE THE PORTFOLIO COST ESTIMATES?

The IRP Rule requires utilities to assume a cost associated with carbon dioxide

emissions for purposes of resource plmming. In Case No. 06-00448-UT. the

Cormnission adopted standardized prices for carbon emissions to use for these plarming

assumptions. The standard monetary values adopted in 2006 are now out of date,

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12 A.

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because greenhouse gas regulation has not yet resulted in an additional cost associated

with greenhouse ga'> emissions at electric generation stations, but the process that will

result in greenhouse gas emission regulations at new and existing electtic generation

stations is underway. It is simply not reasonable to assume that there will not be

additional costs associated with greenhouse gas emissions during the twenty-year

planning period. As I describe later in my testimony, Pl\i'M has addressed the need to

include future greenhouse gas emission costs in resource planning by hiling PACE

Global to provide a projection of such costs based on current policy assumptions and a

nationwide model of electricity generation.

HOW DID PNM CALCULATE THE RISK MEASURE?

PNM calculated the risk measure using an analytic technique called Monte Carlo

simulation. Monte Carlo silnulation uses randomly selected values from probability

distributions as lisk valiables to determine how a change in estimated values of the

vmiables affects the total cost estimate. Performing the Monte Carlo simulation consists

of the following steps:

• Step 1: Determine the potential range of values for il1put valiables (including

load forecast, natural gas fuel prices, market p1ices for electricity, and C02

costs). Then define a probability distribution for each variable, i.e. the

likelihood that each value in the range may occur.

• Step 2: Determine the conelation among input valiables if m1y, i.e. the change

in one variable directly related to a change in m1other variable.

18

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15 A.

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23

DIRECT TESTIMONY O:F PATRICK J. O'CONNELL

NMPRC CASE NO. 13-00 -LT

• Step 3: Generate 900 sets of random input conditions, one value from each

probability distribution while reflecting any correlation among the variables, for

each year of the study period. Each set is referred to as a "draw.''

• Step 4: Calculate the resomce pmtfolio's total system cost for each of the 900

draws using Strategist® to optimize portfolio dispatch.

• Step 5: Aggregate the result-; of the random draws from Step 4 and calculate the

average cost and cost variability.

Using the result of step three, steps four and five were applied to each pmtfolio, using

the same randomly generated conditions. For my testimony, the average cost calculated

through this process is used to report the net present value of revenue requirements over

twenty years and the cost variability, a calculated statistic called the 95th percentile risk,

is reported as the risk measme.

\VHAT DOES THE 95m PERC"ENTILE RISK REPRESENT?

The 95th percentile risk measure reflects a five percent likelihood that a given portfolio's

actual costs will be greater than the risk value. For instance, the Revised SIP with PV

Unit 3 portfolio risk mea.;;ure is $194 million dollars. This measure reflects a five percent

likelihood that pottfolio actual costs will be greater than $6,834 million dollars (S6,640

million plus $194 million) over the next 20 years and a 95% likelihood that portfolio

costs will be less than $6,834 million dollars over the next 20 years. So a larger 95th

percentile risk value means a portfolio's NPVRR is more likely to exceed the average

NPVRR than would be the case with a lower 95th percentile risk value.

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WHAT ASSlJ1VWfiONS REGARDING RESOURCE AVAILABILITIES M'D

COSTS DID PNM MAKE TO PRODUCE THE PORTFOLIO

CO~IPARISONS?

The resource availability and cost assumptions PNM used in this analysis are provided

in PNM Exhibit PJ0-5. These assumptions are the same a"isumptions PNM is using to

develop the 2014-2033 IRP. The data was gathered from the best somces available to

PNM. For example, cost<; for renewable generation are based on the bids PNM received

in response to the request for proposals issued in late 2012 to develop PNM's 2014

Renewable Procurement Plan. Natural gas generation costs are based on <m Electric

Power Research Institute ("EPRI") Technical Assessment Guide ("'EPRI TAG'') cost

databm;e that is reviewed and updated annually for the electric industry. An important

set of a<;sumptions for the analysis includes future natural gas and carbon dioxide prices.

PNM hired PACE Global to develop these prices using their models of the national,

intercom1ected natmal gas and electric systems. I have included the docw11entation of

PACE's work in PNM Exhibit PJ0-5.

\VHY DID YOU USE A T\VENTY -YEAR PERIOD TO CALCULATE THE

PORTFOLIO COST ESTIMATES?

The IRP Rule, at Section 7(1), defines the planning period to be used as a twenty-year

period. New Mexico and the Commission require the development of a long term

resource plan through an IRP process. Also, resource planning requires a long-tenn

view to ensure the development of the most cost-effective pmtfolio.

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DIRECT TESTIMONY OF PATRICK .J. O'CONNELL

Nl\1PRC CASE NO. 13-00 -UT

PLEASE ELABORATE ON YOUR EARLIER STATEMENT THAT THE

INCLUSION OF PALO 'VERDE uNIT 3 RESULTS IN A COST EFFECTIVE

PORTFOLIO EVEN AT A PRICE SIGNIFICA,l~TLY ffiGHER THAi~ THE

$2,500/KW PROPOSED BY PNM.

PNM conducted a sensitivity analysis around the price of Palo Verde Unit 3 and fmmd

that the most cost effective Revised SIP portfolio includes Palo Verde Unit 3 up to a

price of $3,100/kW or $415.4 million. PNM has proposed including Palo Verde Unit 3

in rate ha'ie at a price of $2,500/kW or $335 million. To conduct the sensitivity analysis,

PNM included Palo Verde Unit 3 as a resource option in the Strategist modeling at a

range of prices. Only when the price for Palo Verde Unit 3 exceeds $3,100/kW, does

gas-fired capacity becomes a less expensive replacement for SJGS capacity than Palo

Verde Unit 3. So. while PNM ha<> detennined that $335 million is a fair price for

including Palo Verde Unit 3 in PNM's rate base, the value of Palo Verde Unit 3 to

PNM's customers exceeds this cost by $80.4 million.

HOW WILL THE J>ROPOSED RETIREMENT OF S.JGS tJr..1TS 2 AND 3 Al~D

THE OWNERSIDP EXCHAl~GE OF 78 M\V FROM UNIT 3 TO UNIT 4

M'FECT THE Al'VIOUNT OF CAPACITY THAT PNM OWNS AT S.JGS?

Table PJ0-3 provides the capacity currently held by PNM in each of the SJGS Lmits and

the capacity that would be held, a ... .;;suming Commission approval of PNM's requests in

this case, after the retirement of SJGS Units 2 and 3 and PNM's acquisition of an

additional 78 MW in Unit 4. The ownership transfer of 78 MW from Unit 3 to Unit 4 is

described by Mr. Olson.

21

1

2

3 Q.

4

5 A.

6

7

8

9

10

ll

12

13 Q.

14

15 A.

16

Unit 1

Unit2

Unit3

Unit4

Total



TablePJ0-3

Current ~1\Vs Change Result

170 0 170

170 -170 0

248 -248 0

195 +78 273

783 -340 443

DOES THE MOST COST-EFFECTIVE RESOlJRCE PORTFOLIO INCLUDE

THE 78 MW 0\VNERSHIP TRA.NSFER FROM SJGS UNIT 3 TO lJNIT 4?

Yes. This ownership transfer results in a more cost effective portfolio than would result

from a net retirement of more than 340 MW at SJGS. If the ownership transfer did not

occur and PNM's net retirement at SJGS were 418 MW, the most cost effective

pmtfolio would still be the Revised SIP portfolio with Palo Verde Unit 3, but the net

present value would increase by $79 million due to increased reliance on natural gas

generation, as referenced in PNM Exhibit PJ0-6. The risk measure would also increa.<;e

by $11 million.

DID PNM ASSUJME THAT A NATURAL GAS PEAKll~G PLANT IN THE

SJGS REPLACEIVIENT PORTFOLIOS \VOlJLD BE SITED AT SJGS?

Yes. All of the SJGS replacement portfolios include at least one heavy-frame gas

peaking plant as part of the most cost effective mix of replacement capacity. PNM

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13 14 Q.

15 A.

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assumed that the first such gas peaking plant in each portfolio would be sited at SJGS

due to the pe1mitting and economic advantages of using that site. PNM currently owns

sufficient land at the station to build and operate a natural gas peaking facility. Locating

the peaking facility at SJGS will significantly reduce the need to build transmission

interconnection facilities for the ne\v ga.;; plant because the gas plant will be able to use

existing trammission facilities that are currently serving SJGS Units 2 and 3. Siting new

generation at <m existing generation facility also simplifies permitting the new facility

since there is no change in land use associated with the new constmction. An estimate

of $10 million to pay for construction of a new gas supply line from existing, nearby ga'i

trnnsmission lines to SJGS is included in the plant constmction costs for the gas facility.

IV. RELATIONSHIP TO 2014-2033 IRP

HOW IS PNlVI COORDINATL"iG TIDS FILL"iG \VITH PNM'S 2014-2033 IRP?

PNM's 20141RP is scheduled to be filed with the Commission by July 2014. Consistent

with the IRP Rule, the lRP will present an analysis of portfolio alternatives over the next

twenty-year period, identify the most cost-effective portfolio, and include a four-year

Action Plan. I anticipate that the key near-term elements of that Action Plan will

include:

• Pursue abandonment of SJGS Units 2 <md 3 by the end of 2017;

• Pursue approval for a CCN for 78 MW of capacity in SJGS Unit 4 by J mmary 1,

2015;

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19 Q.

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23



• Pursue approval for a CCN to include PVNGS Unit 3 as a jurisdictional

generating resmrrce;

• Identify new natmal gas resources required to replace capacity being retired at

SJGS and file a CCN to have such resources in place by early 20 18; and

• Identify 40 MW of new solar resomces to be comtructed as replacement

generating capacity for the retired SJGS capacity and seek NMPRC approval to

constmct and operate such facilities by 2016.

Consistent with the IRP Rule, PNM began the IRP Public Advisory Process in July

2013. A number of meetings with the public and the Public Advisory Group have been

conducted. TI1e analysis presented in my testimony has been discussed in the public

advisory process. PNM anticipates that during the next few months, through the IRP

process, the remaining resomces necessary for replacement of the retired generation

capacity in SJGS Units 2 and 3 \Vill be specifically identified and addressed in the fom

year Action Plan, and an over-all, long-term resource plan for meeting forecasted

customer loads over the next twenty years will be described. Of course, this longer-tem1

plan will again be revisited by PNM in its next (2017) IRP process.

FROl\1 AN IRP PERSPECTIVE, 'WHY SHOID.D THE ~'MPRC APPROVE

PNl\l'S REQUEST FOR A CCN TO TRAI\JSJi"'ER 78 J\IW OF CAPACITY

FROM SJGS UNIT 3 TO SJGS UNIT 4?

All pmtfolios that include the additional capacity in SJGS Unit 4 are lower in cost and

less risky than portfolios that do not. Including an additional 78 MW of capacity in Unit

24

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23

DIRECT TESTil\tONY OF PATRICK .J. O'CONNELL


4 is cost-etlective. It is an existing resource and is not subject to siting and constmction

uncertainties as may exist for new resomces.

FROM At'J IRP PERSPECTIVE, WHY SHOlJLD THE Nl\IPRC APPROVE

PNM'S REQUEST "FOR A CCN TO L~CLUDE PVNGS l!N1T 3 A.'i A

.JURISDICTIONAL RESOURCE?

Next to the addition of 78 MW of SJGS Unit 4 capacity in the resource portfolio,

PVNGS Unit 3 is the most cost-effective resource option for replacement of the

abandoned base-load capacity in SJGS Units 2 and 3. All portfolios that include

PVNGS Unit 3 are lower in cost and less risky than portfolios that do not. All such

portfolios showed lower levels of C02 emissions and cost risks than portfolios that did

not include PVNGS Unit 3. It is an existing resource and PNM controls sufficient

transmission capacity to bring the generation to the Four Comers area and into PNM's

load centers. Granting PNM's application for a CCN for PVNGS Unit 3 reduces the

amount of new generation capacity that PNM must obtain and results in significant

savings to customers over the twenty-yem· planning period.

V. CONCLUSIONS

DO YOU HAVE AlW CONCLl.HliNG OBSERVATIONS?

Y cs. Complying with the requirements of the Regional Haze Rule by retiring Unit'> 2

and 3 at SJGS and, installing SNCR on Units 1 and 4, pursuant to the Revised SIP, and

replacing the retired capacity with Palo Verde Unit 3, 40 MW of solar generation, a

natural ga.'> peaking facility located at SJGS m1d an additional 78 MW of capacity in

SJGS Unit 4 is in PNM's customers' best interests because it is the most cost-effective

25



1 approach available to PNM and provides significant enviromnental benefits.

2 Accordingly, the N:MPRC should approve PNM's Application in this case.

3

4 Q. DOES TillS CONCLUDE YOL'R DIRECT TESTiwiONY?

5 A. Yes.

GCG# 517366

26

PNM EXHIBIT PJ0-1

Consisting of 1 page

PNM EXHIBIT PJ0-1 Page 1 of 1

PATRICK J. O'CONNELL: EDUCATIONAL AND PROFESSIONAL SUMl\1ARY

Name: Patrick J. O'Connell, PE

Address: Public Service Company of New Mexico Main Offices Albuquerque, New Mexico 87158-1105

Position: Director, Planning and Resources

Education: B.S., Civil Engineering, with distinction and magna cum laude in General Honors University of New Mexico, Albuquerque, New Mexico 1990

Employment: Public Service Company of New Mexico, Albuquerque, New Mexico: Director, Planning and Resources, July 2012 - present Project Manager, PNM Generation, 2009- 2012 Project Manager, Integrated Resource Planning, 2007 - 2009 Senior Gas Supply Planner, PNM Gas Services, 1999 - 2007

Public Service Company of New Mexico, Santa Fe, New Mexico Project Engineer, PNM \Vater Services, 1996- 1999

URS Greiner, Albuquerque, New Mexico: Design Engineer, 1994 - 1996

GMA Inc., Albuquerque, New Mexico: Staff Engineer, 1993-1993

Geoscience Consultants Ltd., Lanham, Maryland: Designer, 1990 - 1992

Licensure: New Mexico Professional Engineer, License No. 12876

Testimony: New Mexico Environmental Improvement Board, Case No. EIB 10-04(R): In the Matter of Proposed Regulation, 20.2.350 NMAC- Greenhouse Gas Cap and Trade Provisions

New Mexico Public Regulation Commission Case No. 12-00317-UT: PNM's 2013 Energy Efficiency Plan Case No. 13-00004-UT: PNM's Delta Plant CCN Application Case No. 13-00175-UT: PNM's La Luz Energy Center CCN Application Case No. 13-00183-UT: PNM Renewable Energy Plan for 2014

PNM EXHIBIT PJ0-2


PNM Exhibit PJ0-2

PUBLIC SERVICE COMPANY OF NEW MEXICO Current Load and Resource Projections for Summer Peak- 201.4/RP

mil 2015 ill& W1 .ill§ lli.2 ill.!! ill.! lli1 .lli1 (1) 2014 IRP Forecdsted System Peak Demands* 2,020 2,040 2,056 2,075 2,085 2,098 2,110 2,122 2,134 2,148 (2) Forecasted Incremental Customer S1ted PV (15) (17) (20) (20) (21) (20) (21) (20) (20) (20) (3) Fort:ca5..ted Incremental Energy Efficiency (22) (32) (40) (49) (57) (62) (72) (75) (84) (84) {4) Net System Peak Demand (MW) 1,983 1,991 1,997 2,005 2,007 2,015 2,017 2,026 2.030 2,043

(S) four Corners 200 200 200 200 200 200 200 200 200 200 (6) SanJuan 783 783 783 783 783 783 783 783 783 783 (71 Total Coal Resources (MW) 983 983 983 983 983 983 983 983 983 983 (8) Paio Verde Umt 1 and U111t 2 268 268 268 268 268 268 268 268 268 268 (9)

(10) Total Nuclear Resources (MW) 268 268 268 268 268 268 268 268 268 268 (11) RPeves 154 154 154 154 154 154 154 154 154 154 112) /dton

230 230 230 230 230 230 230 230 230 230 (13) Luna 185 185 185 185 185 185 185 185 185 185 (14) Lvrdsburg 80 80 80 80 80 80 80 80 80 80 (lS) Valenua {Purchase) 145 145 145 145 145 145 145 145 145 145 (16) Delta-Person 138 138 138 138 138 138 138 138 138 138 (ll) La Luz

40 40 40 40 40 40 40 40 (18) Total Natural Gas Resources (MW) 932 932 972 972 972 972 972 972 972 972 (lY) 2().t!~~':..'~!;::i_R_::ponse Pr~~.':~~,;, __ i~W. net of losses) 48 so so 52 52 52 52 52 52 52

(20) Wmd Purchases (NMWEC & Red Mesa) 10 15 15 15 15 15 15 15 15 15 (21) Utility Scale Solar PV (42 MW by 2013 + 23 MW in 2015) 23 40 40 40 40 39 39 39 39 39 (22) Utrl1ty Scale Prospenty Battery Demo (net of losses) 05 0.5 0.5 0.5 0.5 0.5 0.5 0.5 05 0.5 (23) PNM Sky Blue l.S MW Solar 1 1 1 1 1 1 1 1 1 1 (24) 2013 Renewable Plan Resource 10 MW Geothermal 6 6 6 6 6 6 6 6 6 6 (25) Total Renewable Resources (MW) 40 62 62 62 62 61 61 61 61 61 (26) Total System Resources (MW) 2,271 2,295 2,334 2,337 2,336 2,336 2,336 2,336 2,336 2,335 (27) Reserve Margin (MW) 288 303 338 331 329 321 319 310 306 292 (28) Reserve Margin (%) 14.5% 15.2% 16.9% 16.5% 16.4% 16.0% 15.8% 15.3% 15.1% 14.3%

Not".L • PNM ass...,rnes a C<.iP<K.Ity credtt fm n.~new.lb!~ <thr.:ult.es ba:;ed on type of technology and contribution at the peak hour * Dt.'rrilr~d i{e-;ptJmf:' & ~;i~Jr R~:"sources grosst>o up tor ·r cansmiS:>!On losses .. PNM d:i5l.imc:, a 100'1,,. (dp~Clty uedit for P:mpent'{ Battery ~mo • Ci.l'~i¥.•t''y' C£>ti!t tor geotherrna! resm;rce '5 ba.:.ed ,;pon developer estimates • ~uture r;:~our:;e~ are wrrent!y b('tr~g ~ele-Ci.<:>d thr-;:.h;th RFP's for renewabies, natural ga~, and lo<ld management, consJstent With the act1on p!.ar. 1n ?N\.~\ ~C L 1 1 ~P, tJit<d lviy lS, :c:1: t'NM ,:Dilt1nuaHy evaluates its need for resources as. circumsunce.s change,

PNM EXHIBIT PJ0-3


Ltne

[1]

[2]

13) [4]

[5]

[6]

[7]

[8]

19]

1101 [11]

[12]

]13]

[14]

{15]

{16]

117]

118]

119]

[20)

121]

[22]

[23]

[24]

125] [26)

In] [28j

[29]

(.lO]

[ ll)

(32)

[33)

[34

135)

[36)

(37)

[38]

[39]

(40]

(41]

[42]

[43

[44]

Summary of Regional Haze Compliant Portfolios

Scenario Description Revised SIP with PV3 Gas Pflcing PACE Reference Case C02 Pncrng PACE Reference Case ($11 in 2020) Energy f.ffrnency furecdst 2014 IRP Forecast PV DG forecast 2014 IRP Forecast Demand Response Fort?Cdst _ 2014 IRP Forecast Resource Alt<?rndtrve Dot abase EPRI TAG/PNM Estimates Renewable Procurements 2014 REPP + Projections Palo Verrie 3 Available $2,500/kW -NOx Control at San Juan SNCR's on 1 & 4 San Juan O&M Harvest Savings Units 2 & 3 San Juan Stranded Asset Costs $20,764,674 SJ Retirements Units 2 & 3 (Dec 2017) 2014

2015 Red Mesa (102 MW) 2015 Solar (23 MW)

2016 Aero derivative (40 MW) Solar (40 MW)

2011

----t-----·--·--·----------- ---·

2018 Large GT (177 MW) Palo Verde 3 (134 MW) -

San Juan Acqursition (78 MW) 2019 2020 l2o21 --

---------- ____ ------· Wi".:!_JlOO MW) __ 12022 ---------------·-- ----2023

2024 -

2025

2026 Solar (20 MW) 2027 2nd Aeroderivative (40 MW) ------- ----2028

2029 Aerodenvatrve (40 MW) 12030 ---·---------~--·--

-12031 Small GT (85 MW) -2032 ----2033

20-Year lOLH 51.20

Average NPV $6,640,253,862 Difference to Revi~ed SIP with PVl Avera~e NPV

95th Percentile Risk --- ____ __1!9i,3_5721!2.. ---------------- ---------

PNM Exhibit PJ0-3

I Revised SIP w/o PV3 FIP ("4 SCR") FIP ("4-Unit Shutdown at SJ") i

PACE Reference Case PACE Reference Case PACE Reference Case PACE Reference Case ($11 in 2020) PACE Reference Case ($11 in 2020) PACE Reference Case ($11m 2020) I

20141RP Forecast 2014 IRP Forecast 2014 IRP Forecast I 2014 IRP Forecast 2014 IRP Forecast 2014 IRP Forecast I 2014 IRP Forecast 2014 IRP Forecast 2014 IRP Forecast

EPRI TAG/PNM Estimates EPRI TAG/PNM Estimates EPRI TAG/PNM Estimates 2014 REPP + Projections 2014 R£PP + Projections 2014 REPP +ProJections I

No No $2,500/kW . SNCR's on 1 & 4 SCR's on all Units None

•

Units 2 & 3 None Units 1-4 ' $20,764,674 $0 $141,090,356 I

Units 2 & 3 (Dec 2017) None Units l-4 (Sept 2016) •

Red Mesa (102 MW) Red Mesa (102 MW) Red Mesa (102 MW) ' 2015 Solar (23 MW) 2015 Solar (23 MW) 2015 Solar (23 MW)

Aeroderivative (40 MW) Aeroderivative (40 MW) Aeroderivative (40 MW) Solar (40 MW) Solar (40 MW)

Large GT (177 MW) Large GT (143 MW)

Palo Verde 3 (134 MW) lxl Combined Cycle (250 MW)

Wind (100 MW) Large GT (177 MW) large GT (143 MW)

San Juan Acqursition (78 MW)

Wrnd (100 MW) Solar (20 MW)

·-2nd Aeroderivative (40 MW)

Wind (100 MW) Solar (20 MW) Solar (20 MW) Reciprocatrng Engines (93 MW)

2nd Aeroderivative (40 MW) 2nd Aeroderivative (40 MW)

Aeroderivative (40 MW) Aeroderivative (40 MW)

Aerodenvative (40 MW) Small GT (85 MW) Aeroderivative (40 MW) Aeroderivative (40 MW)

Reciprocating Engines (93 MW)

50,23 67.57 79.27

$6,697,094,002 $7,420,726,133 $7,198,507,284

$56,840,140 $780,472,271 $558,253,422

$246,641,702 $225,240,969 $348,814,691

PNM EXHIBIT PJ0-4


PNM Exhibit PJ0-4

PUBLIC SERVICE COMPANY OF NEW MEXICO Revised SIP Load and Resource Projections for Summer Peak- 201.4/RP

{1) 2014 IRP Forecasted System Peak Demands• (2) Forecasted Incremental Customer S1ted PV (3J Forecasted lncrementdl Energy lff1oency (4) Net System Peak Demand (MW)

{~) Four Corners

(6) San Juan (1) Total Coal Resources (MW)

(Si Palo V~rdt' Un1t 1 and Un1t

19) _Palo Verde Unit 3 (10) Total Nuclear Resources (MW)

( 11) Heeve;

(12) Afton

(13) lu.na

(14) lordsburg

(lSi ValenCia (Purchase)

(loi Delta·Person (ll) La lul

(18) SJGS Replacement tlesmHcc· Gas Peaking Resources (19) Total Natural Gas Resources (MW)

\20) Totdl Demand Hesponse Progrdnls {MW, net of losses)

(21} 1/Vind Pur(ha~es (NM\~iEC & Re<.1 1\h:s.aj

(n) Utllrty Scaie Sola1 PV (42 MW by 2013 + 23 MW in 2015)

231 Utility Scale Prosper~ty Battery Demo (net of losses) 24) PNM Sky Blue LS MW Solar

251 2013 Renewable Pldn Resource 10 MW Geothermal 26) SJ(,S HPpllcernent Resource: Llt11ity Scale Solar PV (40 MW)

(21) Total Renewable Resources (MW)

(2H) Total System Resources (MW)

(:'9) Reserve Margm (MW)

{30) Reserve Margin(%)

Not~_:~

4Qll

2,020 (15)

__Q3l 1,983

200 783

983

268

268

154

230

185

80 145 138

932

48

10

23

0.5

1

6

40

2,271

288 14.5%

,lQll

2,040 (17)

__!El 1,991

200 783 983

268

268

154

230

185

80 145 138

932

50

15

40

05 1 6

62

2,295

303 15.2%

• ~'1'\jM ., cap¥,t'l c:r('d;t t'01 re,:ewablf"· re;;,ources. based on type of technology and contributton at the peak hour

"' 0-t':rn<~~nd Fi.e::.pon~t- & '\ol~r R.e~o~.;rt:('\ .;ro~ up for Tran,HT\is.~ion losses

'" PNM <J.'>:.'.;rrw.<." lW'Ji- capa<::fty crcd1: fc:r P'osperity Battery Demo

"'C.1P<.tcrty ued1t for g~othermo! r/i'suun:e 1:0 b.a\.ed upon developer estimates

lQ.l2

2,056 (20) (40)

1,997

200 783 983

268

268

154

230

185

80 145 138 40

972

50

15

40

0.5

1 6

27 89

2,362

365 18.3%

.. O:ut~..rrto rt~~ource~ are- currentiv ~me :;<":'le<:tE~d through RFP's for renewable'i, natural gas, ~nd load management, cormstent with the act1on

p!M• PNM ~ 20;1 H~P, flied l:.;~y !.0, .2011, PNM cont~rlui;t,Uy evaluates its Ot!ed for resources :as circumstances change

1212

2,075

(20)

~ 2,005

200 783 983

268

268

154

230

185

80

145 138 40

972

52

15

40

0.5

1 6

27 89

2,364

358 17.9"A.

1l!1li

2,085

(21)

_jg_ 2,007

200

443

643

268 134

402

154

230

185

80 145 138 40

177 1,149

52

15

40

0.5

1 6

2l

89

2,335

327 16.3%

.llii

2,098

(20)

_(g! 2,015

200 443 643

268 134 402

154

230

185

80

145 138 40

177 1,149

52

15

39

0.5

1 6

27 89

2,334

320 15.9%

~

2,110 (21)

(72)

2,017

200

443

643

268

134

402

154

230

185

80 145 138

40 177

1,149

52

15

39

0.5

1

6 27 88

2,334

317 15.7%

Z2ll

2,122 (20)

~ 2,026

200 443 643

268 134 402

154

230

185

80

145 138

40 177

1,149

52

15

39

0.5

1 6

27 88

2,334

308 15.2%

1Qll

2,134 (20)

~ 2,030

200 443 643

268 134 402

154 230

185

80

145 138 40

177 1,149

52

15

39

0.5

1

6 27 88

2,334

304 15.0%

LQ6i

2,148 (20)

(84)

2,043

200 443

643

268

134

402

154

230

185

80

145 138 40

177

1,149

52

15

39

0.5

1 6

27

88

2,334

291 14.2%

PNM EXHIBIT PJ0-5

Consisting of 32 pages

PNM EXHIBIT P J0-5

Part 1 of 3


PN~1 Exhibit P J 0-5

Part 1 of3

Overview of Replacement Power lVlethodology

In order to ensure system reliability and meet targeted reserve margms, PN!v1 evaluated renewable,

natural gas and nuclear generation alternatives as replacement power for retirements at the San Juan

Generating Station. The replacement alternatives were incorporated into PNM' s resource planning

modeling software by Ventyx called Strategist'D to determine the mix of resource additions. First. all

existing resources and new resource alternatives are incorporated into Strategist'R'. This includes

providing the model with associated fuel and operating expenses for existing resources and all revenue

requirements for new resource alternatives. Next, Strategist"' produces resource portfolios that will meet

the targeted reserve margins for the PNl\1 system over a 20-year planning period. Each portfolio of

resources is then economically dispatched to derive a total system cost for the given portfolio. All

resource portfolios are then ranked based upon a net present value of future system costs to determine the

least cost portfolios, consistent with traditional regulated utility resource planning. The optimization of

resource portfolios consists of evaluating all costs, including capital, fuel and operating expenses for

future resource additions.

Replacement Power Alternatives

Fifteen different generation resources were available to use to replace the 340 MW or 783 MW of coal

that were assumed to be retired. The list of resource alternatives, along with a narrative describing each

resource, is shown below:

1. 250 MW of new combined cycle gas generation

2. 204 MW of new combined cycle gas generation

3. 177 & 143 MW new gas turbine

4. 93 MW of new reciprocating engines

5. 85 MW new gas turbine

6. 40 MW ne\v gas aeroderivative turbine

7. 100 MW of new wind generation

8. 20 MW of new solar PV generation

9. 50 MW of new solar thermal generation

10. I 0 MW of new geothermal generation

1 1. 134 MW of existing nuclear generation (Palo Verde 3)

12. 200 MW of new coal generation

13. 200 MW of new nuclear

14. 250 MW of existing combined cycle generation

15. 78 MW of existing coal generation (SanJuan Unit 4)

PNM Exhibit P J0-5 Part 1

Page 1 of 6

250 MW of New Combined Cycle Gas Generation

For this option PNM assumes a 1 x 1 combined cycle gas turbines, which provides a relatively high

efficiency rating. The 250 MW size represents a typical manufactured capacity for this type of

configuration using high efficiency turbines. The 250 MW combined cycle gas turbine ("CCGT") is

modeled assuming a $1,545/kW installed capital cost and approximately a 6,950 Btu/kWh heat rate.

Unlike gas turbines, combined cycle plants require large amounts of water to condense the steam

cycle. To reduce \Vater usage and associated costs, PNM assumed this CCGT will utilize hybrid or

dry cooling technology. This additional cost is included in the installed capital pricing above. PNM

used the EPRI Technical Assessment Guide (TAG) database as the source of the unit characteristics

and adjusted the TAG data for 5,000 feet above sea level. PNM assumed that this resource could

only utilize the available transmission from the San Juan Plant to PNM load centers in north central

New l\Iexico. Thus, this option was only applicable for a four unit retirement at the San Juan Plant.

PNM also assumed a $10 million cost to build a new gas pipeline from an interstate pipeline to the

San Juan plant.

204 MW of New Combined Cycle Gas Generation

PNM models a I x 1 combined cycle gas turbine option, which also provides a relatively high

efficiency rating and does not exceed PNM's current largest generation unit at this size. The 204

MW size represents a typical manufactured capacity. The 204 MW CCGT is modeled assuming a

$1,780/kW installed capital cost and about a 7,100 Btu/kWh heat rate. Installing a larger unit may

decrease the capacity cost and heat rate, but would increase costs for reliability reserves on PNM's

system. Unlike gas turbines, combined cycle plants require large amounts of water to condense the

steam cycle. To reduce water usage and associated costs, PNM assumed this CCGT will utilize

hybrid or dry cooling technology. This additional cost is included in the installed capital pricing

above. PNM used the EPRI TAG database as the source of the unit characteristics and adjusted the

TAG data for 5,000 feet above sea level. This resource \Vas assumed to bypass any major

transmission upgrades by siting it near PNM's largest load center, near the Albuquerque/Santa Fe

area.

177 & 143 1\lW New Gas Turbine

The 177 MW and 143 MW gas turbines ("GT") are modeled as heavy frame units. The 177 MW

option is modeled with 9,790 Btu/kWh heat rate and $979/kW installed capital cost, and the 143 MW

option is modeled with l 0,142 Btu/kWh heat rate and $1,006/kW installed capital cost. PNM used

the EPRI TAG database as the source of the unit characteristics and adjusted the TAG data for 4,000

feet above sea level. The 177 MW and 143 MW sizes represents typical manufactured capacity. This

technology can help PNM maintain system voltage, regulation if needed, and spinning reserve

requirements. These resource are expected to require relatively little acreage and minimal amounts of

water. Thus, these resources were assumed to bypass any major transmission line or upgrades and

allowing PNM to site within WECC Path 48 in north central New Mexico.

PNM Exhibit P J0-5 Part I

Page 2 of 6

93 MW New Reciprocating Engines

The 93 MW reciprocating gas engines is based upon operating ten smaller sized reciprocating engines

at a heat rate of 8,900 Btu/kWh heat rate and $1,521 /kW installed capital cost. Reciprocating engines

can operate over the full ranges and offer maximum load following flexibility. PNM used the EPRI

TAG database as the source of the unit characteristics. This resource was assumed to bypass any

major transmission upgrades and allow PNM. to site it within WECC Path 48 in north central New

J'v1exico.

85 MW New Gas Turbine

The 85 MW GT is based upon a typical manufactured size of aero-derivative hybrid gas turbine with

a 9,150 Btu/kWh heat rate and $1,679/kW installed capital cost. 'Similar to the 177 MW CT shown

above, this unit can provide quick start capability (full operating load in 10 minutes) with a proven

track record. PNM used the EPRI TAG database as the source of the unit characteristics and adjusted

the TAG data for 5,000 feet above sea level to represent typical siting conditions around New

Mexico. This resource was assumed to bypass any major transmission upgrades and allow PNM to

site it within WECC Path 48 in north central New Mexico.

40 MW New Gas Aeroderivative Turbine

The 40 MW option is based upon one 40 MW aero-derivative turbine at a 9,800 Btu/kWh heat rate

and $ 1,644/kW installed capital cost. PNM used the EPRI TAG database as the source of the unit

characteristics and adjusted the TAG data for 5,000 feet above sea leveL Similar to the 85 MW GT

shown above, this unit can provide quick start capability (full operating load in 10 minutes) to help

maintain system reliability. This resource was assumed to bypass any major transmission upgrades

and allow PNM to site it within WECC Path 48 in north central New Mexico.

100 MW Wind Resource

The state of New Mexico offers abundant and excellent wind resources. This option is assumed to be

a new 100 MW wind facility, located in NM and would be procured through a third party entity under

a long term power purchase agreement at the rate of $44.41/mwh levelized over a thirty year life.

Based on previous RFPs, PNM used an average of costs to provide a proxy for this resource. This

option assumes minimal interconnection costs and does not assume any transmission upgrade costs as

this depends heavily on the location of a new wind facility and access to the PNM transmission

system. Therefore, required transmission upgrades would need to be evaluated on a case by case

has is.

20 MW Solar PV Resource

This option based upon a new 20 MW, single axis tracking solar PV facility, located in NM with a

$2,085/kW installed capital cost based upon expected costs from developers. PNM used two

different cost options to take into account the current federal investment tax credit being reduced from

30% to I OC/c beginning in 2017. PNM assumes that solar facilities interconnecting to the PNM

system will provide approximately 72% of the installed capacity to meet reserve margin

requirements. As the penetration of solar increases on PNM' s system it will begin to affect the

PNM Exhibit P J0-5 Part 1

Page 3 of 6

system peak hour during the summer. PNM applies a declining contribution to reserve margin with

each successive resource addition made. This option assumes very minimal interconnection costs and

does no transmission upgrade costs as this resource is expected to be located on PNM distribution

facilities.

50 MW Solar Trough

This option based upon a 50 MW parabolic trough technology of which PI\1~1 would participate in as

part of larger project (>100 ~1W) to take in account larger economies of scale. This proxy alternative

\Vould be located in NM with a $4.178/kW installed capital cost without storage and $7,291 /kW with

three hour storage based upon EPRI TAG estimates. PNM used two different technology options to

account for storage. PNM assumes that solar facilities interconnecting to the PNM system \vith

storage will provide approximately I 00% of the installed capacity to meet reserve margin

requirements. This option assumes very minimal interconnection costs and does not include

transmission upgrade costs.

10 MW Geothermal Resource

Using information gather from the past few RFPs that PNM has issued, PNM believes that some

potential still exists for new geothermal resources. Based on previous RFPs, PNM used an average of

costs to provide a proxy for this resource from a third party developer at an expected PPA rate of

S 131 .49/mwh levelized over a thirty year life. This option assumes minimal interconnection costs

and does not assume any transmission upgrade costs as this depends heavily on the location of the

geothermal resource and the ability to access transmission. Therefore, geothermal alternatives would

need to be evaluated on a case by case basis.

134 MW Existing Nuclear Generation (Palo Verde Unit 3)

PNM has capacity rights to 134 MW of Palo Verde Nuclear Generating Station from Unit 3 which is

not cunently in ratebase. As pa1t of PNM Resources merchant offerings, PNM has assumed that PV

Unit 3 could be transfened at a cost of 2,500 $/kW beginning in 2018. The cunent lease expires in

2046. PNM has assumed that transmission rights can be secured and held to be able to deliver

generation to the Four Corners hub. From there, with the retirement of San Juan Generating Station

Units 2 & 3 retirement, there will enough transmission service available to generation to load.

200 l\lW New Coal Generation

The 200 MW of coal generation based upon participation in a coal plant of a larger size. PNM used

the EPRI TAG database as the source of the new unit characteristics complete with environmental

controls such as selective catalytic reduction and carbon capture. Based on EPRI TAG estimates,

PNM assumes cost of $5, 195/kW. This resource was assumed to bypass any major transmission

upgrades and allow PNM to site it within WECC Path 48 in north central New Mexico.

200 MW New Nuclear Generation

The 200 MW of nuclear generation based upon participation in a plant of a larger size. PNM used the

EPRI TAG database as the source of the new unit characteristics to provide a proxy for the new

PNM Exhibit P 10-5 Part 1

Page 4 of 6

nuclear costs currently undergoing the licensing process for other utilities. Based on EPRI TAG

estimates, PNM assumes cost of $6, I 02/k W. Although those processes are currently for plants sited

on the eastern side of the US, PNM only used this simulate the cost to build nearer to load. This

resource was assumed to bypass any major transmission upgrades and allow PNM to site it within

WECC Path 48 in north central New Mexico.

250 MW Existing Combined Cvcle Generation

The 250 MW of market based combined cycle generation based current oversupply of generation in

the west. PNM believes there are possibilities in today' s market to purchase a portion of a larger

merchant project based on prices publicized by other utilities purchasing (approximately $700/kW).

In order for this to be a viable alternative as a replacement option in 2018, PNM expects that it will

have to obtain transmission services for a period of two years before commencement of any power

delivery in 2018 to the Four Corners hub. This cost has been included in the costs for this alternative.

Since the Arizona market appears to have opportunities to purchase merchant facilities, the

performance of this alternative is based on summertime conditions in Phoenix. Final costs,

performance, location and viability would depend upon the results of an RFP process.

78 MW Existing Coal Generation (San .Juan Unit 4)

As pa1t of the current ownership mix, P:C..TM has the ability to increment capacity at San Juan Unit 4.

PNM included a 78 MW incremental addition as a resource alternative.

PN!'v! Exhibit P J0-5 Part 1

Page 5 of 6

I ', l rPianning Penod

Cost of Capital (After-tax)

Inflation

Escalation on O&M

~Escalation on Fuel (natural gas)

Escalation on Fuei (coal/nuclear)

~Property Tax Rate

/?roperty Tax Rate

!Federal incentives Solar (lTC)

!state Incentives

Solar (lTC)

I So!ar(AEC)

Sorar(PTC)

,' 'i, I>

Nuclear

Coal

Combined Cycle

Combustion Turbme

Solar

' : J' !Annual Reserve Margin Target

I

!Carbon Emission Cost Adder (C02)

Capaoty factor for Wind alternative

Capacity factor for ex1sti ng PV resources

Capacity factor for new PV resources

Capacity factor for new solarthermal resource:

!Contribution to Peak(% of Nameglate)

!Wind Solar PV Technologies (fixed tilt)

Solar PV Technologies (single axis tracking)

Modeling Assumptions

f -,;- ' ' ,,,

2014-2033

8.18%

2.5% per year

25% per year

Varies Pace Global pncrng assumptions

Varies nuclear- 2.5% per year after 2020

2.45%

4.66% solar technologies only

30% (prior 2017)

10% (post 2017)

10%

Varies 10 years, caps at 200 GWh

,::: .• t'-,, ' i >' 40yrs Straight Line 15 Yrs MACRS

4Dyrs Straight Line 20Yrs MACRS

4Dyrs Straight Lrne 20Yrs MACRS

4Dyrs Straight Line 15 Yrs MACRS

4Dyrs Straight Line 5 Yrs MACRS

>i '' 'l<-. > .. ,': :· .. , '.: '< : 14%

Higher than 13% Resource Stipulation to account for uncertainty in

DR Programs, Wind, Solar and DG contributron at peak

Varies Beginnrng in 2020, Pace Global pricrng assumptions

39% Based on results from RFPs issued

26.7% Based on NREL data

26% Based on EPRI Study for NM CSP

28%/100% Based on NREL data (without storage)/with storage

S% Based on historical data of existmg wind facilities

55% Based on Historical Periormance

vanes begins at 72% then declines thereafter; based on NREL & RFP data

PN1H Exhihit P 10-5 Part I

Page 6 of 6

PNM EXHIBIT P.J0-5

Part 2 of 3


PNM Exhibit PJ0-5 Part 2 of3

Resource Alternatives

[------ Gas Alternatives ~

1\e.ourceName Ae<o Turl>lne

Capital Com/Non .. fuel Revenue Requirements.

IRP Slze, MW 40

IRP Reference- Yt><ff 2014

Ccmstructton E:;ca:dt.G~ ).S%

O&M Es~.,:aiat1on, 7t. 2.5%

Total Plant Cost. S:'JOJ':.

AFUDC. $000's

Total Cap1tal+AFUDC, S(JOJ''>

1 ?tal 6P~t;I+AFUDC. S/kW

Total Cap1tdl NPV Stra~ lnr .... t, SOVCJ'.:;

IRP/BART Performance .and O&M

,IRP/BART Slle. MW

Year l.s.t Ava1labl~.,

F1xed O&M•, SOOO :.,}yr

F~>ed O&M', S/kW-yr

Fi~-;;d-oiivl•:k$/y~ ~Vari-able O&M,-'s/MWh

Varrable O&M, ~5/yr

Equtva!ent Avadao~Hty

Heat rate. Bt.;/t:Wh

PPA Alternatives

!RP Reference YPar

PPA Alternatrve .

Emissions Oat<l

CO(ibs/MWh)

NOx (lbs/MWhJ

Particuia,te (lbs/1\/Vo,.h)

502 (lbs/MWn)

C02 (lbs/MWh)

Mercury (105/I..Wr:i

•FOII.tt~I;,J .. fa~tcpv.".;

i$/MWh/ (f!~ :R.P

40

&<.541

3,205

65,746

1,644

1 J,so_~ ,_

~c:s

0.12

0.08

J 00,

0.00

Qn<f ,;0~ 'r!:i,CfV,;IfK)J'l:~' jc:t,-;f)>l..:ubll'

~Turl>lne

($1J1i\11)

85

2014

2.5%

2.5%

135,493

7,1~-142,692 . 1:679;

164,094

~Turbille

. !far&el~

146,642

-- ?,690 154,331

1,679;

Ga$ Turbine

(laf&e)

1~3,80~ 1,006

16~,1~L~

~TU~ Gil$ Turl>lne ~IRed~ ~eel~

. RI;C:!p(oalti'1& {la!C'I SJ<>$ ~e)< ~

--·- ---~so 93

1g644 153,~85

21,152

_[~3;7,97 ~--1,038

204,446 [ $ - ----~- .. ····~·····-L--

P•ge 1 of 3

~1:~_81,

0.12

o_os; 100'

0.00; 845

2014

2.5%

385,3~6' 1,545 :

469,~31_~-~

0.11-

o.os

2014

166,307

o.26·~---3 65

blstln& l.al.ut:ll

Combkled Cyde

54,172

___ 2: 776_.

56,948 'i.414;--

' _6.6_,~!7. '-~

·····-

9,800

0.12

0.08

250

2014

B% 2.5%

173,000

17},000' 692

211,565

7_000

0!2 0 08

I ---,~--1 Capital C()~ts/Non-Fuel Revenue ~equirements

)IRP Size, MW ;1-RP~R;f~~e,n-;;e Year

~co-~s-t~~·~t-i~-~ ·E·;~~-~~-ti~~-~-% 'Q&"M"i:scal~t~·~n;% ...

Total PI~~~ <::o;t, sooo·; :AFUDC, S0001s .. . .....

~i'~\;i(;pii~I.P:Fu6c,$iioo;;· (ro!~ic~-pi!~ I;AFLioC, s/kw

Total Capital NPV Strat Input, $OOO's

IRP/BART Performance and O&M [I~ ~{BA_RJSJ_z'~: ~vi . . ........... . ;Year 1st Available

iFi~~dO&M', $000';/yr Fi~~d o&M*,S/kw:;,; 1Fi;;e'd-o&M•;i<s/vr · 'va;iabl~o&M'; s/Mwh -(variable o&iVI; kS/vr · ··· ~ EQ~i~~i'~-~t- A~~ii~b-ility 'fl~~trate, Bt~/kWh ·--

PPA Alternatives IRP Reference Year

PPA Alternative- LCOE ($/MWh) @ IRP

Emissions Data CO(Ibs/MWh) NOx (lbs/MWh) Particulate (lbs/MWh) SOZ (lbs/MWh) C02 (lbs/MWh) Mercury (lbs/kWh) ~ FOM mclr;des operations and mamtenanc.e, property taxes and g(

PNM E:.hibit P.J0-5 Part 2 of3

I -- -------Resource Alternatives I

I coal & Nuclear - - ] I Rene~at;lc~s :=J ,.

• Coat w/tarbon Palo V11rde 3{2.500 Solar TrQIJgh I capturll

lllw:tear $/kW}

Solar Trough {storage} ·

SolarPv SolarPV Wind· Biomass Geothermal .

2014 -11o'471 $

Page 2 of3

1--=l Capital Costs/Non~ Fuel Revenue Requirements

IRP Size, MW

IRP Reterence Year

ConstnKtlon Escalation,

O&M Escalation,%

Total Plant Cost, SOOO's

Total Capital NPV Strat Input. $000's

IRP/BARTPertormance and O&M _

_ IRP/BART Srze, MW

Year 1st Available

Vanable O&M, $/MWh

V~riable o&M, kS/yr Equ1valent Ava11abil1ty Heat rat~, Btu/kWh.

PPA Alternatives

IRP Reference Year

PPA Alternative- LCDE ($/MWh)@ IRP

Emissions Data CO(Ibs/MWh)

NOx (lbs/MWh)

Particulate (lbs/MWh)

SD2 (lbs/MWh)

CD2ilbs/MWh)

Mercury (lbs/kWh)

~tOM mdudt>~ Op<'•'ut•a/L\ <Yld ;-rrQ,fli~CI"an<:e, pr<'IH';,ty t<.Ut'.'> ,m:rgr

P~i\1 Exhibit P.J0-5 Part 2 of 3

[- Resource Alternatives ~-~-~--~]

c= Regional Haze Alternatives ""]

I SNCRs on SJGS SCRs on SJGS 4Unit

U2&U3 SCIIs on FC4 SCRs on FCS Ul-U4 (Total) Shutdown SJGSI

178 MW to SJ4)

2014 2014 2014 2014 2014

2.5% 2.5% 2,5% 2.S% 2.5%

2.5%

73,80S s 34,058 $ 31,096

$ 4,224

$ 3S,282 • s N/A $ 391 s 343 $ 564 '

85,514 $ 39,611

443 9S

2018 2017

$

564 s 564 $ 6A43

Page 3 of 3

PNM EXHIBIT P.J0-5

Part 3 of 3


SIEMENS

Page 1 Restricted ©Siemens AG 2013 All rights reserved. BPS I Pace Global

ro .a 0 (5 Q

) (.) ro

0...

(f) 0... (l)

N Q)

Ol

ro 0...

Pace Global's Marketlink scenarios are a set of four internally-consistent states of the world developed against a backdrop of changing policy frameworks over time

'It The prevalence of certain geopolitical, environmental, and macroeconomic conditions can lead policy makers to focus near-term on one of several competing aspects of energy policy:

--- Costs

Environmental Protection

~- Energy Security

Safety

'It As the geopolitical, environmental, and economic conditions change, energy policy is likely to shift away from the predominant near-term focus into other competing objectives

--· Market and regulatory response feedbacks over time

Each scenario is developed by carefully evaluating the relationships and correlations between energy policy and the fundamentals of fuel and power markets

The scenarios are intended to push the envelope of potential outcomes; in other words, they are plausible, but low probability

Page 3 BPS I Pace Global

Focus on low cost energy; weak environmental regulation; few coal retirements; few renewables

Strong environmental policy results in high C02

price, many coal retirements, and significant renewable expansion; power sector demand and fracking ban results in high gas pnces

Page4

Near term shock to oil and gas prices results in push for diverse domestic supply; opposition to exports, low gas prices longer term

Nuclear phase out with continued pressure on coal capacity; flat demand growth; pressure on gas pnces

BPS I Pace Global

• Pace Global and PNM identified natural gas price and carbon price as the two major drivers of portfolio performance

• The "Clean" and "Cheap" Marketlink themes drive gas and carbon prices in opposite directions, based on the underlying economic and regulatory drivers. These themes were used to define the selection of scenarios for use in the analysis.

• Three scenarios were deployed:

·.~~~~;i~s:;0,~"tf~'i;t~v l~.eferenoe,

'~-~~:,< \"


Conditions

Environmental Regulations

Natural Gas Prices (HH and Permian)

Gas Market Factors

C02 Prices

PRB Coal Price

National Coal Retirements

Regional Power Sector Load Growth

Power Sector Expansion

Page6

};>MATS remains on track for 2016 implementation

?NYMEX Forwards to 2015

>Modest growth in Permian gas production, declining San Juan production

>No C02 regime

YPRB 880010.80 in the range of $12-14/ton plus transport

>Announced (up to 25 GW)

};>Base load growth (1.5%)

J;>Continued replacement of coal fired generation with gas. Moderate expansion of solar and wind

Mid Term 2016-2025

J;>Possibility of additional regulations, e.g. revised CSAPR

J;>Gas prices move towards range of $5-6/MMBtu

>Growth, then plateau, of Gulf Coast LNG and Mexican pipeline exports

};>Modest C02 regime starts in 2020 ( -$1 0/tonne)

Y PRB 880010.80 in the range of $15/ton plus transport

};>10-15 GW (up to 40 GW cumulative)

>Base load growth (1%), increased efficiency saps growth

>Renewable penetration increases with 15-20% of load outside of SERC and RFC being met by renewables

Long Term 2026-2035

};>Gradual tightening of emissions restrictions

>Gas price increases towards a range of $6-7/MMBtu

};>Production costs edge up as associated gas development declines

};>C02 prices above $30/tonne in the 2030s

YPRB 880010.80 in the range of $13-14/ton plus transport

};>30-50 GW (up to 90 GW cumulative)

>Base load growth (0.5%), demand side management and efficiency stall most load growth

>Coal replacement with gas and continued build out of wind and solar throughout the country.

Note: All values represented in 2012$

BPS I Pace Global

Conditions



Gas Market Factors

C02 Prices

PRB Coal Price




Page 7

>- Potential delays/extensions for MATS compliance

>- Gas prices remain <$4/MMBtu

>-Rapid decline in San Juan Basin production; accelerated growth in pipeline exports

;;.. No C02 regime

~PRB 880010.80 in the range of $11-13/ton plus transport

>-Announced, with some reversals (up to 15 GW)

>-Low load growth (0%-0.5%)

;;..Replacement of coal retirements with gas and renewables in advanced development

>-No new environmental regulations

>- -$4-5/MMBtu as LNG exports begin

>-Sustained growth of Gulf Coast LNG exports; robust associated gas development

>- No C02 regime

~ PRB 880010.80 in the range of $14-18/ton plus transport

>-Limited coal retirements, <5GW (up to 20 GW cumulative). Mostly due to local and regional growth factors.

>-Demand growth recovery (1.5%)

>-Gas build out to meet demand growth with moderate expansion of wind in Midwest and solar in Southwest

>-Limited environmental regulations

>- Gas price gradually increases to $6/MMBtu

>-Production costs edge up as associated gas development declines

>- C02 price introduced ($1 0/tonne)

~PRB 880010.80 >$20/ton a short ton plus elevated transportation costs, due to high demand

>- Slight increase in coal retirements as concern for environment grows. 10-15GW (up to 35 MW cumulative) of older less efficient plants

>-Demand growth recovery (2%)

>-Limited renewable expansion; demand growth met through gas generation.

Note.· All values represented in 2012$

BPS I Pace Global



Gas Market Factors

C02 Prices

PRB Coal Price




Page 8

;;..MATS remains on track for 2016 implementation

;;..Gas price rises to $5/MMBtu

;;..Supply/demand similar to reference case; many states move to ban or sharply restrict tracking

;;.. Federal C02 policy passed

~PRB 880010.80 in the range of $12-14/ton plus transport

;;..Announced retirements

;;.. Load recovery (1.25%)

;;..Gas replaces retired coal with renewables significantly increasing share in West and Midwest

;;..Continued new regulations: revised CSAPR, regional haze, ash disposal, Federal RPS

;;.. Power sector demand and tracking restrictions result in price runups to $10/MMBtu

;;..EPA institutes tracking restrictions; drilling declines by 50%; LNG export construction stops; LNG imports increase

;;.. Federal carbon policy starts in 2018(-$35ftonneby2025)

~ PRB 880010.80 in the range of $12-14/ton plus transport

;;..Stricter policy, including C02, drives up to 140 GW of coal (cumulative) out by 2025

;o..Efficiency/DSM penetration (0.5%)

;;..Federal RPS sets 15% floor with most states, outside of SERC and RFC, reaching >25%

>Regulations increasingly restrict ability of coal-fired plants to remain economical

;;.. Some feedback to revert back to $7 -8/MMBtu levels

;;..EPA relaxes some drilling restrictions; rapid recovery of San Juan Basin CBM, other dry gas production

> C02 prices reach $55/tonne

~PRB 880010.80 in the range of $10-12/ton plus softened transport costs

>Stricter policy, including C02, drives up to 170 GW of coal (cumulative) out through 2035

;;..Efficiency/DSM penetration (-0.5%)

J.;-Strict environmental regulations and storage advances drive cost of renewables below fossil generation driving >30% penetration

Note: All values represented in 2012$

BPS I Pace Global

:::::s ...... m :E :E tA. N T""" 0 N

Permian Basin Natural Gas Price

10 9 ~ ~ ~

8 7 6 5 4 ~·

3 2 1 0

.. ,, \. y~p~~~~«~t~)~ri~,~eJ<l~;:~::!·~ > $5fMMBto .ut;~ti,l almostr2030;;:~:·

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--- Reference Low Gas & Carbon Scenario High Gas & Carbon Scenario


Q) s::::: s::::: 0 .....

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'···.·..-:~.·"~~w:~··~~··"~ ':'~"!~~ ~~J;~·':':':·~.~~::·, PRB FOB Price '"\~iea~hr:en~ir((fiman~~~~,i~. 1.6 -1 -------------

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--- Reference --Low Gas & Carbon Scenario ·'""''"""''_., .. ~ ... High Gas & Carbon Scenario


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Page 12

WECC Coal Retirements

""' .... --' , , ,----.,.,"' ,

CV) LO r- en .......- CV) LO .......- .......- .......- .......- N N N 0000000 NNNNNNN

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BPS I Pace Global

120

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Page 13

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BPS I Pace Global

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Page 15

·Capacity • Heat rate • Avail. ·Costs

~t~~~~ I I ...

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.... ····Reserve Margin

·Power Prices

BPS I Pace Global

Gas Supply Inputs

Gas Demand Inputs

Page 16

Fully Adaptable Model: Supply, Demand, Pipelines,

Storage, LNG Terminals can all be modified

Process Iterated Multiple Times

Output Fa recasts

~2~ip~1ipe{§~peig~~;f:roro " .••• Flf9dl,!.Q~r~.p)' ~OQ~.

BPS I Pace Global

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Conditions

Key Drivers

Key Energy Policy Components

Page 18

Short Term 2013-2015

)> Weak economic recovery places focus on cheap energy

)> No new regulations other than MATS

)> No C02 regime

)> Low fuel prices (gas below $4/MMBtu)

)> Low load growth driven by weak economic growth

)> Low power prices

)> Announced coal retirements

Mid Term 2016-2025

)> Weak economic recovery

? Free trade policies dominate

)> Limited support for renewable energy and emissions regulations

)> No C02 regime

)> Gas prices remain low ($4-5/MMBtu) as LNG exports begin

)> Coal prices begin to rise due to increased demand and exports

)- Electricity demand grows with no focus on efficiency measures

)> Limited coal retirements

Long Term 2026-2035

Y- Moderate economic growth

Y- Growing but limited environmental policy focus

)> C02 price introduced ($1 0/tonne)

)> Gas price increases to $6/MMBtu as demand grows

;;. Demand for eastern coals declines while PRB demand remains strong

)> Electricity demand continues to grow rapidly

)- Slight increase in coal retirements as concern for environment grows

BPS I Pace Global

Conditions

Key Drivers

Key Energy Policy Components

Page 19

Short Term 2013-2015

~ Strong economic and political conditions ripe for environmental regulations

~ Strong support for stringent environmental regulation

~ Strong anti-fossil fuel orientation

~ Federal C02 policy passed

~Increased gas demand results in higher gas prices

~ Reduced demand for coal

~ Economic recovery leads to strong power demand growth

~ Environmental policies to drive massive coal retirements

Mid Term 2016-2025

~ Economic conditions strong

~ OECD largely agrees to common 80% by 2050 carbon target

~ Federal carbon policy starts in 2018 ( -$35/tonne by 2025)

~ Increasing gas prices (at times reaching $1 0/MMBtu)

~ Declining coal use domestically, exports continue

~ Efficiency policies and load reduction measures result in declining load

~ Coal retirements reach 140 GW (cumulative) by 2025

3

Long Term 2026-2035

~ OECD economic growth declines

~ OECD carbon goals moderated, 50% by 2050 carbon target

~ C02 prices reach $55/tonne

~Gas prices moderate to $7-8/MMBtu level

~ Significant coal demand decrease

~ Load growth continues to be negative

~ Coal retirements reach 170 GW (cumulative)

BPS I Pace Global

ro .0

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Catalyst Paper Snowflake ___ _

-~=- __ __:_:.-ceiifr~a:-¢omi>~"-•-=-= __ . -1 ::·.:::·.:~;.:-----L.-----centralia Complex

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----~-"-~f!.~OlJOO_e!"!i.OO C~---- ~~unnrsid~-~-~-~-~~!!l_~~_9_f!._ Ass_~~i~~----- -----+--·-'-4.~.:::!... ________ _

Torrance Refinery ·- ·- · ·-- ·-··-···valmanl-······ --wNclark

wilbur- E:a5t t>owei Plant Wilbur west Power. Plant

-wY.aia~ .... : ___ r<>llowsto_neE:n~r_Qt_L_t> _____ _

12./31/2024 ' 12T3IZ2624- __l_:=~··---2.~?{

*Note that the San Onofre Nuclear Generation Station (SONGS) in California is retired across all cases.


---------~_g_:~~::;::§~~~~~t=~~: ~- __ , __ _ .Che_roke_e (C9L ____ _

_______c_;,ot~a____ ___ _ ____ CI)I~nl'~l1_<l'\lL _

Dave Johnston East tfiir<J sireat

~-~-------·-·-------------- -·----- --Four Corners

-- --riWiis-on-sundi <3€mer8i;ri9 siatTOn , __ --------- -- -Hay_deri--~==-----

J E Corette Plant -~--~--- ---~~--------

Kucc t<LiCc

Wilbur East Power Plant --wi11JurWesi Power-PlanT

- ---- - - wyodak ----- ____ v'ii_iowsto-nej'nergy·-;c;----- 2029

*Note that the San Onofre Nuclear Generation Station (SONGS) in California is retired across all cases

Page 22

-------f-----~~----

X

BPS I Pace Global

*Note that Navajo and Intermountain are additional plants for retirement beyond the Reference Case. *Note that the San Onofre Nuclear Generation Station (SONGS) in California is retired across all cases.

Page 23 l\U reserved. BPS I Pace Global

PNM EXHIBIT PJ0-6


PNM Exhibit P.J0-6

SJGS Unit 4 Additional Capacity Portfolio Comparison

Scenario Description Revised SIP with PV3 Revised SIP with PV3 no 78 MW to SJ4

line ~~~-------------------f--------~~~~----~----------1---------~~~~--~-----------1 [11 Gas Pricing PACE Reference Case PACE Reference Case

[2} C02 Prid~_g -------- __ .:cPA:~C:::E:_.: Rc.:e:::fe:c.r.•::nc.:c:,::e.:cC:,::as:::e:.>(.:.$:::11:..;1~n..::2:::02000"-)----t-·---'-P'-'AC:::E:.;Rc.:e:f:e:::r..::e:::nc':'e:::=C::a:::se,~(c:S_ll~:.::.:in_:2c::0:::20::l) ____ _ f3j Energy Efficiency forecast 2014 !RP Forecast 20141RP Forecast

{41 PV DG Forecast 2014 !RP Forecast 2014 !RP Forecast

(Sl Demand Response Forecast 2014 !RP Forecast 20141RP Forecast

f6] Resource Alternative Database EPRl TAG/PNM Estimates EPR! TAG/PNM Estimates

[7} Renewable Procurements ----1----....:2"0'-'1'-'4-'-Ro:'E:-'PP:;:+=-::-;Pr:Co'-:jec:ct:;;io:::n;.:cs_ ----11----- 2014 REPP +Projections ------j [81 Palo Verde 3 Available $2,500/kW $2,500/kW

[9] NOx Control at San Juan SNCR's on 1 & 4 SNCR's on 1 & 4

(10 } San Jwan O&M Harvest Savings Units 2 & 3 Units 2 & 3

(11 } San Juan Investment Recovery $16,401,523 $20,601,519

(12 I SJ Retirements Units 2 & 3 (Dec 2017) Umts 2 & 3 (Dec 2017)

[13 I 2014 (14 i 2015 Red Mesa {102 MW) Red Mesa (102 MW)

[15 I [16 I 2016

2015 Solar {23 MW) 2015 Solar (23 MW) b::-:-::-------------t------A:--e.:.r:cod'Ce""ri"'va"'t'-iv"'e:C(4:-'0~M:C.:W'-:c.)---------~-----;A-"er"'o":d'-er'-'iv"'a0:tlv-"e0:.:(C'40-:7M':LW:-c):-----l

[17 I Solar (40 MW) Solar (40 MW)

[18 I 2017 [19 I 2018

----+-----·-:----:=-::::-:-c-:c:--------- ·-----------------Large GT (177 MW) Large GT (177 MW)

[20 I Palo Verde 3 (134 MW) Palo Verde 3 (134 MW}

(21j -·------------+---"'Sa:::c...:J:.:":::an::..:..:Ac;;q;::u:.:":.:''=io;_:_n-"17:_:8:_:M~W='~1._. __ ~- -----2nd Aeroderivative (40 M~---

[22lr-----------------------+------------------------------+------------------------; [23 l (24 I 2019

l::=c----------+--------------------------------

(25 I 2020 Wind {100 MW)

[26 I 2021 [27 I 2022

::;.:-:------------r-------__"'!_l_fl!! (100 MWL_ _____ ---·--·-----;:-;--,==c---------Solar (20 MW)

[28 J 2023 [29 J 2024 [30 J 2025

::::-:::--·-------·---------------------- ---· Aeroderivative (40 MW) ___ _

[31 I 2026 Solar (20 MW)

[32 I 2027 2nd Aeroderivative {40 MW) Large GT (143 MW)

[33 J 2028 [34 I 2029 Aeroderivative (40 MW)

[35 J 2030 [36 1 2031 Small GT (85 MW)

[37 I 2032 [38 i 2033 =::-------------!-------------- -----~---,A;-e-rod-;-e--,-nv::-:at--,-ive:-;(-:-:;40:-:-M:::Wcc-)----

[39]

20-Year lOLH

1401 Average NPV

(41} Difference to Revised SIP with PV3

Average NPV [41)

95th Percentile Risk

51.20 37.74

$6,640,253,862 $6,719,185,750

$78,931,888

$194,357,382 $205 615,262

BEFORE THE NEW MEXICO PUBLIC REGULATION COMMISSION

IN THE MATTER OF THE APPLICATION l OF PUBLIC SERVICE COMPANY OF NEW ) MEXICO FOR APPROVAL TO ABANDON ) SAN JUAN GENERATING STATION UNITS ) 2 AND 3, ISSUANCE OF CERTU'ICATES ) OF PUBLIC CONVENIENCE AND ) NECESSITY FOR REPLACEMENT POWER ) RESOURCES, ISSUANCE OF ACCOUNTING ) ORDERS AND DETERMINATION OF ) RELATED RA TEMAKING PRINCIPLES AND) TREATMENT, )

PUBLIC SERVICE COMPANY OF NEW MEXICO,

Applicant

) ) ) ) )

AFFIDAVIT

STATE OF NEW MEXICO ) ) ss

COUNTY OF BERNALILLO )

Case No. 13-00 ___ -UT

PATRICK J. O'CONNELL, Director, Planning and Resources, Public Service

Company of New Mexico, upon being duly sworn according to law, under oath, deposes and

states: I have read the foregoing Direct Testimony and Exhibits of Patrick J. O'Connell and it

is true and accurate based on my own personal knowledge and belief.

SIGNED this 17th day of December, 2013.

(---"-,

\[il;'Lt'f __ -f' ?. {(1\vt.~(( ____ _ PATRICK J. O'CONNELL

SUBSCRIBED AND SWORN to before me this 1 ih day of December, 2013.

OFFICIAL SEAL · sAMlS~Marehead

NOTARY PUBLIC IN AND THE STATE OF NEW MEXICO

2 GCG #517362

V )/media/Files/P/PNM... · PNM Exhibit PJ0-6 AFFIDAVIT Resume of Patrick J. O'Connell Current Load and Resource Projections Summary of Regional Haze Compliant Portfolios Revised

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