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Fxhibit TAG4
Page 47 of I 10
83 50 hxrcxatio~~ Any and dl equipment placed on the premises of a Party sh& be
and remain the pperty of &e Party providing such equipment regardlas of the
mode a d manner of annexation or attachment to real prumy, des ~th~~istt
. mutually agreed by the Parties.
ArticIe9. - Operations
9.1: General. Each Party shall comply with the Applicable Reliability Council
q&e.ments. Each Party &dl provide to the other Party all infomation that may
reasonably lx required by the other Party to comply with Applicable Laws and
Regulations and Applicable Reliabil* Standards.
9.2 Conrrol Area Sorification. Ai I& tkcc munh behe Initial Spchronizatim
Date, htercomection Customer shall notify Transmission Provider in wridng of
&e Control Area in which lhe Large Generating Facility will be located. If
Tnterconection customer elects to locate the kge Gmerathg Facility in a
Cmld Area other than the ConmI Area in which the large Generating Facility is
physMIy located ad ifpded to do so by the rekvant transmission tariffs, all
necessafy arrangements. mciuding but not limited to those set forth in Adele 7
and klicle 8 of this LGLLZ, and remote Control Area gemrator interchange
agreements, ifapplicable, and rbe appropriafe measurrs under such agreements,
shall be executed and implemented prim to the placement dthe Lmge Generating
Facility irm thc other Conml Area.
9.3 Tnmsmission Provider Obligations. 'l'ransmission Provider shall cause the
Tmsmission System and TranSnisSiun Providds Tnterconnedon Facilities to be
operated, maintained and controlled jn a safe and rdiablc manner and in
accordance with this LGIA. Tmsmissioa Provider may providc operating
imtmctions to Interconneerion Custamer consistent with this LGZA and
TmnunisSim Provider's operating pmtocoIs orad procedures as they m y change
from time to timc. Tmmission Provider will consider changes to its operating
protocols and proc&es proposed by Interconnection Customer.
.:-
, .I
39

Exhibit TAG4
Page 48 or i 10
9.4 htcrconndon Customer Obligations. htmmectim Customer Wl al it3
own expense operate, maintain and mntro1 the Large Gemh~g Fslcilityand
htercdon Customds Intercanrtecti on Facilities in a safe and reliable manner
and in acooraanCe with this LGIA. Zntercormection Customer shall opate rhc
b m e Gemmtmg Facility and Intercompection Cummds Intacomedon
Faciua in accordance with dl applicable requhmenB ofthe Control Area of
which it is pert, ws such requirements are set forth in Appendix C, htercomectiun
Details, of this KIA, Appendix C, InkrcbnneCtion Details, will be modified to
reflect changes to the requirements ashy may change from time to time. Either
Party my request that the other Pany provide copies of the requkments set forth
in Appendix C, Inteconnection &tails, of this LGIA.
9.5
Srart-Up and Synchronization. Consistent with the partics' mutually auxptable
procedures, Intercormctbn Customer is responsible for tbc proper
sqdironization of the Large Generating Facility to Transmission Provider's
Transmission System.
9.6 Rea ctke Power.
9.6,l Power Factor Design Criteria. Interconredon Customer shall design the
Large Canerating Facility to rnabhin a conposite power delivery at
continuous rated pwu output at the Point of Interconnection at a power
W r within the range of 0.95 l&g to 0.95 lag, dess Transmission
Provider has cstablishcd different quirments that apply to all genmtors
in the Control Area on a m w l e basis. T'hc requirements ofthis
pmpph shall not apply to wind generators.
9.6.2 VoItage Seheduies. Oace Interconnection Customer has synchronizled the
Large Generating FacihQ with thc Transmission System, Transmission
A.ovider shall require Interconnection Customer to operate the Large
Genaating Facility to produce or absorb reactive power within the &sign
limitations of the Large Gmdg Fadip set forth. in Article 9.6.1 power
Factor Desii Citeria). Transmission Provickfs voltage scheddes shall
treat all sowm o€m&ve power in the Conmi Area in an cyuit;tble and
not unduly discriminawu manner- Trammission Provider W1 exercise
ReasmabIe EE&s to provide IR~~OIXI&O~ Customer with such
schedules at least om (1) day in advance, and may make changes to such
schdul~s as not- to maintain the relhbility of the Transmission
Systm. Interconnection Customer WI qmate the Large Generating
Facility to maintain the specified output voltage or power factor at thc Point
. of Interconnection within ibe dwig limitations of the Large Generating
Facility set forth in Attick 9.6.1 (Power Facfor Design Crite~a)- If
40

Exhibit TAG4
Page49ofllO 103
9.6.2.1 Governom and ReguIatoxs. whefievep the Large
Gmemting Facility is operated h plld with the
Trammis~jon System and the speed gums (XinShIkd on
the generating unit pursuant to hod utility Practice) and
vokage regulators ate capable ofoption, Tnterconnection
Customer W operate the Large herating Facility w3h its
speed governors and voltage rcguhtors in automatic
option. Ifthe Large GanWating Facility's speed governors
and voltage regulators are not capable of such autmic
option, Intmmection Customer shall immeaiitely notify
Transmission. Provider's syslirn operator3 or its designated
represcnhtiw,, and ensure that such Large herating
Facility's reactive power production or absorption (measured
in MV~TS) arc within the design capabilily of tbe rage
Genming Facility's generating unit@) and steady state
stability limits. hmmection Customer sMl not caw its
Large herating Facility to disconnect autornatkdly 01
~tanrm~usly ftm the 'Transmission System ar trip any
generat@ unit comprising the hrge Genenitinng Faciliry for
an under or over frequency dition unless thu abnormal
frequency condition persists for a h e pen'od beyond the
hits set forth in ANSUIEEE Standard C37,I04, or such
other standard as applied to other generators in the Control
Arm on a compambk basis.
9.6.3 Payment forReactive Power. Transmission Provider is required to pay
Interconnection Customer for reactive power that Intercomection Cmtoxer
provides or nbsohs fiom the Large Gencmting Facility whn Transmission
Provider requests Xntercomection Customer to operate its Large Generaiing
Faciiity outside the range spcdficd in Article 9.6.1, provided that if
'liansmission Provider pays its OWXI or afiliated generators for reactive
power service within the speci[id range, it m w also pay Interconnection
Customer. Payments shall be pursuant to Article 1 1.6 or such ohm
agreema to which the Parties have otherwise weed.
9.7 Outqes and Interruptions,
. '?
... .
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9.7.1.1
. :*
- 9.7.12
9.7.1.3
Fxhibit TAG4
Page5Oof110
Oatage Aufho rity and Coordination. Each Party may in
accordme with Good Utility Pmcticc in coordination with
the other Pdy remove hm service any of its respective
InterconneCtiOrr Facilities or Network Upgrades that may
impact &e otber Party's facilities a5 m perform
lrnaintenance OF tdng or to instdl or replace equipment.
Absent an Emergency Condition, the Parly scheduling a
moval of such fa&ty(ies} from mice will use Reasonable
Effom to schedule such rb-moval' on a date and time mutually
acceptabk to the Parties. In all circurnst;inces, my Party
p&hg to remove such facili:y(ies) from service shall use
Reasonable Efforts to minimiat the effecr on the o k Party
of such removal.
Outage SeheduIes. Transmission Provider shall post
schddcd outages of its mnsmission faciIitics on the OASIS.
Interconnection Customer shall submit its plwned
maintenance schddes for &e Large Generatifig Fadity to
Tmmission Providm for a ininhum of a roiling twentyfour
month period. In~moction Customcr shall update its
planned maintenance schedu1e.s as nwcssary. Transmission
Provider may quest hterccmection Customer to reschedule
its rnaintmance as necessary to maintain the reliability of the
Transmission System; provided, however, adequacy of
generation supply shall not k a criterion in dcrcrmining
Transmission System reliability. Transmission Pmvider shall
compensaE Interconnection Customw for any additional
. direct costs that Intercomtion Customer incurs as a resuIr
of having to reschedule maintenance, includhg my additional
overtime, breaking of maintenance contracts or other costs
abve and beyond the cost Tttcrconnection Customer would
hve id absent Trawmission Provider's request to
reschedule maintenance. h~Ierconnection Customer witl. not
be eligible tu receive cornpewtion, if durbg the twelve (1 2)
mouths prior to the date of tkc scheduIcd maintenance,
Intercome&n Customer had modified its sc hedulc of
maintenmcc advitiw.
Outage Restoration. If an outage: on a Party's
Tntercomection Facilities or Mctwork Vpgades adversely
affects the other Party's operations or facilities, the Party that
oms ox controls the faciliry rhat is out of smke shall use
42

i.
EA ibi t 'I'A G -4
Page 51 of 110
Reasonable Efforts to promptly restore such hcdity(ies) to a
normal opting condition consistent withthe nature of the
outage. The Party that owns or ccmnfrofs the facili~ that Is out
of service shall provide the other Party, to the emt such
information is known, information an the nature of the
Emergency 130nditioq an estimated time of restodon, and
any comdve actions m-uid- Initial verba! notice shafl be
fotIowed up as soon 8s practhble With Wrinm notice
cxplahhg the nature ofthe outage.
9.7.2 Interruption of Senice. Ifrequired by Goad Utility Practice to do SO,
Transmission Provider may rem htercomdon Customer to inrerrUpt
or rcdwc deliveries of electricity if such delivery of ektricjw could
adversely affect Transmission Provider's ability to perform mch activities
as are necessary to safely and reliably operate and maintain the
Transmission System. llx foilowing provisions shall apply IO my
interruption or redudon permitted under this Article 9.7.2:
9.7.2.1 The intermptiw or reduction sMi corrtinw only for so tong
BS reasonably necessary under Good UtiIity Practice:
9.7.2.2
9.7.23
Any such intermption or reduction shall be made on an
cquitablc, n0n-d~ crimkhy basis with rqxct to all
generating facilities dircctly conncctcd to the Transmission
SyStm;
When the itxmpthn or reduction must be made under
circurnstanccs which do not allow for dvance notice,
Transmission Provider shall notify lntcrconnection Customer
by telephone as soon as practicable of the reasons for the
curtailment, intemrptioa, or reduction, and, if horn, its
expectad duration. Tzephone notification shall be followed
by wrifm-~ notification as soon as practicable;
9.72.4 Except during thc cxistcnct: of an Emergency Condition,
when lhe interrlIption or reddon caa be scbedukd without
dvance notice, Transmbion Provider shall no@
intmnncction Customer in advance regarding the timing of
such scheduhg and furrher notify lnntcrcmcc~ion Customer '
of the cxp&ed duration Transmission Providm shall
coordinate with Inkconnection Customer using God Utility
fractice to xhedde the &mption or reduction during
... .
43

Exhibit TAG4
Pqe 52 of 1 10
9.7.2.5 The Parties shall cooperate and ccwrdiraate with each other 10
the extent necessary in order to restore the large Gmcmhg
Facility, Jntmonnection FaciIitiq and the Transmission
System to their n d optraring state, consist en^ with sysconditions
and Good Uti& Practice.
9.73 Under-Prequency and Over Frquwq Conditions- The Transmission
System is desi& to antically activate a load-shed program as
required by the Appkabk Reliability C O In the ~ event ~ af an under-
€rqumcy system dWmx. htmcomw?ion Customer shall implement
under-fiequcncy and wer-frequency rclay set points for the Large .
Generating FaciIiry as required by tbe Applicable Reliability Council to
emure ''ride through" capability of the Trmsmisdon Spmn. Large
heratbg Facility response to frequency deviations of pred&rmincd
rnagnitudcq both tmdCr--hquency and over-frequency deviations, shall be
studied and courdinatcd with Transmkion Rvvider in accordance with
Good Utility practice. The term "ride thtough" as uscd herein sbli mean
the ability of a Gentrating FaciIity tu stay connected to and synchized
with tbc Transmission System dhg system disturbances m-i~lin a range of
~der-frequcncy and over-frequency c:o~.tions, in accordance with God
utility Praaicc.
9.7,4 System Protection and Other Control Requkemeats.
9.7.4.1 System Protection Facilities. Interconnection Customer
sMl, at its expense, innstall, upemte and maintain System
Protection Facilities as a part of the Large Generaring FaciQ~
M hterconnectian Customds Ifitercomechn Facilities.
Tdssion Provider shall install at Interconnection
Customer's expense any System Protech Facilities that nay
be required 011 Transttlission Provider's Intercmnection
Facilities or the Traxasmision Systcm as a result of the
interconnection of the La.ge Csnerating Facility and
Intammectiort Cwtumeis lntercomecfion Facilities.
8.7.4.2, Each Party's protection facilities shall be designed and
ccurdjmtd with other systems in accordance with Good
utili@ MGe.

Exhibit TAG4
Page 53 of 110
9.7.4.3 Fach Party shall be mponsibk for protection of its facilities
consistent with Gwd'Uti3iQ Racticc.
9.7.4.4 Each Party's protective relay design shall incorporate the
nmessary test switches to perform the tests required in &ick
6. The required 'test switches will be pIaed such that they
allow operation of lockout relays while preventing bteaker
failure schemes from opemting and causing unnecessary
breaker operations and/or the tripping of Intercomecti~
Customer% units.
97-45
9.7.4.6
Each Party d l mi, opr& and maintain Sysem Protection
Facilities in accordance with Good Utility Practice.
Prior to the In-Semice Date, and again prior to the
Commercial Operation Date, each Party or i~ agent shall
perform a complete calibration test and Zunctiond trip test of
iht System Protection Facilities. At intervals suwsted by
Gcd Vrility Practice and fdlowhg m y apparent malfunction
ofthe System Protection Facilities, each Party shall p ~ o m
both calibration and funtiom1 ~p tests of its System
Protmion Facilities, Thee tesff do not require the tripping
of any in-service generalion unit. 'Ihese tcsk do, however,
require that dl protective rc1ay.s and Iockout contacB be
XtiVZlled.
9.7.5 Requiremen@ for Protection. In compliance with Good Urility Practice,
Interconnection Custmer shall provide, instali, own, and maintain relays,
circuit brcakcrs and all other devicts necessary to move any fhdt
contribution of the Large herating Facility to any short circuit wcmhg,
on the Transmission System not oth&e isolated by Transmissioa
Providds equipment such that thc fernoval of the kult con~bution shall
be coordinated with the proteahe tcquiremmts of the Tmmhsion
System. Such protective equipment shall incIude, Without limbtion, a
disconnecting device or switch with load-intcmrptisg mpbility Iacated
betweefi the Large Generatirg Facility and the Transmission Systcm at a
site selected upon mutud agreement (not to be unreasonably withheld,
conditioned or delayed) o€ thc Parties. Inemmection Customer shall be
mpnsibk for prutection ofthe Large Generating Facility and
interconnection Customer's other equipment brn such conditions as
negative sequence cmts, over- or under-frequency* sudden load
rejection, over- or under-voltage, and generator loss-of-fizld.
45

Exhibit TAG4
Page 54 of I IO
ILI~~~~MCC~~OII
Customer shall be solely respansibh to disconnect the
Large Genera* Facirity and ht.rc-on Customer's other equiprncnt
if conditions on the Transmission System could advemcIy
Generating Facility.
the Large
9.7.6 Power Qual$- Neithm Party's facilities shall muse excessive voltage
flickor nor introduce excessive distortion to the sinusoidal voltage or
current waves as defined by ANIS1 Standard CX1. I - 1 989, ia a&o&ce
with IEEE3andard 519, or any applicable supeaseding electric iad-
standard. In the event of a ConfIiCz between ANSI Standard '284.1 - 1 989, or
my appliable superseding electric inrtustry standard, ANSI Standard
C84.1-1989, or the applicable supersding clectric industry standard, shaI1
control.
9.8 Switch&- and Tagging &des. Each Party &all provide the other Party a copy of
its switching and tagging des that are applicable to the other Party's activities.
Such m4cE'ting and a&g rules shall be deve1oped.m a nokdiscriminatory
basis. The Parties shll comply with applicable switching and tagging des, as
mended from time to time. in obtaining clearances for fT;oTk or far switchjng
opmtions an equipment.
9.9 Use of Interconnection Facilities by Third Parties.
9.9.1 hrpose ofhterconnecction Facilities. Except as mzy be required by
Applicable Law and Regulations, or as otherwise agreed to among tire
Parties, the hrmnnection Facilities shall be constructed for the sole
pt~p% of hercoimecthg the Large Generaring FaciIity to the
Transmission System znd shall be uscd for no other purpose.
9.9.2 Third Party Users- If required by Applicable Laws and Regulations tlT if
the Parties mumally a pe, such agreement not to be uarcasonably
withheld, to allow one or more third parfes to we Transmission Provider's
Xntmmction Facilities, or any part thereof, Interconnection Customer
wilI be enad to compensation for the capital expenses it incurred in
connection with the herconncction Facilities based upon the pro rata 'use
ofthe Interconnection Facilitim by Tmnission provider, all third party
users, and Interconnection Custmer, in accordance with Applicnblc Laws
and Regulations or upon sone ather mutudly-agreed upon meMology.
Xn addition, cos1 responsibiIity for ongoing costs, including operation and
maintmance costs associated with the Interconnection Facilities, wiU be
allocated between Interconnection Customer and any third party users
based upon the pro rata use of the Inrermmection Facilities by
:.
46

Exhibit TAG -4
Page 55 of 1 10
.3 09
Tmmission Provider, d third paay users, and IoterconneCtion Custumer,
in accordance with Applicabre Laws and Regulations or upon somc other
mutually agreed upon methodology. Ifthe issue of such cumpensation or
allocation m o t be resolved through such negotiafions, it shalI be
suhitkd to YERC forresoIufion.
9.10 Disturbance Analysis Data Exchange. The Parties d l cooperate With one
mother in the analysis of disturbances to &her the Large Generating Facility or
Transmission Provider's Transmission System by@ekg and providing access
to ary information relating to any disturbance, including information from
oscillography, protective rehy targets, breaker Opcmtions and sequmcc of events
records, and any dkmbmce MmaCiOn required by Good Utility Practice.
10.1 Tmmission Provider Obligations. Transmission provicfer shall main& the
Transrhission System and Tmmission Provideis Inkrumnection Faci litits in a
safe and reliable' manner and in accordauce with this LGIA.
102 Interconnection Cuatomcrr Obligations. Intercomdon Customer shall
maintah the Large Gwemhg Facaty md Interconnection Customer's
Interconnection Facilities in a safe and reliable manner and in rtccordmxe with this
LGIA.
10.3 Coordination, The Parties Wl confer rcgularry to coordinate the p w g ,
scheduling and performance ofpreventive and corrective maintenance on the
Large Generating Facility and the Tntcrcomection Facilities.
10.4 Secondary Systems. Each Party shd cooperate with the other in ihc inspection,
maintenance, and testing of control or power circuits that operate bcluw 600 volts,
AC or DC, including, but not limited to, any hardware, control or protective
devices, cables, conductors, electric mceways, secondary equipment pis,
transducers, baReries, chargers, and voltage and current transformers that directly
affect ths operation 6f a Pws facilitks and eqkpmt which mal- reasonably be
expected to impact the other Party. Each Party shall provide advrmce notice to the
other Partybefm lldmtdm ' g any work on such circuits, especially on electrical
circuits involving circuit breaker fxip and close contacts, current kansfmm, M
potential transformers.
10.5 Operating and Maintemcc Expenses. Subject to the provishns herein
addressing the us0 dfacilitks by others, and cxcept for options and
47

11.1
11.2
I13
Exhibit TAG4
Page 56 of 110
maintenance expenses assuchted with modifications made for providing
int%rcormection or trammission service to a third party zpnd such third party pays
for such expenses, Interconnection Customer shall be respo&b€e fur d
rewonable qses including overheads, assocjated with: (I) owning, operating,
maintaining, repaixing, and replacing Interconnection Customer's Interconnection
Facilities; and (2) operation, maintenance, repair and replacement of Transmission
Providefs Interconnection Facilities.
htcrconncction Customer Intercoronertion Facilities. Interconnection
Customer shall design, procure, construct, hall, own a dor control
Int&cmne& Customer Entercomection Facilities described in ,4ppendix A,
htmmction Facilities, H&mk Upgrades and Distribution Epgades, at its
sole expense.
Transmission Provider's Tnterconncction Facilities. Tmkssion Provider or
TransmisSim Owner shd1 daign, procure, construct, install, own andlor conmi
tbe Transmission Provider's Interconnection Fadities descinkd in Appmdix A,
Zntacomedm Facilities, Network Upgrad= and Distriiution Upgrades, at the
sole expse of the Interconnection Customer.
Network Upgraddes and Distribution Upgrades. Transmission Provider or
TransIxljssion Wncr shall design, procure, construct, install, and own the Network
Upgrades and Distribution Upgrades described in Appendix A, Inremnnectiun
Facilities, Network Upgades and Distribution Upgrades. The Intercomecum
Custumer shall be responsible for all costs related to Distribution Upgrades.
Udm Transmission Provider or Transmission 0p;ner elects to fund he capiial for
the Kebvork Upgrades, d q shall be solely funded by Tntcrconnection Customer.
i1.4 Transmission Credits.
11.41 Rcp3yment of Amounts Advanced for Network Upgrades.
. Interconnection Customcr shall be entitled to a cash repapen&
cqual to the total amoant paid to Tansmission Provider and
Affected System Operator, if any, for the Network Upgadq
including any tax gross-up ur other tax-related payments associated
with h'etwark Upgrades, md not refundd 10 Interconnection
Customer pursuant to Article 5.17.8 or dhcrwise, to tx pid to

11.42
Exhibit TAG4
Page 57 of 110
Interconnec~ion CWomer on a dollar-for-dollar basis for the nonwage
smsitive &on of trammission charges, as payments are
made under '€'rans&xission PKlvider's Tariff and Af%& System's
Tariff for missbn Services with respect to the Large Generating
Facility. hny repayment shall indude inmest cdcdatd in
accordance with the metHod010~ set forth in FERC=s regulations at
18 C.F.R. I 35.19a(ax2)(iiQ from the date of any pcl)'ment for
Network Upgrades through. the date on which the Internmedon
Customer meivcs a rcpayment of such payment pursuant to this
subpagraph. htacunn@on Cuss~mer may assign such
repQymenirigkts to any person.
Kotwithtanding the fmcgohg, 'Intmmection Customer,
Transmission Provider, and Affected Systm Opemior may adopt
any altmative payment schedule that is mutually agreeable so long
as 'hm&ion Provider and Affected System Optxitor take one of
the following actions no later than five years from the Commercial
Operation Date: (I) return to Wmconnection Customer any
mourn advanced for Nemnrk Upgrades nut prcviwsly repi4 or
(2) decks in whing that Tmission Provider or Mected System
operzrtor wilL conhue to provide payments to Interconnection
Customer an a dok-forddlar basis for the non-usage sensitive
portion of transmission chgcs, or dcvelop an alicmtk schedule
that is munznHy WeabIc and provides for thc r cm of ail amamts
advanced for Network Upgrades not previously repaid; however, fuLl
reimbursement shall not ex?& beyond twenty (20) yeam from the
Commercial Opmtion Date.
If the Large Generating Fdity ~b to achieve commercial
operation, but it or another Generating Facility is later constructed
and makes use of the Netwoik Wpgrades, Transmission Provider and
Affected System Operator shall at that time reimburse
Interconnection Customer for the mounts advanced fur the %&work '
Upgrades. Before any such rehbursernmt can occur, the
hterconncction Customer, m.&e cn~w that ultimately constrtrcts the
Generating Facility, if &rent, is rqmmible for identifying the
entity to which reimbursement must be made.
Special Provisions for Affected Systems. Unlcss Transmission
Provider provides, under the EGJA, for the repayment of mounts
advanced to Affc~d System Opcrator for Nebvork Upgtadcs,
49

E.xhibit TAG4
Page 58 of 110
11.43 Notwhhstanding any other provision of this LGlh, nathhg herein
shaU bc construed as relinquishing or foreclosing any rights,
including but not limited to frrm trammission righis, capacity rights,
transmission coagdon rights, or transmission diu, that
htercamectioll CuStoIIIer, shall h entitled to, now ar in the future
under my other agreement or tariff as a resuIs of, or othenrise
capcay, X any, created by the
associated with, the t i o n
Network Upgrades, including the right to obtain cash
reimbursements or transmission credits for transmission smice that
is not associated with the Large Generating Facility.
115 . Provision of Security. At least iHirty (30) Calendar Days prior to the
commencement of the pmment, installation, or constmaion of a discrete
portion af a Tmission Provider's Lnrerconnection Faciiitia, Network
Upgrades, or Distribution Upgrades, Intercomection Customer SM pvide
'I'rar?smission Provider, at Zntercomcctioo Custome?~ option, a gumtee, a smew
bond, lctter of credit or other form of security that is mso~bty acceptabk to
Transmissio=! Provider and is consistent with the Uniform Commercial Code of
thcjurisdictian idcatifred in Article 142.1. Suck Security for payment shall be in
an mmt sufficient to cover the costs for constructing, procuring and installing
the appIicablc portion of 'lransmission Provider's Tnterconncction Facilities,
Nehvork Eppdw, or Distribution Upgrades and shall be reduced on a doIlar-fordollar
basis fur ppr-sltu made to Traiimission ,Provider for these purposes.
II.S.1
11.5.2
h addition:
The gmantee must be made by an entity that meets the
creditworthha requirements of Transmission Provider, and contain
terms and conditions that -lee payment of any amount that may
be due from Interconnetxion Chstomer, up tu an agreed-to maximum
amount.
The 1ette.r ofcredit mustbe issued by a financial institution
reasonably acceptable to Transmission Providcr and must spccify a
reasonable expiration date.

Exhibit TAM
Page 59of 1 IO
1153 The sufety bond must be isslled by an insurer reasonably acceptable
to Transmission provider and must specify a reasonable expiration
date.
11.6 Irrtercomecfion Customer Compensation. If Transmission Provider reqwsts
or directs IntercennectIon Customer to provide a senice pursuant to Articics 9.6.3
(Payment fur Reactive Power), or 3.5.1 of this LGTA, Tmnsrnission Provider
shaII compensate Interconnedtion Customer in accordance wirh Interconnection
Customer's applicable rate schedule then in effect d e s de provision of such
service@) is subject to an RTO or E30 bTR€-appmved rate schedule.
Inteicomrection Customer shall, serve Tmmission Provider dr RTO or IS0 with
any filing of a proposed rate.scWule at the time of such lifing with FEW. To the
extent that no rate schedule is in eff& at he time the Intercormectim Customer is
required to providc or absorb any bctive Power mdcr this LGL4, T~msmkbn
hider agrees to compzrmte Intmconnection Customer in such mount as would
have been due interconnection Customer had the rate schedule been in effect at the
time service commenced; provided, however, that such mte scheduk must be filed
at FERC or other appropriate Govemmtntal Authority within sixty (60) Calendar
Days of the cmmmcemc=nt of service.
1.1-6.1 Interconnection Customer Compensation for Acibns During
Emergency Condition. Trammission Provider or W O ar IS0 shalI
compensate Tnterconnection Customer for its provision of real and
reactive power and other Emergency Condition &ices h t
Tntcrcunncction Customer provides to support the 'l'ransmission
System dwkg an Emergency Condition in accordance with Articlc
11.6.
Article 12. Invoice
El General. Each Party shall submit to the other Party, on a monthly basis, iniroices
of a m o due ~ for the preceding month. Each invoice shdl state the munth to which the
invoice applies and fully describe the SeTyices and quipmat provided. The Parties may
discharge mutual debts and papent obligations due ad owkg to each other on the same
date thro@ ntmg, in which case all momts a Party owes to thc other YarQ under this
LGLA, including interest paymmts or credits, shall be netred so that only the net amount
rema+ due shall be paid by the owing Party.
122 Final lhvaice. Within six morrths after completion of the cmstruction of
Trnnsmission ProvidetJs Intermmcction Facilities and thc Ketwork Upgndes,
Transrnissian Providcr shall provide an invoice of the final cost of the c on~tion
5I
l13

Exhibit TAG4
Page60of1lO
of Transmission Provider's htm6mection Facilities and the Network Upgrades
and shall set forth such COB in ficient detail to enable Iterconnection
Customcr to compare the actual costs wi& the estimates mil to ascertain
deviations, if any, from the cost &maws. Transmission Provider shall refund to
Interconnection Customer any amount by which the actual papmt by
hrcorm~on Customer for estimated costs a d s the aetuaI costs of
construction within thirty (330) Calendar Days of the issuance of such f d
COE3mdOIl hVQke.
-
123 Payment. Invoices shall be rendered to the psying Party at the address specified
in Ap- F. The Pary receiving the invoice shall pay thc hoke m%hh~ thirty
(30) Calendar Days ofreceipt. All payments shall be made in immediately
available fds payable to the other Party., or by wire transfer to a bank named and
account desiptd by the invoicing Party. Payment of invoices by either Party
will not constitute a waiver of my rights or claims either Party may have under
this EGIA.
12-4 Disputes. In the event of a billing dispute between Transmission Provider and
Intcrconuection Customer, Transmission Proeder shall continue to provide
htmmncctian Service untltr this- LGJA as long as Tnterconnectim Customer: {i)
conttinues ta d e all pqmcnts not in dispute; and (ii) pays to TranSmiSsion
Provider or into an independent escrow account the portion of the irlvojce in
dispute, pending resolution of such dispute. If kkrcmcction Customer fails to
meet hse ~ Vruquiremmts O for continuation of servicc, then Transmission
Provider may pmvide wticc to Tnterconncdon Cusiomer of a Defmlt pursmnt to
Article 17. Within thiw (30) Calendar hys &cr tbc rcuo~u~on of the dispute,
the Party that ows money to the other Party shall pay the mount
With
interest calculated in accord whh he methodolog set forth in FERC's regutations
at 15 CFR $ 35.19ga)(2){iii]-
Article 13. Emergencies
13.1 Definition. "Emergency Condition" SW mean a condition or situation: (i) &at in
the judgment of the Party making the claim is imminently likely to endanger life or
property; or (ii] that, in the case ot'Tmmission Provider, is irnmintntly lhIy (as
determined in a nondiscriminatory manner) to caw a matmid advcrsc efht on the
smdy of, or damage to the Transmission System, Transmission Provider's
IntMconneetion Facilities or the Transmission Sysams of others to which the
Transmission System is dircctly connected; or (iii) that, in the case of Intercomwtion
Customer, is imminently likely {as dcknnincd in a um-dkcr~natmy manner) to came
a material adverse &ect on the securiT of, or damage tu, the Large Generating Facilitgr
52
-134

Exhibit TAG4
Page 61 of 110
or Interconnection Customer's Interconnection Facilities' System ~ st~mti~n and black
start shall be considered Emergenq Conditions; provided,
is not obiigated by this LGIA to possess black start capabiliv.
Intercu&ori Customer
13.2 Obligations. F A Party shaI1 comply witb the Fmergency Condidon procedures
of the applicable ISOIRTO, NERC, thc Applicable Reliability Council, Applicable
Laws and Regulations, and any emer~pncy prccedures amto by the Soh
Operating Committee.
13.3
I
Kutice. Transmission Provider shalI notify Interconnection Customer promptly
when it becomes aware of an Emergency Condition that affects Transmission
Provider's Inkrcomeection Facfities or thc Transmission System that may
reasonably be expected to affect lntermnnection Customds operation of &e
Targe Generatifig Facility or Interconnection Customer's hkrconneciion
Facilities. Interconnection Custornw shall notify Transmission Mvidcr promptfy
whm it becomes aware of an Emergency Condition that dkcts the Large
Generating Facility or Intercomdon Customer's Inmrmnection Facilities tplat
may reasonably be expected YO affect the Transmission System or Transmission
hovidcr's Interconnection Facilities. To the cxtem informadon is known, the
notification shall dcjcribe the Emcrgmcq' Condition, the exlent of the damage or
deficiency, the expccted effect on the operation of IrYterconnection Customer's or
Transmission frovidds facilities md opmtions, its anticipated duration and the
corrective action taken dor to be taken. The kitial notice shall be followed as
soon as p.mdcable with written notice.
13.4 Immediate Action. Unless, in htercomection Customcis reasonable jud-ent,
immediate action is required, htcrconnectim Customer shall obtain the consent of
'I'ransmission Provider, such conxnt to not bc unreasonably tvithhcld, prior to
pdonnhg any manual switching operations at thc Large Gencratiag Facility or
Intmcomectiw Customer's hbconnecuon Facilities in response to an Emcrgcncy
Condition cithcr declarcd by Transmission Provider or otherwise regarding the
'f'ranmission System. '
13.5 Traamission Providcr Authority.
13.5.1 General. Transmission Provider may take whcver actions or inactions
with regard to the Tsansmission System or Transmission Frovidefs
Intmonnection Facilities it deems rxcessary during an Emergency
Condition in order to (i) prwerve public ReaIth and saffty,
(ii) prcscrve the rcliakdity of the Transmission System or
Tmmissicm Frobider's Interconnection Facilities, (5) limit or
. prevent damage, and (iv) elcpedire restoration of service.
53
-115

13.5.2
Exhibit TAG4
Page 62 of I 10
Transmission Provider shall use Reasonable Effwts tu minimize the
effect of such actions or inactionS on the Large Generalkg Facility
or Intercurneetian Custom& Tnkrcomcction Facilities.
Transmission Provider may, an the basis oftechnical considerations,
require the Large Generating FaciJity to mitigate an Emergency
Condition by taking actions necessary and limited in scope to
remedy the Emergency Condition, includmg, but not lided to,
directing htercomection Customer to shutdown, start-up, increase
or -e the rcal or Teactive power output ofthe Large Generating
Facility; implementkg a duction or disconnection pursuant to
Artick 13-52!; directing Interconnection Customer to askt with
blackshi (if available) or rcstOration efforts; or altering the outage
schedules of the Large Generating Facility and hterconncction
Customer's Intercomedon Faditis. Interndon Customer
&at1 compty ~tth aIl of Tmnsmission Provider's operating
instructions concerning Large Generatirag FxWy mi powa and
reactive power output within the manufacmfs desi@ iimications of
thc Large Genera- Facility's eqquipmenr that iS in sewice and
physicaIly avaiIable for operation at the time, in compiiance with
AppIicablt: 12% and Regulations.
Reduction and Disconnection. Transmission Provider may reduce
htuconnt~tivn Service or discsonnect the Large Genmthg Facility
or htexmnection Customefs Interconnection Facilities, whm ,such,
reduction or disconnection is necessary under Good trtility Practice
due to Emergency Conditions. These rights are separate and distinct
from any hght of curtailment of Tmrnission Provider pursuant tu
'tmmission Provider's Tariff. When 'hnmission Provider can
schedult the reduction or &conn&ion in advance, Transmission
Provider shall notify [nkrwmection Customer of &e reasom,
timing and exped duration of the redudon or disconnection.
Tmsmission Provider shall cmrdinate with Tntercormectiun
Customer using Good UtiIiV Practice to schedule the duction or
discomation during periods oflcast impact to Interconnection
Customer and Transmission Provider. Any reduction 3r
diucomcctiun Wl continue only fm so 10% as reasonably
necessaryunder Good Utility Practice. The Parties shdI cooperate
witb tmh other to restore the Targe Gzteralhg Facility, the
htcrconnection Faditics, and the Transmission System to the&
n o d opting state as soon stc practicabk consistent with &wd
Utility Practice.
54

Exhibit TAG4
Page 63 or 1 10
13.6 htmconnection Customer Authority- Consistent with Good Wirily Practice and
the LGIA and the L.GIF, Inlmmection Customw may take adom or hadons
with re@ to tk Large Generating Fdty or Intercoanection C~stomeis
Interconnection Facilitis during an Emergency Condition in order to (i) preserve
p&lic health and safety, {ii) presenw the mliability of the Tage Generathg
FaciSty or Tnterconnection Customer's interconnection Facilities, (E) limit or
przvent damage, and (iv) expedite restoration of service. Interconnection
Customer shdl use Reastlnable Efforts to minimize the &ct of such actions of
inaCti~n~ on thc Transmission System and Transmission Provider's
Inberconncction Fditics. Tmsmissian Provider shall use Reasonable Efforh to
assist Interconnection Customer in such actions-
13.7 Limited Liability. Fxcept as othdse provided in Mcle 1 1.6.1 of llGs LGIA,
neither Party shall be liable to the other for any actioa it takcs in responding to an
Emergency Cundition $0 long as such actinn is made in g d faith and is
consistent with Good Utility Practice.
Articlc 14- Replatory Reqalremeats and Governing Law
14.1 Regulatory Requirements. Each Party's obIigations under this LGIA sRal1 be
subject to its receipt of any required approval or certiibte from one or more
Governmental Authorities in the form and substance satisfactory to the applying ParQ, or
thc Party making any required filings with, or providing noticxi to, such GovemmentaI
Aufhorities and the c,xpkation of my time period a.wociatcd herewith. Fach Party shall
in good f&th scck and use its Reasonable Efforts to obtain such othcr approvals. &Sing
in this LGM shall require Intermmcctim Customer tu take any action tha~ could mdt
in its inabiIity to obtain, or its loss of: ststus or exemptim under hc Feded Power Act,
the Public Utility Holding Company Act of 193 5, as amended, or the Public Utility
Kc~Iatury Policies Act of 1978,
143 Governing Law.
14.2.1 The vali~ty, interpretation and performance of this LGIA and each
of its provisions shall be govemed by &e laws of tkstate whm the
Point of Interconnection is locatcd, xithout regard to irs conflicts of
law principles.
14.2.2 This I.GW is subject to aI1 Appkable Laws and Regulations,
55

14.2.3
Article IS, Notices.
15.1
15.2
15.3
15.4
Exhibit TAG4
Pagc640f110
GensraL Unlcss otherwise provided in this LGL4, any notice, demand dr quest
fequked or permi#& to bc given by cithu Party to the other and any insfrummt
required or pitted to bc tcn- or dciivered by either Pa* in InrTiting to the
other shall Be effective when delivered and may be sa given, tendered or
delivered, by recognized national courier, or by depositing the m e with the
United States Postal Senrice wi& postage prepaid, for delivery by ccrlifizd or
registered mail, addrwscd to the Party, or personally delivered to the Party, at thc
address set out in Appcndix I?, Addmses fur IMivery of Notices and 3iIlings.
Either Party may change the notice information ix this LGIA by giving five (5)
Business Days writtcn notice prior tu the effective date of the change.
Billings and Payments. Billings and payments shall be sent to the addresses set
OUT in Appdix F.
Alternative Forms of Kotice. Any notice or requesl xquired or permiad IO be
given by e. Party to the other a d not requid by this Ageement to be given in
writing may be so given by telephone, facsimile or mail to the telephone numbers
md emad addressw sct out in Appcndix F.
Operations and Mahtentlncc Notice - Fhch Parly shall notify the othcr Party in
h h g of the identity of the perso;l(s) that il designates as the pint{s) of conact
with respect to the impkmentation of Artkles 9 and 10.
Article 16. Force hjcurc
16.1 Force Majeure.
56

Exhibit T AW
Page 65 of 110
16-1.1 - Economic hards&p is not considered a Force Majeure event.
16.1.2 Neither &dl bc considaed to be in Default with respect to any
obiigation hereunder, (including obligations der Article 41, ather
than de obligation to pay money when due, ifprevented from
fulf111ing such obligation by Force ihiajeure. A Party unabfc to W
my obligation hereunder (othcr than an obligdm to pay money
when due) by reason of Forcc Majeure shall give noti& and the full
pnrticulars of such Force Majeure to &e oiher Party in writing or by
telephone as soon as reasonably possible after the o c m m of the
cause relied upon. Talephone notices given pursuant to this article
shall be confirmed in &ling as m n as reasonably possible and
shalI spcc~cdly state full particulars of the Force -jam, the timc
and date when the Force Majeure d and when the Force
Majeure is mombIy expected to cease. The Party affected shall
exercise due diligence to remove such disolbiIity with reasonabk
dispatch, but shall not k required to accede or agree to any
provision not satisfactory to it in order to d e and terminate a strike
or other labor distmbancc.
Article 17. Defslsllt
17.1 Default
€7-1.1 General No Dehlt shall exist where such failure UJ discharge an
obligatiun (other &an the payment of money) is the msult ofForce
Majeure as drfmd in this LGIA or the result of an act of omission
ofthe ohcr Party. Upon a Brcach, the non-breaching Party shall
give Written notice of such Breach to the breaching PEIZ~. Except as
provided in Article 17.1.2, rhe breac'ning P q shall have thirty (30)
Calmdar Days from rcceipt of the Defadl nolice within whkh to .
cure such Breach; provided however, if such Bmch is not apable
of cure witbin thirty (3 0) Catendar Days, the breaching Party shall
comm~lce such cure within tfiirty (30) Calendar Days after notice
and continuowXy and diligently complete such cure within ninety
(90) Calendar Days from receipt of &e D&lt Mice, and, if d
within such time, the Breach specified in such notice shall cease ta
exist
57

Fihibit TAG4
Page66ofllO
17~1.2 Right to Terminate. If a Breach is nut cured as provided in his
article, or if a Breach is not capable of being cured within the p c ~ M
provided for herein, thc non-breaching Farty &a11 Rave the rigk to
declare a Default and terminate this LGL4 by Written notice at any
time UntiI cure occurs, and be relieved of any fkther obligation
hereunder and, wheher or not tha~ Party terminates this LGIA, to
rccuvc~ bm the breaching Party all amounts due hereunder, plus ail
other damages and remedies to which it is enlitled at law or in
equity, The provisions of this artidt will survive termination of this
LGm.
18.1 Indemnity. The.Pades shall at all times indemnify, defend, and hold the other
Paty harmless from, any and aI1 damages, losses, claims, including claims and
actions relating to injury to or dmtb of any person. or damage to prcpxty> demmd,
suits, recoverks, costs and expenses, court costs, attorney fees, and dl other
obligations by or to third _&es, arising out of or resulting from thc othcr Party's
action ur inactions of it5 obligations under thjs 1,GlA on behalf af he
Indemnifying Party, except
'by the indenmifled Party.
cases of goss negligence or intenthnal wrongdoing
18.1.1 Indemnified Person. If En Indemnified Pcrson is entitled to
indemnification under this Article 18 as a result of a claim by B third
party% and the Indemnifying Party fails, afwr notice and reasonable
opportunily to proceed mder .k&le 18.1, lo assume the defensr: of
such claim, such Xndaificd Person may ar he expense of the
Indemmfying Party cont~ settIe cr consent 10 the entry of aq
judgment with mpcct to, or pay in MI, such cleim.
. lS.1.2 lndemnQing Party. Kan Indemdfyin,p Parp is obIigated to
indemnify and hold any Inderrinified Person harmless under this
Article 18, &e mount owing to thc Indemnified ferson MI be thc
mount of such Indemnified Person's actual Loss, net of any
insurance or other recovery.
18-13 Tndcmnity Prmdures. PromptIy afterreceipt by an IndemnZcd
Person of any claim or natice of thc cuwencment of any action or
administrative or legal proceeding or invesrigation as to which Ihc
indemnity providcd for in Mcle 18. I may apply, the Indemnified
Person shall now the Indemnifying Pmy of such fact. Any failure
58

182
Exhibit TAG4
Pagc67of110
of or delay in such notS40n shall not affect a Party3
ind&ficakn obIigatiun unless such fail- or delay is materially
prejudicial to TIK Indemnifying Party.
The Indemnifying Party shall have the right to assume the defense
thmf with counsel designated by such Indemnifying Party and
reasonably satisfkctory to the Indemnified Person. If the defmdanu
in any such action include me or more IndehfEd Persons and the
Indundying and if the hdemifred Perm reasonably
concludes thxt there may bc lc@ defenses available to it andlor
other Indemd2e.d Persons which are different from or additional to
those available to the kiddying Party, the IndmmZtd Person
shalI have thc right to sekt separate counsel to assm such legal
defenses and to atberwise participate in the defense nf .such adon on
its om bebalf. Tn such instances, the hdemnifylng Party SUI only
bc required to pay &e fces andexpenses of om additional attorney
to repraerrt an Indemnificxl Person or Indemnified Persons having
such differing or additional legal defmscs.
The lndernnified Person shaU bc wtitlcd, at its expcrasc, to
participate in any such action, suit or proceechg, the defcnse of
whick has bem assumed by the hdmifyhg Party.
Ndwitkstanding the foregoing, W Indemnifying Party (i) shall not
bc entitled to assumc and control thc dcfcnsc of any such action, suit
or proceedings if and to the merit that in the opinion of the
hdmmified Person and its counsel, such actiozl, suit or proceeding
involva the patatid &position of criminal liability on the
Indemnified Person, or there exists a conflict OT adversi5 of interest
be.hvetn the Indemnified Person and the Indtmnifying Party, h such
evmt the Indemnifying Party shall pay the reasonable cxpenses of
he Indemnified Person, and (ii) sM1 not settIe or consent to the
entry of any judpcnt in any action, suit or pm~ccding
without the
consent oflhc lndemslificd Person, which shall not be msmabIy
whhheld, condition& or delayed.
Consequential Damages. Other than the Liquidated Wages heretufore
described, in no event shall either Party be liable mder any provision of this LGlA
for any losses, damagcs, costs ore,xpcma for my special, indirect, incidental,
consequential, or punitive damages? including but not limited to loss of profit or
revenue, loss of the use oT equipment, cost of capital, cost of temporary equipment
or services, w %ek b d in whole or i? part in contract, in tort, including
negligence, strict liability, or any other theoxy o€ liability; provided, however, that
59

Exhibit TAG4
Page 68 of 1 IO
damages for which a garty may be liabIe to the other Party der anoher
agreenent will not be considered to be specid, in- incidcntat or
consequmtid damp heremer.
18.3 Xnsumnce- Each party shall, at its own expense, mahain in force throughout the
period of &is LGL+ md until released by the other Parly, the follo-rving minimum
-- inSmmcc covemges, with insurers authorized to do business h the state where the
Point of Inttrconnectiofi is located
183.2
18.3.3
183.4
1835
Commercial General Liability Insurance inchding premises and
opations, personal injury, broad farm prom darntlgc, broad form
hl&t cantractual liability coverage (indudins coverage for thc
cwtracttd indemnificntion) products and completed operations
coverage, coverage for explosim, collapse and underground hazards,
indeAncndent co~tractors coverage, coverage far poilution to the
extent normally available and punitive damages to the emat
nomaliy available and a cross liability endorsement with minir;lum
limits of One Million llollars ($1,OUU,OOO) per ocxurrmcel0ne
Million Dolh ($1,000,000) aggregate combined single limit for
personal injuy, body injury, including death and property damage.
Comprehensive AutomobiIe LiabiUty lnsruance for covmgc of
ow& and non-owned and hired vehicles, trailers or semi-milen
desipcd for hvcl on public marly with a minimum, combined
single limit of &e Million Dollsrs f%l,OOO,OOO) per occwc$x1ce for
bodily injury, includiq death, and p rom damage.
Excess Public Liabihty Insurance wer and above the Employm’
Lkdbihty Commercial General Liability and Comprehensive
Automobile LiabiIity Insurance coverage, with a minimum
combined single limit of Twenty Million Dollars ($20,OOO,WO) per
o c c m w m Million ~ Dollars ($20,000,000) aggregate.
The Co&ercial Generat Liabitiv Iwmce, Comprehensive
Automobile kmrame and Excess Public Liability Insurmx policies
shall name the othm Pany, its parent, assaciatd and Affiliate
companies and thcir respective directors, officers, agents, S C ~ I S
60

ExhibitTAG-4
Pagc69ofllO -1 23
and mp10yee~ f"Other Prtrty Grot@') as additional insured. All
policies shall contain proviSiws whereby thc hsma waive dl
righls of subrogation in accordance with ftae pvkhns of this LGIA
against the, Other Party Group and Fovide thirty (30) Calndar Days
advance witten notice to the ofha Party Group pai~ to armiversq
date of cancellation or any materid change in coverage or condition.
The Capumchl Gmd Liability hsmcc, Comprchcnsive
Automobile Liability humcc and Excess Public Liability
Insurance policies shall conmin previsions that specify that the
policies are primary md shall apply to such extent ~vitlmut
consideration for otherpEcies separately carried and shall state that
each insured is pmided coverage as though a separate policy had
been issucd to each, cxccpt the insurer's liability &ail not be
increased beymd the amount for whkh the insurer would haw been
Liable had d y one insured been ccvered Each Party shaU bF:
rqmorrsibk for its rtspectivc deductibla or retentiom.
183.7 The Commercial Genera1 Liability hurancc, Comprehensive
Automobit LiabiIity Tnsurancc and Excess PubHc Liability
Insurance politics, if written on a claims Fm Made Basis. shd be
maintained in full force and effict for two (2) years after ternination
of this I,GIA, which coverage may k in the form of tail coverage or
extended reporting pcrid coverage: if agreed by the Parties.
18.3.8 The requimenh contaked hmin as to the types and limits of dl
insurance to be maintained by the Phes are not h~mded to and
shall not in any mafiner, limit or qualify the Iiabilitics and
obligations assumed by the Partics urldcr this LGIA
183.9 Within ten (1 0) days fdlowing execution of this LGIA, and as mn
as practicable &er thc end of each fiscal year or at the renewal of
the insurance policy and in any went within ninety (90) days
thereafter, each Fdy shall provide certification of all insurance
recpkd in this LGM, cx~mted by each insum or by an authorized
rfpKsenbtive of each insurer.
183.10 Nohvithstanding ~e foregoing, each Party may xelf-iasure tu meet
the d u m insurance qukmmts of 2Wiclcs 1 8.3.2 throyh
.
18.3.8 to the extent it maintains a self-insurance program; pvided
that, such Party's sex$& secured debt is mtcd at investinen1 grade or
better by Standard Bt Poor's and that its self-insurance pgram
*, .
61

183.11
Exhibit TAti-4
Page 70 of 1 IO
meets tbe mhinun insurance requirements of Rrticles 18.3.2
through 18.3.8. For any period of the that a Pws ,wbr smd
debt is unrated by stai3dard & Pods or is mtcd at tesLc than
hvatment grade by Standard & Poor's, such Party shall compIy
with. the insumme requirements applicable to it der Mcles 18.3.2
thrulrgh 183.9. In the event hat aP- is permittad to self-insure
pursuant to this dele, it shalL notify the other FW that it meets the
requirements to self-insure and ?hat its self-iasmnce program meets
the minimum jnsurance requkements in a manraer consistent with
tbat specfied in Article 18.3.9.
The fades agm to report to ach other in writing as soon as
prwtical d accidents or mcumnces resulting in injuries to my
person, including &a& and any prqxrty damage arising out of this
LGIA.
19.1 Assignment. 'l'his ffiU may k assigned by either Party only wiih the wrhten
consent of &e other, provided that either Party may assign this LGTA without the
consent of the other Parry to any Affiziate of the assigning Party with an qual or
greater credit rating and with the legal authorily and opmtional ability to saris@
the obligations of the assigning Party under &is LGIA; and provided firher that
Irrtercomection Cwomcr shall have IRc right to assign this T,GIAt without the
consent of Transmission Provider, for cohtaal scmi~y pnrpses to aid in
providing fmancing €01 the large Generating Facility, provided tht
htexomedon Customer will promptly notify Transmission Provider or any such
assignment. Any financing arrangement entered into by Interconnection Customer
pursuant to this article wil1 provide that prior to or upn the exercise of the secured
party's, fnrsfee's or mo@agee*a assignment rights pursuant to said arrangemat,
&e secured creditor, &e lm~stcc or mortgage will notify Transmission Provider of
the date and particulars of any such exuck of assignment rightls). including
providing the Transmission Provider with prooflhat it meets the requkmmts of
Articles i 1.5 and 18.3. Any aEqted assignment that Violates this article is void
and ineffective. An? assignment under this LGU shall not relieve e Pwty of its
obligations, nor shall a PWs obligations be enlarged. in whole or in part, by
reason thereof. Wh~m required. consenf to assignment will not k unreasonably
withbdd, conditioned or delayed.
Article 20. Severabdiq
.. ,. .
62

Exhibit TAG4
Page 71 of 110
20.1 Swmddity. lfauy provision in this LGIA is fd1y determined to lx invalid,
void or uncnforccabIc by any court or 0th- Gwvemnmld Authority having
jurisdiction, such &ermWon Wl not invalid&@, void or W e unenforceable
any other provisiorr, agrement or wemt of this I ,GW, provided that if
hterainnection Custorna (or any third party, but only if such third pariy is not
acting at the direction of TmmnissioaPmvider) se& and obtains such a fd
dctermiaation with mpt tQ any provkion of the Alternate @tior* (Mcb 5-12),
or the Negotiated Option (&lick 5.1 A), then none of .these provisions shall
therafter have my force of effect and the Parties' rights and obligations shall be
governed solely by the Standard Option (A.rSicle 5.1.11.
Article 21. Compa-mbi€ity
Article 22. Confidentiality
22.1 Confidentiality. ConfidentiaJ. Momation shall include, without timitation, aI1
information reladng to a PEtrty's tecbnoiow, march and development, business
affairs, md pricing, and my information supplied by either of &e Parties to the
other prior to the exemtiun of lEs LGIA.
infomation is Cddential Infarmation only if ir is clearly designated or marked
in wrihg as confidmtia1 on the face of the dment, or, if the hfmnation b
conveyed odly or by inspection, Ethe Party providmg he information onzIy
informs the Party receiving the information that the information is ~onfidentid.
If requested by either Pasty, the otha Party &AI provide ia wiling, tbe basis for
asserting that the infomation referred to in this Article 22 w m t 5 codi&tntiai
b-eaiment, and the requesting Party may discIos@ such &ting to thc apprupfiate
Govemmwd Authunty. Each Party W be mpnsibk for the costs associated
with zdfording confidential &mmt to its information.
22.1.1 Term. During h e tezm of this LGIA, aad for a p&d of three (3)
years afm the expiration or termination of this LGL4, except as
otherwise provided in this Artick 23, each Party shall hold in
confidence and shaII not disclosc to any person Confidenrial
Information.
63

22.13
Exhibit TAG4
Page R d l
IO

-.:,:
22.1.5
22.1.6
22.1.7
Exhibit TAG4
Page 73 of I 10
NO Warranties- By providing Confidential Information, neither
Prty makw any wananties nr representations as to its x mcy or
completeness. In addition, by supplying Confidentid Information,
neither Party obligates itself to provide any particular information or
Confidential Mmtim to hc other Party nor to enter into any
further agreements or proceed with my other relationship or joint
Venture.
Standard of Cam- Each Party shall use at least the same smdard
of care to protect Confidential Information it receives as it uses to
protect.ib own Confrdmtial Infomuition h m unauthorized
disdustm, publication or dissemination. Each Party may flse
Confidential Infomation soMy to fuzfill its obligations to the other
Paw under this LGIA or its regulatory requifiments.
Order of D~sclosure. If I court or a Government Authority or entiv
with the right, power, Kd apparent authority to do so quests or
requircs either yarty, by subpoena, urd deposition, intamgator&
requcsts for p~ikti~~i of docurncnts, adminisrrative order, or
otherwise, to disiose Confidential Infomatibn, that Party shall
provide the other Party with prompt notice of such requcst(s) or
requirement@) SQ thar the other Partjr may scck an appropriate
protective order or waive comptiance withthe terms of this 1,I;XA.
Notwitbstmding h abmnce of a protective order or waiver. tke
P q may disclose such ConEdcntial information whkk in the
opinion of its counsel, the Party is legally compelled to disclose.
Each Party will use ReassonabIe Effom to obtain reliable ~ssurance
h t cunfidmtial treatment will be zccorded m y Confidential
Information so furnished.
22.1.8 Termination of Agreemcnt. Upon termination of this LQIA for
my man, each Party shall, within ten (10) CaIdar Days OF
receipt of a written request froln thc other Party? use Reasonab!c
Effom to destroy, erase, or &lek (with such destruction, erasure,
and ddetion certified in writing to the other Party) or return to the
other Party, without retaining copies thereof, any and all witten or
electronic ConCidentiaI Information received h the othcr Party.
22.1.9 Hcmedies. The Parties agree that monetary damages wdd be
inadequate to compwate a Pmy fox the o h PastJl's Brcach cf its
obzigations under this Arricle 22. E&h Party mcordingIy agrees that
65

.- . :'. .-
.
Exhibit TAG4
Pase 74 of 1 IO
the other Party shall bc enticled io equitable relief, by way of
injunction or otherwise, Xtbc first Pblrly Breaches orthreertms to
Breach its obIigatims under this Article 22, which equitabIe relief
shall be granted without bond M proofofdimages, and the receiving
Party shall not pIead h defense tbat there w~uld k. an adequate
remedy at law. Such rmdy shall not Be deemed an exclusive
remedy for the Breach ofthis ArticIe 22, but shall be in addition to
d odm remedies avvaihble at law or in equhy. The Parties fiuthcr
acknowledge and agm that the covenants CORM herein arc
necessary for &e protection of legitimate business interests and are
reasonable in scope. Nc Party, however, shall be liable for indirect,
kidend, or cornsequential or punitive damages of my nature or
kind resulting from or arkhg in c~nnacCion witb this Article 22.
22.1.10 Disclosure to FERC, its Staff, or a State. Notwithstandixlg
anything in this Article 22 to the contrary, andpursuant to 18 CFR
section lb.20, if or its staff, during the course ofan
investigation or otherwise, quests information horn one of the
Parks that is othcmisc l-cquiredto bc maintained in confidence
pursuant lo this LGTA, thc ParQ shall pvidc &e requested
information to FERC or its mff, within the time pmvided for in the
request for inforimtion. h providixg the information to FERC or its
stafF, the Party must, cons'istent with 18 CFR section 388.1 22,
requcst that the informaGon be Wted as confidential and non-public
by FEKC and its staff and thal the infomation tx withheld from
public disclosure. Partis are probibit& from notifjing he 0th~~
Party to this I ,GL% prior to the release of the Con6ddaL
Momation to FERC or its &. The P w shall notify the other
Party to the LGIA when it is notified by FERC or its stafT that a
request to release cflnfidential information has been received by
ff,RC, at which time either of the Parties may mpd WOE such
information would be made public, pursuant to 18 CFR section
388.1 12. Rcquwh from a state reaplatow body conducting a
confidential iavestigation shall Be treated in a similm mcr if
consistent with the appfimbk shtc rules and ~gulahons.
221.11 Subject to the exception in Article 22-1.10, aay infm~on that a
Pay claim is comp&tivcly sensitive, commercid or financial
infwmation under this LGIA ("Corfdential Informationl') shall not
be disclosed by the other Parly to my person not employed or
retained by he other Party, except m the exfmt disclosure is (i]
required by law; (ii} rwmbly deemed by the disclosing Party to bc ,
66

c .
Exhibit TAG4
Page 75 of 1 10
requird to be disclosed in connection with a disputr: between or
among fhe Pdes, or the defense of litigation or dispute; (iii) ,
otherwik pcrmitkd by consent of the other Party, such coflsent not
tu be u~easonably withhcI& or (iv) nmssary to fuEilI its
obligations der this LGIh or as a Irammss ’ ion service provider or
a Control Area operator including disclosing the Codidential
Idonnation to an RTO or IS0 or to a Tegional or national reliability
mganimtion. The P w asserting co&dmtkdity shaIl notify the
other Party in writing sf t!x information it claims is canfidential.
Prior to any discbsures ofthe o k Paq‘s Confidential Information
under this subparagraph, or if any third party or Gcvernmentd
Authority makes my request or demand for any oftfie informslton
dmdxcl h this subpamgmph, the discfosing Party a’grecs to
promptly notify thc other Party in writing and agrees toassert
confidentiality and w-e with the other.Parp in seeking 10
protect the Confidential Information fmmpublic disclosure by
confidentiality a m a t , profdve order or other reasonable
mmm.
Article 23. Environmental Heleases
23,1 Each Parry shall notify the other PWy, first orally and then in writing, of the
reieasc of any bardous Substances, my as&= or lead abatement activities, or
my typc of remcdiatian actbitis relzikd to !he Large Gencrathg Facility or the
I~~~onrr~~ioTI.E’acifitits, each of which may reasonably he expected to afTect &e
othci Party. The notifying Party shall: (i) provide the notice as soon as
pncticablt, provided such Party makes a good faith cflort to provide the notice nu
Iatm than twenty-four hours after such Party bscomw awarc of the occurrence;
and (ii) promptly furnish to the other Party copies of any publicly available rcporrs
fded with any Gcmmrnental Authorities addressing such events.
Article 24, Information Requirements
24.1 Tnrormation Acquisition. Tmsmhsion Provider.and htercomcc-tion Customer
shall submit specific information rcgarding the electrical chmctaistics of their
respective facilitics to wch other as desmi below and in accordace with
Applicable Reliabiliq Standards.
67

ExhibitTAG-4
Page 76 of 1 IO
243 Information Submission by Transmission Provider. The initial information
submission by Transmission I'rovider sMi OCCUT no later tban OM: hundred eighty
(1 SO) Calendar Days prior to Trial Operation and shall inch&. Tm&ion
Sysmn btfomation necessary to allow Imcrcameaion Cusbmer to select
equipment and meet any sysm protection andmbility requirements, des otherwise agreed to by the Parties. On a monthly his Transmission Providcr
shdI pvidc Interconnection Customa a status ~yxt LRI the cowction and
- installation of Transmission Provider's Intercomation Facilities and Network
Upgrades, including, but not limited to, fie following information: (1) ~acoigress to
date, (2) a description of the activilies she the last report (3). a description of the
action items for the next @a& and (4) the delivery status of equipment ordered.
243 Updated Information Submision by Xntercomction Customer. The upinfomation
submission by InterCt>nrrer;tion Customer, inchdins ~ ~ r e r
irhmatioq shall occur no lam than one hundred eighty (1 80) Calendar Days
prior to the Trial Opemtion. Interconnection Customer shall submit a compIeted
copy of thc Large Generating Facility dm requkments contained in Appendix 1
to L!X LGP. it shali also include any addhional infmnation provided to
Tmsmission Provider for the Feasibility and Facilities Study. Infomation in tbjs
submission shall be the most current Large Generating Faciiity design or expcctcd
pcrfonnance daw Information submitted for stability models Ml be mmptibk
with Transmission Provider standad mod&. If there is no comptible model,
htemnnection CuSt0me.r wdI work wi~ a codtmt mutually aged to by the
Partic5 to develop and supply a standard mode1 md associated infomation.
Wntercomection Custimcfs data is materially ciiHmcnt fmmwhat was originally
providcd to Transmission Provider pursuant to the htercomection Study
Agtxti?cnt between Trammission Provider and Tntcrcomection Customer, then
Tramissiion Provider will conduct appropriate studies to determine the impact on
Transmission Provider Transmission System bad on the actual dsta submitted
pursuant to this Article 24.3. The Intt~~~~e~tion Customer shall not besin Trial
Qmation until such studies are compkted.
24.4 hformnrioa Supplementation. Prior to the Operation Date, the Parlies shall
. suppianent their idbrtmtion submissioi~~ described abw in this Arride 24 widt
any and all "asbuilt" Large Generating FacciIity Xomtbn m "as-tested"
Ferfomance 'information that differs fin the initid submissium or, altemtivdy,
written cobation that ho mch dflermces exist. The Interconnection Customer
shahal conduct tw& on thc I,qe Gcnerathg Facility as required by Good Utility
Practice such as an open circuit "step voltage" test on the Large Generating
68

:.9
. ExhibitTAG-4
Page 77 of 11 0
Facility to verify proper opedon ofthe Large Generating Facility's automatic
voltage regulator.
Udcss athcrwise agreed, the test conditions shall include: (1) Largc Gcnmhg
FaciliQ at synchronous s p e (2) tmtomatic voltage regulator on and h voltage
control mode; and (3) a five percent cbqe in Tage Generatkg Facility terminal
voltage initiated by a change in &e voltage re@a?os refcrcncc voltage.
. Interconnection Customer shall provide validated recordings showing the
respoms.of Large Generating Fxility terminal and field voltages. In the event
that direct recordings ofthese vukages is impractical, recordins of othcr voltages
or c-ts that mirror the response of the Large Generating Faciliw's tmninal or
. field voltage are acceptablu ifhfiurmation necessary to tranSlate thex altematc
qumtitia to actual Large Gcncra&g FacW tennhl or field vdtags is
provided. Large Generating*Fxility testing shall be conduc-tcd and results
provided to Transmission Provider for each hdividual generating unit h a station.
Article 25. Taformxtion Access and Audit Rights
25.1
25.2
Information Atcess. Each Party (the "discloskg Party") shall make- available to
the other Party infmnatim that is In the possession of th Ctisc~oosing Party and is
necessary ia order for thc other Fasty to: (i) veri5 the costs incurred by h
disclosing Parky for which the other Party is responsible mdcr this LGIA; and
(ii) c~trry out its obI&&ons and responsibilities under this 1,GLA. Thc Parties shall
not use such infomation for purposes other than those set forth in this Article 25.1
and to enforce their rights der this LGK
Reporting of Non-Force Majeure E~hts. Fsh Farty (the "notifirkg am")
shall notify the other Party when the notifying kcomes awme of its inability
to camp$* with the provisions of tkis 1,GIA for a mson o k than a Force
Majeure event. The 'Parties agree to cooperate with each otIier and provide
necess~uy infomatbn regarding such inaldity to comply, includingthe dale,
, . . .
69

:..a:. ..
.,. ' . .
-
E.uhibitTAG-4
Page 78 of 110
durarion, r~ason for the inaBility to comply, and conative acrionS taken or
planned to bc taken with respect to such inabili& to comply. Noiwitfistanding the
foregoing, notification, roopernth or idodon provided under this aXticle sbll
not entitle the Par& receiving such norificatioh tu allcge o cause €or anticipatorybrcach
of this LGLA.
253 Andit Rights. Subject to he requirements of cdidentiality der Article 22 of
this LGIA, each Party shall have the right, during mrmal business 3om, and upon
prior reasonabk notice to the other Party, to mdit ELI its own expense the other
I3u-p'~ accounts and recards prhiningto either Pws performance oreither
Party's satisfaction of obligations this LGEA. Such audit rights shall include
audiu o€ the ather Party's cam, EaIculation ofkvohd amounts, Transmission
hvidefs efforts to docatc responsibility for the provision of reactive support to
the Transmission Systrm, 'd'ransmission Provider's e€€- to allocate respmibiIity
for interruption or reduction of generation on the Transmission System, and each
Parry's actions in an Emcrgcacy Condition. Any audit authorhxd by this artidle
shall be performed at the offices where such accounts and records are maintained
and shall be limited to those portions of such accounts and records that reiate to
each Party's -performance and satbfactiorr ofobligations wder this L a . Each
Party shall kccp such accomts and records for a perid cquivdant to the audit
rights periods described m hrtide 25.4.
25.1 Audit Ri@h Periods.
25.41 ' Audit Rights Period for Const,mctionTRcIntcd Accounts and
Records. Accounts and records related to the design. engineering,
pracurement, and consrmction of Trmsms ' sion Pm~kiefs
Tnkrconncctlon Facilities and Network Upgrades shall be subject to
audit for a pCriod of twenty four months hllowhg Transmission
Provider's issuance of a final invoice in accordance with Article
12.2.
254.2 Audit Riehts Period €or AI1 Other Acconnts and Records.
Accounts and records related to CitkPrirty's pfomancc or
satisfaction of all obIi,@iom under this LGN other than those
described in Article 25.4.1 shall be subject to audit as follows: (i)
for an audit relating to cost qbligakns, the applicable audit rights
period shall be twenty-four months after the auditing Party's receipt
of an invoice giving rise to such cost obligations; and (ii} for an audit
mlating to all other obligations, thc applicable audit rights period
shall be twentyfour months aRer the event for which the audit is
SOU&.
70

Exhibit ‘I‘AG-4
Page 79 of 110
25.5 Andit Results. If an audit by a Party determines that an overpayment or an
underpayment has occurred, a notice of such overpayment CT underpayment M 1
be given to the other pafty together with those records from the audit whjch
support such determination.
Article 25. Subcontractors
26.1
26.2
263
GeneraL Kothing in this LGIA shall prevent a Party fmm utilizing the services nf
any subcontractor as it deems appropriate to perform as obligitbns under this
LGlA; provided, however; that each Party ShaH quire its sukontractors to
comply with all applicable terms ancl conditions of this LGIA in providhg such
services and each Party shaIl remain primarily iiabk to the other Party far the
performanee of such subcr>ntractor.
Rcsrpnsibiity of PrincipL The d o n ofany subcontract tel~onship shall
not relieve the hirig P q of any of its obliptim under this LGW. The hiring
Party sMl be fully responsible to &e other Party for the acts OT omissions o€my
subcon~ur the hiring Party hires as if no subcontract had ken made; pmvid,
homer, that in no evm~ s?dl Transmission Provider be liable for the actions.or
inactions of ktercumection Custornw or its su~ntra~tors with rcspcct to
obligations of Interconnection Customer under Article 5 of tbk LGIA. Any
applicable obligation impsed by this LGIA upon the hirhg Party shall be equally
binding upon, and shall be consnvcd as having qplicaticm to, any sukontrxtor of
such Party.
ffo Limitation by Insurance. The obligations under this Articte 26 will nof be
limited in any way by any limitation of subcorrtractor‘s insurance.
Article 27. Disputes
27.1 Submission. In the event either Part); has a dispuk, or asserts a c b , that arisw
out of or in connectiOn with Xis LGIA or its performance, such Paw (the
“disputing Party’) shall provide the other P w with Written notice of the dispute
or claim (“Notice of Dispute”). Such dispute or claim shall be referred to a
daigmkd senior ~present&ve of each Party for resolution on an Momal basis
as promptly as practicable &a receipt of she Noh of Dispute by the other Pafly.
In the event the designated reprcsmtdvcs arc unable to resolve the dah ar
dispute through unassisted or assisted negotiations within thh- (30) calendar
r

27.2
Exhibit TAG4
Page80oflIO
Days of the other Party's rec&pt of the Notice of Dispute, such cIaim or dispute
may, upon mutual agreement of thc Pad=, be submined tu subitration and
resoIved in accordancc with the arbiir&n procedures set forth khw. In the
everst the Parties do not agmc to submit such claim OT dispute to arbitration, each
Party may exercise whatever rights and remedies it may havc in qity or at law
consistent with tbe terms of this LGIA.
External ArhitFatioo l'rocednrm. Any arbitration initiated der this LGL4
W be conducted More a single ncubd arbhator appointed by lhc Parties. Jf
the Parties fail to agree upon a single arbitrator within tcn (1 0) Calendar Days of
the submission of the dispute to axbitralion, each ParQ shall choose one asbitrator .
who shall sit on a thrcc-mcmbcr arbitmion panet. The two arbimors so chm
MI within rwmv (20) Calendar Days select a third atbitrator to chair the
mMrarion panel. In either case, the ahhtors W be knowldgsable in electric
utility maaers, including electric mmnission and buIk pwer issues, and shall not
have any cumcnt or past substantial business or financial relahmhips with any
to the arbitration (except prim arbitration). The arbieator(s) shall provide
ach af the Pdes an opportwiry to be heard and, acqt as othe-ivrrise provided
herein, shall conduct the arbitration in accordancc with thc Commercial
Arbitrafon Rules of the American Arbitmtion Association ("Arbitration Rules")
and any applicable FERC rugulertions or RTO nr:cs; provided, however, in tfie
event of a conflict betvt-een de Arbitmtion Rdes and the m s of this Article 27,
the twms of this &tide 27 SlraIl prevail.
27.3 - - Arbitratiqm-&c,isions.
.___ -. U&ss o&&se agreed by the Parties, the arbitmto$s)
shdl render a decision within ria@ (90) CaIendar Day of appointment and shalI
notify the Parties in w&&g of such decision and tbe mons therefor. The
&itator(s) shall be authurkd only to hrexprcx and apply thc provisions of this
LMA and shall have RO power to modify ok change my provision ofthis
Agreement in any marrner. The decision of t!x arbitrafw(s) shall be final and
binding upon the Parties, and judgment on the award may be entered in any court
having jurisdiction. The decision of the mbitrator(s) may be appealed solely OG
de mmds that the conduct of the arbitratm(s>l cr the deFision itself, viohwt the
standards set forth in rk F d d Arbitration Act or the Administrative Dispute
Resolution Act. The fmaI decision ofthe arbitrator must alsQ be fdcd With FEXC
if it affects jurisdictional rates, terms and conditim ofservice, lrrterc~nncction
Facilities, or Network Upgrades.
27.4 Costs. Each Party shalt be qomible for its ORTI costs incurred during the
arbitration process and T m the folIowing costs, XappIicabb: (1) the cost of the
arbitrator choscn by thc Party to sit on the three member pncl and one half of the
72

.
Exhibit TAG4
Page 81 of 110
cost 6f the third arbitrator chosen; or (2) me half the east of the single arbitrator
jointIy chosen by the Parties.
23.1.1
28.1.2
28.1.3
Good Sbndmg. Such P q is duly organized, validly exishg and
in good standing under the laws of the state in which it is organized,
fomed, or h m ~ as applicable; ~ , that it is qualsed to do
business in the state or states in which the Large Gcncrating Facility,
htercomection Facilities and Nclwork Upgrades ow-& by such
Party, as appIkable, arc located; md that it has the corporate power
and author@ to o m its properties, to carry on its business as now
bekg conduct& and to enter into this LGIA and carry out the
wctions contemplated hereby and perfom and cany out all
covcnam and obligations on its part to be performed under and
purslaetnt to this T.GL4.
Authmily. Such Party has the right, power and a&wiq to enter
into this LGIA, to become a Party hereto and to perform its
obligations hereunder. This LGU is a legal, valid and bhding
ol$igatian of such Party, enforcable against such Party i,u
accordam with its [em, except as the edorceability thereofmay
be limited by applicable bnkmptcy, insolvency, reorgankahn or
other similar laws affecting creditcrs' rights generally and by gencral
equitable principles (regardess of whether drceability is sought
in a proceeding in equity or at law).
No Conflict. The execution, delivery and ptrfomance of this LGLA
docs not violate or conflict with the orgmizatiod or fornation
dot;uments, or bylaws or operating agreement, of such Party, or any
judgina license, permit, ordcr, material agmnm or instrument
applicable to or bidq upon such Party or any of i% assets.
28.1.4 Consent and Approval Such Party has sought or obtained, or, jn
accordance with phis IGLA will scek or obtain, each comt,
appzoval, authorization, order, or acceptance by my Governmental
Authority in co&ectioxl with the execution, rlelivq and
73

Exhibit T AW
Page 82 of I10
performance of this LGm, and it will provide to any Gwvemenrat
Authority notice of any actio= under this LGM that are required by
Applicabxe Iaws and RegulariOns.
Article 29. Joint Operating Committee
29.1 Joint Operating Committee. Except in he case a ISOS all1 UT&,
Transmission Provider shsrI1 cmstiGe a Joint Operating Committee to coordinate
operating and techuicd considerations of Intmmection Service. At least six (6)
months prior to the expected Initial Synchaon Date, IntcmMcction
Customer and Transmission Provider shall each stppoint one represen~ve and
om alternate to the Joint Opeming Committee. Each ktercomdon Customer
shall notify Transmission Provider of its appointmmt in k t h Such ~
apphments may be changed at any time by simiIar notice. The Joint Operating
Comrnittce shalI mcet as necessary, but not less than once each caIendar yeat, to
c;.xrry out the duties set forth herein. The Joint Opetating Committee shall hoId a
mccting at fie quest of either Pw, at a time and place aped upon by the
representatives. The Joint Operating CommittCc shall p d m aI1 a€ its ddes
consktd With the prWiSiOnS Of this LGM. Ench Party shall coopcrate in
providing to the hint Operating Committee all idormarim rtquired in the -
perforname of the Joint Operating Cornminee's duties. All decisions and
ageenens, if any: made by the Joint Operating Committee, shall be evidenced in
writing. The duties of rhe Joint Operating Committee shall incIudc the following:
. . . . .. . .
29.1.1 Establish data requirements and op-ating record requirements,
29.1.2
29-1-3
29S.4
d
Review the rcquircments, stmhds, a d procedm for data
acquisition equipment, protective equipment, and any other
equipment or software* .
hUly revisw the one ( 1) year forecast of maintenance and
planned outage schedules of T~mission Provider's wd
Interconnection Cushmds facilities at the Pnint af Interconnection.
Coardinate tke scheduling ofroaitltznance and planned outages on
the h1erconnection Facilities, the Large berating E'acdhy and
other facilities that impact the normal operation of the
intercOnnecCtion of the Large Generating Facility to the Transmission
System.
71

29.1.5
29.1.5
Article 30. -3lisckLIaneons
30.1
30.2
303
30.4
Exhibit TAG4
Page 83 of110
Enm that information is bei-ng provided by each Party regarding
equipment availability.
Perform such other duties as m y tx conferred upon it by mutual
agreemenr of the Parties.
Binding Effect. This LGU and the rights and obiigatiom k of, shall be binding
upon and shaaII inure to the benefit of the successors and assigns of the Parties
hereto.
Con€lictsi In the event of a conflict between the body of this LGU and any
attachment, appcmdiccs or exhibits hmto, the terms and provisions ofthe body of
this 1.GIA SML prevail and be deemed the final intent of the Pdes.
Rules of Interpretation. l'his Lcrl.4, unicss a cIcar contrary intention appears,
sM1 be construed and interpreted as follows: (I) the supla n m k includes the
plural n*mber and vice versa; (2) reference to my pcrson includes such person's
successors and assigns but. in the casc uf a Party, only if such successo~ and
assigns arc permitted hy this tGlA, and rcfcrencc to a person in a particular
capacity excludes such person in any other cap& or individually; (3) refererxe
to any agreement (including this LGU), document, instnrment or tariff means
such agrccmcnLdowcnG instnunmt, or tariff as amcndcd or mollified and in
effect hm time to time in accordance with the tmhs thereof and, if applicable,
the terms hereof; (4) referrmcu to any Applicable Law and Keguladons means
such Applicable Laws and ReguIations as amended, modified, codified, or
reenacred, ir! whole or in part, and in effect h m rime to he, including, if
applicable: des and regulations prurnulgtcd thcmmdcr; (5) unless exprmly
stated otherwise, reference to any &tick, Section or Appendix mans such Article
of &is T.CX.4 or such Appmdix to this LGIA, or such Section to the LGW or such
Appendix to the LGIP, as he case may be; (6) "hemmder", 'herear, "herein",
"hereto" and words of similar import shall be deemed references to this LGLA as a
whole and not to any particular Article or other provision hereof or thereof; (7)
"incllrding" (and with correlative rreaning "include") mas including withofit
limiting the gendiv of any description preceding such term; and (8) dative to
the determination of any pcrjod oftime, "frum" means "hm and inchding", 'to'
means %I but excluding" and ''through" means "through and including".
E~tirc: Agreement. 'This LGIA. including al Appmdiccs and Schcdulcs attached
keto, constitutes the entire agreement between the Pmies with reference to the
75

30.5
30.6
30.7
30.8
30.9
30.10
Exhibit TA G-4
Page 84 of 110
subjm ma- hereof, and supersedes aIl prior and contemporaneous
unaerstandqs or agreements, oral or w&en, between the Parties with rmpect m
the subject matter of this LGIA. There are no other agreements, rqmsmtations,
warmth, or cov&ants which condtute, any part of the consideration for, or any
condition to, either 'Party's compliance with its obligations under rhis LGIA.
- No Third Par@ Beneficiaries. This LGIA is not iutended to and doe, not
create
rights, remedies, or benefits of any charmer whboevm in favor of any persons,
corporations, associations, or entitics &cr than the Parties, and the obligations
herein assumed are solely for the use and benefit of the Parties, their succesmrs in
hkrwt and, where permitted, their assigns.
Waiver. The fahe of a Par& to this T,GU to insist, on any occasion, upon strict
performance of any provision ofthis LtiIA will not k considered a waiver of any
obIigtion, right, or d e of, or imposed upon, such Parry.
Any waivm at any h e Pry either Paq of its n&ts with respect to &his LGLA &all
not be deemed a continuing waiver M a waivcr with respt to my other failure to
comply with any other obligation, right, duty of this LGIA. Termination or
Default of this LGLA For any r@ason by htercomection Customer shall nor
com~tute a waiver of hterconnection Customer's legal rights to obtain an
kterconnection &om Transmission Provider. b y tt-aiver of this LGIA shall, if
requested, be provided in writing
Headings: T& d.pgiptive headings of the v&ous Articles of this LGM have
been inserted far convenience ofreference only and arc of no significance in thc
interpretation or constmaion of tbis LGTA.
Multiple Counterparts. This LGLA nay be executed in two or mort
counterparts, each of whicb is deemed an original but all constitute one and the
samc instrument
Amendment. fie Parties may by mutual agrement amend this LCJIA by a
written instrumtnt duly cxecutcd by the Padies.
Modification by the Parties. The Fan5es may by mutud agrccmmt amend the
Appendices to ~ LGIA by a w&tm iastnrment duly executed by the Parties.
Such ammdmmt shall bccumc cffec tive and a part of this LGlA U ~ Isaiisraciion I
of all Applicable Laws and Regulations.
30.11 Reservation of Rights. Transmission Provider shall have the right to make a
urdaterd filing with FFAC to modify this T,MA with respect to my rata, t m s
76

Exhibit TAG4
Page 85 of 110
and conditions, charges, classihanS of servicz, rule or regulation under section
205 or any other applicable provision of &e Fec€zral Power Act 2nd ERCs rules
and replations fiereundes, and Intercwnectirm Customer shall haw the right to
make a unilateral filing with FRRC tn modify this LGh pursuant to scctim 206 or
any other qpfiable provision of the Federal Power Act and FERC's des md
regulations themmdeq provided that each Pzrrty hlI have the right to protest any
such fihg by tbc 0tht.r Party and to p.rl;cip.te fully in any proceeding before
FERC in which such modifications may k considered. Nothing kt thisLGIA
shall hit the righ of the Pmties or ofFEICC under sections 205 or 206 of thc
Federal Power Act and F ER0 des and reguktiom dmeunder, except to the
extent that the Partics ohmvise mutually agree as provided herein.
30.12 No Parhership. This LGXG shaLI not be interpreted or construed to mate a*
miation, joint venture, agency reIationship, or menhip between the Parties
or to impose any p-h~~hip obligation or partnership liability upen either Partqr.
Neither P q &dlI have any @t, power or authority to enter into any agreement
or undertaking for, or act on W of, or to act as or be an a@ or representative
of, or to othmise bind, the other Party.
77
. _-.

Transmission Owner
Southwestern EIeWc Power Company
Intmnnection Customer
Southwestern Electrie Power Company
Exhibit TAG4
Page 86 of 1 IO
78
. ~
. .. *... .

Exhibit TAG 9
Page870f 110
Appendix A To Agreement
The facilities described in this Appendix are bmd on the studies conducted in rqmg to the
Tntercoweclion Rqucst, GFN-200B-010. In the event that other hrerconnection custolners
suspenrZ tzrmifiate or qu& unexecuted filing of their LGLAs, then additiod d ie$ may be
required that codd result in changes IO The hkrcdm Facilities and the Network Uppdcs
and in changes to Interconnection CustMner’r cost obligatiuns for hose facilities.
One (1 1 coal fired steam Wine generator rated at 610 MW summer / 620
MwwintM:
One (1) 24138 kV Step Up (GSW) transfbrmer.
I Onc (1) I3 -81133 kV Rwwve Auxiliary Transformer (RA’Q
One (1) 343138 kV Coal Hading Facility Transformer
I Thrcc (3) 138 kV transmission lines fro% the GSU 138 kV bus, from the RAT
138 kV hus, and from the Coal Ilanding Transfonnzr 138 kV bus, to
Transmission &mer’s three dead-end stnrctures at Tmmission Owncr’s 1 3 8
kV subsbtioa
AlJ.mssary why, protection. control and communication s,wtm required
.
to pmrect the Generating FaciIitjl and Interconnectim Cusmefs
htwcormection Facilities and cwrdie with Transmission Owner’s relay,
pmtion, C O ~ I and , communication systems. Interconnection Customer
shall i-11 power syskm stabiiizns.
The mrnunlations facifitias described bclow and in Apdices C and D
will be paid for, and imtdlcd by Tntmnncction Customer. The data circuits
described bclow sha0 be used to provide the necessary generator data, otbm
status data and remote interngation and cont1-01 tc Transmission Provider and
Transmission Owner as set forth in Appcndices C and D:
(a)
@}
dedimed voice dispatch circuit bcnt& Generating
Facility’s operatoTs and thc Transmission h r ’ s dispatch
center in Shrevepars Louisiana
Om or more telmmmunication did-up lines. inchding
aciated inkiface equipment at the Generating Facility
mdor Point of Intmmnn: tiw.
.,

2. Network Upgrades:
(c)
Exhibit TAG4
Page 88 of I IO
oxlc R E communication cirwir betwctn & Trammission
Owner's d-h center 61 Shreveport, 1,ouisiana and the
Generating Facility andlor Point ofIntercr>nnection.
8 Tkree (3) dad-end structllres at the new 138 kV substation for the three line
Imninalls to Intercmmh Custorncr's GSU, MT, and the Coal Handling
Faciliry Transformer.
Three (3) sets ofmisccllantous 138 kV iim term% equipment
Three (3) wts of I38 kV mercring
Relay modifications as required to interconnect the Genedon FaciIity and
associatcd facilities.
Instali a dynamic huh recorder and remote terminal unit lmmd at the
Generating Facility.
Estimated Cost
. - -(a] Stand Alone Nerwork Upgmdw to bt? &sign& procured, constructed, and instdled
by Transmission Owner:
None
@) Nchvork Up,des to be designed, procured, constructed and ins&IIed by
'Imnsmission Owner:
?hrk 73811 I5 kV Substation - Build new substation with
twelve 138 kV h i t breakars, me of which will bc
operated at 115 kV. Relocate two138-:15 kV
auteansfomers from Patterson to thc Twk subtion.
Turk - Sunar Hill 138 kV Trmsmission Line -
Ruild a new approximateIy twenty-four (24) mile I38 kV, 1530 MCM
ACSRtransmission line
3 42

... , .... .. ~ ..T~rlr-€Io~.l.lI.kY..transmission
Exhibit TAG4
Page 89 of I IO
Lk
Turk- Southeast Texykamt 138 kV Tra~misSi~n -
Build a ncw approximately hkty-four (34) mile 138 kV, 1590 MCM ACSR
mnsmission line. Transmission hvie recommends this Line to b roured
as dose to Arkansas Electric Cmpcrativc Corporation (AECC) FuItm pwr
station as practical.
I Sum Ail1 138 kVSubtion- Add onc 138 kV
line terminal including WO c2) I3 8 kV ciicuir
breakers.
a Southeast Tarkana Stibstation -Add one
I3 8 kV line ternid including two
(2) I38 kV circuit b&en
Patterson I38kV Suh tion - In-11 six (6)
I38 kV circuit Mers to convert the existing
substation to brder and a half configurntion.
Repke one (1) 138 kV chub breaker. Remove
(2) 138 kV-115 kV aG+Um~fEma and
~WO
relocate to Tuck substarion.
Turk- Hope 115 kV Transmission Line - Build a new
approximately IWO (2) miIc 1 3 kV, IS90 MCM ACSR
transmission line (operated at 1 I5 kv) frcm Turk
substation m rhe existing OkayHope 1 15 kV line.
Sever and reconnect to form o n m
Iine. , . . - . . . . .
Turk - Okay 138 kV Transmission Ihe - Ruiid a bew
qpmximalely two (2) rniIe, 138 kV, 1591) MCM ACSR
ixansmissiun h e from Turk substation to thc
misting Okay-Ihp 115 kV transmission Iine
Sever and rebuiId approxirnateIy twelve (12) miIa of I 15 kV Iine
to Okay substation to l38 kV standards with 1590 MCM
AEX io form a Turk - Okay 138 kV
transmission line.
Okav Subsmion -Replace three (3) singlephase
1 15/69 kV autotrans formers with m e ( 1) 90 MVA,
three-we 13 8/69 kV autatransformer and convert
high side of station to 138 kV.
Qkav- Patterm I38 kV 'Transmission Line - Rebuild approximateIy
nincteen (19) miles of 115 kV Imc to 138 kV standards
with 1590 MCM ACSR.

Exhibit TAG4
Pagc 90 of 1 10
AshdownRECIAEC C Deliveh Point1 - Replace
switches 6276 and 6277 with 3000 A, 138 kV
switcfrcs md replace the conductor Mwem
them With 1590 MCM ACSR
Total Estimated Cost
IC) Affectad System Upgmk - The folhwhg upgrades were a b identified in the
~
Facilities Study for the Gentrating F&;iitY.
Cmvert Southwest Arkanms Electric Cmperativc CorpomLion's
("SWAECCY) iMiIId wbstatiori high side from 115 kV to 138 kV.
Replace circuit switcher at S WAECC's McNabb submion (due to short
circuit considerations).
Transmission Owner and hnta~~~ectim Customer a p e ro coopte .with the
Affected Systemls) to develop the constmctian plans for the repbmment of the
McNabb I 15 kV circuit switcher and the conversion ofthe Millwood mbstatfoon from
1 I5 kV KO 13 8 kV operation due to the convtrshn afthe Okay-Millwood 1 I5 kV Ii ne
fa 138 kV operation. A Consmztion Ageemen: between the lntercoanection
_. . _Cusx~mer~and the AlTec~ed Sys~emDpor (SWAECQ wiiI.k dtveloped IO
implemect the mstruction plan.
(d} Joint Network Upgrades
Mmc
a None
(0 The cost fwthe Transmission Owner's Interconnechn Facilities to be conshctd by
Interconnection Customer is escimatcd at $0.
(g) &dispatch Cats. 'I'ransmissian Owner and Transmission Provider agree thee will
be no rcdipch costs associated with outages necessary to complete the inkrconncction
of thc Generating Facility. The cost, incIudbg penalties, of redispar& 07 market-reIafed
r' . .
J 4.1

E.xRibit TAW
Page 91 of 1 IO
custs nrising from outages described m Section 9.7.1 of the Agreement will be estimated
as outage schedules m Mined.
(h) The total cost €or the Transnzissiw Owner's Interconnection FaciIitiq Stand None
Ndwork Upgrades and Other Network Upgrades is estimated at $86,173,000.
(i) Immonncction Customer's potential liability for reimbursement of Transmission
Owmr for taxes, hkmt ador pendItirs der Section 5.17.3 is tshated ai $0. This
amount is not included in the bd COST in Section 2@) ofthis Appdk A. This estimate
assumesthat there are no costs incurted by the Transmission Owner for land
Tmmission Owner apes lhar Interconnection Customer wilI not be required tc
pvide financial'&Q for the estimated tax l~iLiq until a Ga-wnmental Aud~oriy
determines that thc tax is de.
G> The prhn of the Network Upgrades that is subject to t4e transmission service credits
described in Section 11.4 of this Agrement is estimated at $84,990,000.
3. Distribution Upgrades:
No Distribution Upgrades
4. In tercvnnecfioa Service: In termnnwtion Customer has seIeded the foHnwing:
- 620 MW hwgy Resource Tnkrconnection Servjce
- MW Nexwork Kesowc Interconnection Service within Transmission Owner's
Control Area
to outside Tmission Owner's
ContrnI Area
- - MW Network R c s o ~ ~ n - ~ ~ ~ e
5. Constrtrction Option Seiected by Infercmnnection Customer:
Jntercomection Customer has selffted the Standard Option for construction of the
Transmission Provider's Interconnection Fadities and the Stand Alone Network
Upgrades. (Choicfs are Standard Option, AItemate Option, Opum to Build, Nqoriattd
7. Pemih, Licenses and Authorizations:
83
f #:

Exhibit TAG4
Page 92 of I 10
I’he Point of Change of Ownerstlip shdI bc the point where Interconnection CWrner’s
three (3) I38 kV trmsmission line($ Wachcs to Tmsrnission Owrrer’s dcad-cnd
structurc(s) at the Turk 138 kV substatiort
The Point dIntercomection shall k the point of attachment to the 13 8 kV bus at Turk
Substation dthe mnductors hm each of the three (3) dead-end stsuctllres where the
tmmisiim limes Wm the Gemting Fsciiity are termtnated in the 138 kV Twk
Substation as shown in Figure A-2, which drawing is aetachod hereta and made a part
hereof. l’kc imrcuntKction metering, to be locatd at thc 138 kV Turk Substation shdI
include any necessary compsatim mch that it is effectively located at be Point of
herccmectim.
7
-...
f 9rl

.. .
Exhibit TAG4
Page 93 of 1 ID
Fi’igtlre A-1. Interconnection FaciIEty Onefine
aj

Exhi bit 'I'AG-4
Page 94 of 1 IO
Fignre A-2. Point uf Change of Uwnership,.Foint ofh tercwtnection and Metering
. -. .

Mibit TAG4
Page95ofllO
Fipre~A-3. Map of the Area surrounding Turk Power Station
-.*
87

Obtain C&*eemmentd huthorhtion - 138 kV Turk to
Sugar Hill CKPK *
Obtain Governmmtal AlahorEration - 138 kV Turk 3
SouTheast Temkm CECPN *
Station sitc available from Interconnection Cwoner
Complete the Turk to Silgar Hill 138 kV linc *
Complete the Turk M Southas& Texarkana 138 kV tine *
- Complete the 138kV Iine-t.eminal at-SugarHilI I
.- -
Complete the 138 kV line terminal ar Southeast Texarkana
Complete enough of the Ttrrk 138 kV SubsMon to comcct the
Sugar Hill a d Southeast Twarkana lines and energize
hkrconnedon Ctstomer’s Interconnection Facilities.
Campkk T&mission Owner’s
Immonnection Facilities
In-Servioz Date - B d d
Interconnection Facilities
In~omection Customer’s
Complck all mmiinbg Network Upgmdes *
Mia1 Synchronization Date
-+
- .
TrmSmissioa Owner 0646-2008
Transmissim Owner 06-06-2008
‘Interconnection Customer 12-08-2008
Transmission Owner 12-1 8-2009
Transmissim Owner 12-18-2009
- Tmsmissiou Owner 12-31-2003
Transmission Owner 12-3 1-2009
Tmsmbsion Owner 12-3 1-2009
5

Exhibit TAG4
Page 97 of 1 IO
89
... ,

Fxhibit TAG4
Page 98 of I10
. .
Payments ibr Tranrmiss3on Owaer’s Interconnection .Facilitie and Network Upgrades,
Transmission Owner shall invoice htcmnaectimi Customer on a monthly his for thc costs
incurred for the Trmsmission Owncr‘ s Intenmmem ‘on Facilities and Network Upgrades-
htemnneetion Customer shall pay such monthly invoices as provided in this A mmr.
Projected Cost of Tmnsmissim Owner’s Interconnection FacZiti& and Network Upgrades
2007
2008
2009
2010
201 1
$378,000
$1 8,43 8,000
w,1. %,dol3
$6,988,000
$235,000
* hring the course of design and construction, Transmission Owner may update the projected
costs and w-11 share such updated projections with Tntercormcctim Customer.
- . . . . _. I - .
_ - --.*,-.a -

._ . -- -
laterconnection Details
ExhibitTAG4
Page99of I10
Appendis C to LGIA
Intereiineetion DetaiL
This Appad~ C to LGlA is 811 integral part of thc IntercomWion and Operating Agreement
among the Inkrcon&on Customer, Transmission provider and Transmission Owner.
1. FaciIiry; IrrtercomeCtim Custamer intends tcr cnvn and operate and man Interconnection
Customer’s Intucunnection Facilities as described in Appendix A. The Interconnection
Customer‘s Generatbg Faciliw will consist of one cud fied steam turbine generator rated 6 IO
MW (summa) / 620 MW (winter). Customer‘s Wities also consis& of the one associated
24,01138 kV herator StepUp (GSU) hamformer, 13.8tl38 kV Reserve Amdiary ‘l’ransfbrmer
(RAT’), a 343138 kV CoaI Hmdting Facility transformer, and associatd 138 kV srnd 24.0 kV
equipment from the Interconnection Customer’s facility up to the Point of Change of Itlwned~ip
with be Transmision Owner as desmi b Section I (a) of Appcndix A-
Z Poiltt of Change of Ownership. The Point of Change of Ownership shdI be as described ir~
Appemdk A.
3. Point of Intemmertion. Thc Point of Inkrcmnectian shall be as dcscrihed in Appendix A.
4. Provision 01 andlary se&
Nothing in this Ament should be construed as obIigaring Transmission Owner to
provide hcikq S y j ~ M s lntzrconnection-~st~m-~~ An~l~y S~cjs? mcesmy to
deliver hc ~.ncrgy produced by the Gcnmtor Facilities over the Transmission System, if
any, will be provided TO Intertonnectim Customcr or any entity purchasing or othemise
acquiring energy generated by tbe Generator Facilities pursuant to the provisions ofthe
Transmission Provider’s Open Accm Transmission Tariffur my successor tadT
6. Conditiom of Irrtercunaection.
91
6.1 No Sirnuthumus htemnnections. htacmection Customer sgnm thal it wiII
not interconnect or operate any pan of its system connemd to the Transmission System
in synchrunization with aay other electric system, wmer such other electaic system is

-- .-_
Exhibit TAG4
Page IO0 of 110
6.4 Control Area. The &des a p b t at thc time this Agreement is executed,
Intmonnwion Customer plans to opzmte the Generating Facility in thc 'I'mnsmissim
Ownw's Control Area. IntMcmection Customer agrees to provide at least sir (6)
months advance notice to Transmission Owner and Transmission Provider prior to
changing he Generating Facility to a diffwent Contrd Area. Interconnection Customer
shall comply with all afTmsmission Owner's requirements and specifications for
rnetcrhg and tc1cmeh-y requid t~ mzornplish the Qperatim orthe Gending Faciliqf
m 8 different Control Arc&
65 CompIetian of InterconnectioB. Interconnection Customer understands and
q m s that Tranmission Owner shdl complete the connection dthe Transmission
Owner Inhunmtbn Facilities aiid the hterconneCtion Customer's hterwnnection
Fxflitk and will manage all work on Transmission Owner's Tmmissim System.
Intemection Customer shall not iattrcmnoct with &e Transmission System prior to
completion of the instalMon and testing of the Metering Equipment in accordance with
the terms of Section 7.4 of this A p m L

93
-6.7 Construction Statas. ’Re htmnnc&n Customer shall inForm TraTlSmikion
Owner and Tnnsraission Provider on a regular basis, and at such other?h~ as they
reasonably rccps?, of the Staftls of the mdon ad hallathn of the
Intercomedon CUS~OM~~’S Intmomcctian Facilities and rke &ne* Facility
hcludh& but not Ihited to, the following information: ti) pro- to date; [io a
description of scheduled activities for next periad; and (iii) the identification ofmy
event which the Interconnection Customer reasonably expects may dchy construction of
thc hterwmectioxl Customer’s htermmectiion Facilities andror the Generating Fxiliry.
68 Deign and Construction. The Parlies agree to cause their respctive
TnttmonncMion Facilities to be comQ-uc& in accmknce with the Transmiion
Owner’s Guidelines fm Generation, Transmission and T~ansmission Hemicity End-
Users Intercmeckn hcilities in effcct at the time of the commencement of
construction .or modi ftcation,
6.9 Additional Cornmanicatloo Reqnircrnents. The addhional communication
requirements for the Intcrconnecthn Customer‘s Tnterconnedw Facilities and the
Generating FaciIiiy arc a$ noted in Section 8.0 METERING A;- SCm.4 .
REQUIREMENTS of the TransmisSion Owner’s Guidelines for Gcneratim, T mneian
and Transmission EI&city EXA.krs Jntercomcction Facilities.
f

Exhibit TA C; 4
Page 102 of 1 IO
Appendh n to LGIA
Security Arrangements Details
Infkmcture security of Transmission System equipment and operations and controi
hardware and sofivare is essential to ensure day-today Transmission System reliability
and operational stcurIty. FERC will expect all Transmission hviders, market
participants, and Interconnecfion Cwomers inkrcomected tu the Trammission System
to comply with the recornendations offered by the President’s Critical Wasimcture
Protection Board and, eventually, best practice recommendatibns h m the dectric
reliability authority. All public utilities will be expected to meet basic standards for
system inbstructure and opcralional security, including physid, operational, and cyber-
securitypractices.
94
.:.:c

Exhibit TAG4
Page 103 of 1 10
, Appendix E To Agreement
Commercial Opmatioa Date
This Appendix E is a part of &e Agreement between Transmission Provider,
Ttansmksion maer and Intercomdm Customer.
Cxl Mom, Sr. Vice pcesident
Chief @crating mcer
~mthwcst Pawer P ~ I
415 N. McKhley, f140 Plaza West
Little Rock, AR 72205 ’
Managing Director, Transmission Assct Management
American BIectric Power Service Corporation
700 Morrison Road
Gahama, OH 43230
Re: Turk Power Statim {GEN3IX)M)IO)
Dcar Mr- Monroe and Mr.
On [Date] kutfiw&em Electric Power Company has completed Trial Operation of the
mkenced Cieaeraing Facility. This letter confms that Sauthwstem Eka-ic Poww Company
cummenced comrncrcial opration of the Generating F&ciliQ, effdve as of (Date plus one
_. Wl- . .
- . -
. .
Thank you,
Sr. Vice President, Fossil and Hydro Gcnemtion
American Electric Pqwcr Service Corporation
I55 West Nationwide Boulevard - Suite 500
Columbus, OII 432 I 5
cc Maiiaghg Dirccmt, Regulated Tariffs
American Electric Power Service Corporation
I Riversjdc Plaza
Columbus, OH 43215
95
137

-- .. .'
Notices:,
Tmsmksion PmvideF:
E-uhibit TAG4
Page 104 of 110
Appdix F to LGlA
Addresses for Delivery of Notices and BiLlings
Car1 Mom, Sr. Vicc hident
Chief Operating Officer
Southwest Power Pool, Inc.
415 N. McKinley, # 140 Pfwa West
Little Rock, AR 72205-3020
Phone: 501-614-3218
FacMe: 5 0 1 AM-95 5 3
With a copy to:
.- - .-
Maaging Dircctor, RegdateJ 'I'd&
American Electric Pmw Service Corporation
I Riverside Flaza
Columbus, UIT 432 I 5
Telephone: 6 14-23-2764
Facsimile: 6 14-223- 1069
Interconnection Custornm:
Sr. Vice President, Fossil md Hydro Generation
Ame~cm Electric Pow Service Corpbratidn
255 West Nationwide Boulevard - Suite 500
Columbus, OH 432 15
Telephone: 614-583-7700
Facsimile: 514-383-1 135
-%-

Exhibit TAG4
Page 105 of 110
BiMigii and Payments: Addresses for comtmc~on hvoices, O&M invoices and
settlement of ancillary servicw:
Transmission Provider:
Tony Alexauder, Supenim of Tariff Accounting
Southwest Power Pool, hc.
415 N. McKinley, #I40 Plaa Wm
LittfeRock, AFL 722054020
Send p ymts fm cw&tian and U&M invoices to We addm Wi5ed on the
invoice.
Director, New Plant ntueloprnent Projects
American Electric Power Service Corporation
I Riverside Phza
Columbus, .OH 432 15 , . .. , -. -.
Telephw: 6 14-71 (53291
Facsimile: 614-71 6-1 779
Alternative Forms of Delivery of h’otioe9 (telephone, fatximite or email):
Carl Monroe, Sr,‘ Vice President
Chief Operating OfFcer
Sourhwest Power Pod, Inc. ’ ’
415 N. McKinley, B 140 Plaza West
Little Rock, AR. 722053020
P~OIIK 501-614-3218
Facsimile: 50 1-664-9553
*..
.. I
-97-

.-
Transmission Owner:
Exhibit TAG4
Page 106 of I IO
Managing Director, 'liansmkion Assa Macagcment
American E lhc Powm Sem-w Corpopation
700 Monism Road
Gahanna, OH.43230
Telephone; 61 4-552-1600
Facsimile: 814-552-2602
Vice bairn Ehgineering Sewices
Amrim Hechic Power Service Corporation
1 Riverside Plb Columbus, OH 4321 5
T&@oI~ 614-716-1270
Facsimile: 6 14-7 16-1 803
'I'ransmissiun Provider
Lanny Kickell, Director, Uperatiom
soutllwest Power Pod, Inc.
4 15 K. McKinley, # I40 Plaza West
Little Rock AR. 72205-3020 -.
Phone: 501-614-3251.
Facsimile: 50 1-614-9353
Transmission Owner:
SwFgcO &sed IIiIl PS Sys- Control Center
500 North AlIen Ave,
Shre~ep~rt, LA 71 101 -2669
3 18-673-39 12
With a CQ~Y to:
&aging Director, Transmission operations
Amcnm Electric Power Servicu: Corporation
1 Riverside Pha Columbus, OH 33213
-98 -

Interconnection Customer:
Exhibit TAG4
Fage 107ofllO
AEP Gmmtion Dispatch
Amerjcan'EI8ctric Power Senice Corporation
1 55 West TWionwide Bonkvard - Suitc 500
Colmbus, OH 4321 5
Telephone: 6 14-583-E 19
Fxsi mik: 6 1 4-583 -1 6 13
-99-

Exhibit TAG4
Page IO8 of 11 0
Appendix G $0 LGIA
Requimmeats of Generaton Refying on Newer Twhnslogies
.. .. , *: :..... *.e;
None
-100-
.:... .
. .

. :*
.-:
FxhibitTAG4
Page'l09ofllO
Appendix €€ to LGIA
. .
.
.,-. .:.;.
i:

Exhibit TAG4
Page I10 of 110
. -.:,..-.-- .. ..* .: .... ..
a.

2008 STATE OF THE lVLARKET REPORT
SOUTHWEST POWER POOL, INC.
Prepared by:
Boston Pacific Company, Inc.
External Market Advisor
for the Southwest Power Pool, Inc.
Craig R. Roach. Ph.D.
Stuart Rein
Katherine Gomhall
1100 New York Avenue. NU', Suite 490 East
Washingon. Dc zoO0s
Telephone: (202) 296-5520
www. bostonpaci fie-corn
May 5,2009
Edibit TAG5
Page I of 117
BOSTON PAClFlC COhlPANY, IN[-.

TABLE OF CONTENTS
Exhibit TAG-5
Pag 2 of 117
EXECl.iTWE SLJMMARY ................................................................................................ 1
I- OVERVIEW OF THE SPP FOOTPRINT ............................................................ 14
I1 .
A . Brief Overview of SPP .............................................................................. 14
B . Customers - The Demand for Elechcity ................................................. 18
C . Generation - The Supply of Electricity .................................................... 23
D . Transmission - The Bridge behveen Supply and Demand ...................... -32
EIS MARKET RESULTS .................................................................................... 39
A .
B .
C .
D .
E .
F .
Brief Overview ofthe €IS M ~ e............................................................ r
39
Market Activity ......................................................................................... 39
Market Prices ............................................................................................ 42
Revenue Adequacy (Net Revenue Calculation) ....................................... 51
Fuel Type .................................................................................................. ...
55
Market Parucipatron .................................................................................. 56
G .
H .
Market Power Measurenirnt and Mitigation ............................................ 61
Revenue Neutrality Uplift @NU) ............................................................. 65
111 . ENERGY DELXERY ......................................................................................... 72
A .
8 .
C .
..
T~S~LWQXI Service ................................................................................ 72
. .
Transmssion Congestion .......................................................................... 77
Transmission Inv~sfileTlt .......................................................................... 85
IV . RECOMME~~ATIONS ...................................................................................... 91
A . EIS Market and New Markets ................................................................... 9t
B .
C .
D .
E .
F .
Transmission ............................................................................................. 92
Wind .......................................................................................................... 92
&neration Interconnrction ....................................................................... 92
Offer Caps ................................................................................................. 93
Wrnd Capability Ratings ........................................................................... 93
V . BROADER ISSUES OW THE HORIZON .......................................................... 94
A . F2deraI Climate Change Legislation ......................................................... 95
B . Expansion of Wind Generation ................................................................. 99
C . Tax Incentives for Investment in Renewabks . Transmission . and Other
Energy Innovation ................................................................................... 101
APPENDICES
i
BOS-PON PAC'I FIC COMPANY . IN('.

1 Figure 1.1
Figure 1.2
Figurz 1.3
Figure 1.4
Figure i.5
Fipiirr 1.6
Figure 1.7
Figtm I, 8
Figure 1.9
Figure I. 10
Fi-we I. 1 1
Figure I. 13
Figure I. 13
Fispre 11.1
Figure tT.2
Figure 11.3
FiLwe 11.4
I figure IL.5
NERC Interconnections
List of Figures
Map of SPP Balancing A~~thm-irks
SPP Daily Mahum and Minimum Electric Energy Demand by Hwr from
2006 io 2008
SPP Electric Load hmiion Curve for 2008
Current Insralled Generation Capacity by Fuel Type
Currmt Installed Generation Capacity by In-Service Year
Active Requests for Generation Intercomection: Capacity by BaIancing
Authority from 200 I to 2008
Type of Active Generation Interconnection Requests
Regions of High-Voltage (23W kV) Connectivity in SPP
Regions of Mediim-Volrage (. 1 I5 Ict’ to L 61 kV) Connecriviry in SPP
Days of Transniission Oritages by Month for 2006 to 2008
Days of Transmission Outage3 by BaIancing Authority for 2008
Ratio of Days oTTransrnission Outages to Nurnk of Trwsrnission Bm&e
bv Balancing Authorits for 2008
Cornpanson of Average MorrtHy- On-Peak SPP Electricity Prices and
Panhandle Natural Gas Pnces
Cornpanson of SPP. MISO, & E RCOT - Wide Hourly Average Prices by
Month for 2008
SPP. MISO. & ERCOT Hourly Prices fcr 2008
SPP Hourly Price Range b): Month
Avemge Armud Price By Balancing Authority
11 Figure 11.6 1 Annual Price Range by Balancing Authority
11 Figure 11.7 1 Average Monthly Price by Bdancinng Authorit!
Figwe 11.8
1 Figure 111.1
Components of RN U by Momh for 2008
Trmsniissioii Owner Rrbenur filr 2008
ii
~
Edlibi t T.4G-5
Page 3 of I 17
15
17
22
BOSTON PAClFIC COMPAKY. IN

iii
Edtibit TAG-5
Page 4 of 1 17
3 ti&
BOSON PA€'iFIC COMPANY. IN'.

List of Tables
Evhibit TAG-5
Page 5 af 117
Table I.2 Monthly Peak Electric Energy Demand (MW) for SPP If
Table 1.3
Tnbk 1.4
Total EIeclric Energy Usage (hWh) Withb SPP by Month and Year
Balancing Authority Demand and E lkc Energy Usage in 2008
~ ~
~~ ~ ~
1 Table 1.7 I Generation Outage Data Coincident with Peak Load by Month fx 2008 -1 35
Table T.8 DC Tie Transmission Capability 35
Tab12 11.1 Electricity Sales in the €IS Marker by Mod
41
Table Li-2 Electricity Rrchase in the EIS Market by Month
41
Table I1.3
Table [I-4
! :~blr I1.i
rnbk I l.il
Iahlr I;.-
EleMrieity hces Compared With Neighboring Regions for 2008
Electticity hces Compared With Nei&boring Regions
Volatility by Balancing Authority for 2008
Flagged Interval hcts Beyond ThreshoIds for ZOOS
Cost Assumptions Used for Net Revenue CaLculations in 2008 Dollars
T:ibI: [[.F Summary of 2008 Net Revenue Calculations 54
['nblc l1.L'
1 rAhl? [ I . l i r
l
1 r .ibis I!. 1 I
S m n of ~ Combined Cycle Net Revenue Calculations for ScIeacd
Bdancim Amhokies
Sumrrt~ of Corubrtstion Turbuie Net Rtvenue Calculations f~ SeIected
Balmcine Authorities
Generation by Fuel Type for 2008
iv
~~
20
21
BOSTON PACIFrC COMFANY. Ilric'
1 [;$I
~

Table 11.15
Table [I. 16
Tab1 5 11.17
Tabk IT. I8
TAbk 11. I9
Table I r.10
Tabk l', 1
Market Ramp Rate Violations
Exhibit TAG5
Page 6 of I17
Average Ramp Rate of Capacity Made Available to the €IS W e t by Month
Effect of the FERC and SPP offer Caps in 2008
Shares of EIS Market Sales for All Market Participants (Anonjmously
Ranked) for 2008
Shares of Capacity Made Awdabk During the Pak How of &e Month for
AI1 Market Pxkicipants (Anonvmoustv Ranked) for 2008
SPP All-In Price by Month for 2008
Highest TRM by Percentage of Sumnier Emergency Limit During 2008
Percent of Five-Minute InkrvaIs Wth At Least One Flowgate Congested
2008 Tixp 10 Congested Ftowgaies in SPP
Shadow Pnces in S PP in 2008
2008 Top IO Congested Flowgates by Average Shadow Price in SPP
Projea Classification
Potential Effect of C02 Ricing on the Cost of Elehcio ($iMW%). by
Technology
v
74
SOSTON PACIFIC COMPANY. INI

DISCLAIMER
E.uhibil TAG-5
Page7of 117
The dam and analysis in this report are provided for informatonal purposes only and shall not be
considered or relied upon as market advice or nmrket settlement data. Boston Pacific Copany.
h. [“Boston Pacific”) makes RO representations or warranties of any kind, express or implied,
with respect h the accuracy or adequacy of the information contained herein. Boston Pacific
sW1 have no liability to recipients of this information or third parties for the consequences
arising from errors or discrepancies in this infomtio~ for recipients’ or third parties’ reliice
upon snch infomation. or for any claim, Iw or darnage of any kind or nature whatsoever arising
out of or in connection with ti) the deficiency or inadequacy of this information for any purpose,
whether or not known or disclosed to the authors, (2) any error or dkrepy in this
information. (iiil the use of this information. or (iv) any loss of business or other consequential
loss or damage whether Qr not resulting from any of the foregoing.
vi
BOSTON PAC1 FIC COMPAW. IN[-.

A. Purpose
EXECUTIVE SUMMARY
Exhibit TAG5
Page 8 oT 1 I 7
Boston Pacific Company, Inc., as the Extzmal Market Advisor (EMA) for the Southwest
Power Pool (SPP) Regional TranSrnission Organization (RTO), has been asked to provide an
annual report on electricity mket conditions to the SPP Board of Directms (BOD or Board), the
Federal Energy Regulatory Commission (FERC), the SPP Regional Sate Committee (RSC), and
other appropriate state regulatory authorities.' The purpose of this 2008 St& ofrhe Mmkf
Report is to fulfill that request. The FERC requires Smte of the Markt R ep= like this from all
RTOs and Independent System Operators [ ISOs).
Our report first provides an overview of supply and demand conditions in the SfP
footprint. Next we pravide an extensive report on SPP's energy market - the Energy Imbalance
Service (E19 Market, The €IS Market started on Februarq. 1,2007 so this report is on its second
year of operation. We then begin a discussion of transmission services ("'the Transmission
Market"). Some broad recommendations based on our analysis come next. Finally. we identify
a few market and regiilatory events that are Iikly to affect SPP's markers in coming years.
This is the fifth Ski& ofthe Murlirt Repoi-t Boston Pacific has completed for SPP. All
have been analogous to an annual physical in the sense that 51" report on a great many diagostic
tests and ask a lot of questions. Keeping with that anahgy. we conclude that SPP is a healthy
RTU. For the €IS Marker, the signs @fg@:ocrd healrh iwiudz robust participation. prices and price
volatilip which compare well to neighboring lSOs, and the absence of structt~ral market power.
For the Transmission Market the clearest sign of good health is the substantid investment in the
transmission sysrcm. which. in large pax is the resuIt of the SPP BOD. the RSC. and SPP
members consmacrtvely addressing the most difficult qusstiion - who pays?
Still. there are actions SPP should take to keep or improve its guod health. First, it must
continuz to reduce and manage stress -that is. mns.mission congestion. Second. it should move
quickly to expand its markets - SPP docs have a plan for "Future Markets." Third, there are a
set of smIl areas that need artcntion including a new source of data for updates of the Offer
Caps. a change in method to prioritize the generation interconnection queue. more transparency
to identify the cause cf transmission outages, and stricter standards for reporting seasonal
capabilities fer wind generating units.
E. Overview of the SPP Footprint
As an RTO. SPP provides services to non-dkcriminately manage utilization of the
transmission systtrns owned by its members. A5 of April 2W9, SPP had 34 members. SPP
added three new members on December I. 2008: Lincoln Electric System ( LES). a municipal:
and two ncw state agencies, Nebraska Public Power District (NPPDI and Omaha Public Power
-__.. --
I
.%e (k&r CirmriIlg KII; Slatus Sub-iwt to Fu:uItilliiwxit of Kequimnm~s, l~ch-uary 1(1,20~l4, ITRE' Duckc1 KO
Kl'&LlJlO(l and IiKiU-J,94HX1, ai p. 56. fn. 222.
1
BOSTON PACIFIC COMPAhY. INC'.

E.ihibit TAG5
Page9cflI7
District {OPPDJ. SPP's Regional Entity IRE) footprint includes sixteen separate balancing
authority operators that individually. are responsible for marching electriciq- supply and demand
within their territories .'
SPP's members provide electricity to meet their customers' needs. The peak electric
demand of these cusromers in &e SPP RE footprint in 2008 was 41,391 Mw and this peak
occurred in August. The 2008 peak demand was 0-7% higher than in 2007, and this percentage
growth wag identical to the 2007 peak demand growth.
Electric energy usage also increased, but more slowly than last year. In 2008: usage was
208.3 million MWh, an increase ofjust 0.5?40 over 2007, the growth bei% lower than last year's
increase of 1.6% As with electric demand. electricity usage in SPP is seasonat and peaks during
the summer, particularly in July and Au~ust. Customers within the five largest balancing
authorities in SPP mount for 73.1 % of tom1 electric energy usage in SPP. These five balancing
authorities and their shares of 2008 energy iis%e are American EIectric Powx [ AEPW) with.
22.3%. Oklahoma Gs & Electric (OKGE) with 14.5% Southwestern Public Service Company
(SPS) with 14.4%. Westar Energy. Inc. (WERE) with 14.1%. and Kansas Ciry Power & Light
(KCPL) with 7.8%.
Generating facilities supply the electricity that is used by the customers of SPP's
members. The total generating capacity in SPP was 57.765 MW.' In comparison to the peak
demand of 42.89 1 MIA' during 2008. SPP has a significant resource margin [ installed generation
capacily in excess of peak demand) of 14.874 MW or 35%. However. in realiry, rhs capacity
includes some units &at arz not necessarily dedicated to serve load or, due tc Iimited
transmission capability. are not deliverable to mett a11 loads at all times. If we remove this
capacity €rom the total and also adjust our total for net firm purchases and sates. we gat a total
capacity number of abour 50.600 MW. When we compare this to the peak demand of 42,891
MW, we get a re50urcc margin of 18%. Since 2000, there has been a significant amount of
construction of new natural Sas-fired generating plants. whrch contributed significantly to the
installed resource margin. Ofthe total generating capacity in SPP. 55% is natural gas-fired. and
89% of capacity in SPP is either coal- or natura! gasfired. This healthy resame margin can
have positive implications for both reliability and for mitigation of the potential exercise of
market power within SPP.
2
BOSTON PACIF[C COMPANY. [NC'.

E?ihibt TAG-5
Pqe 10 of 1 I7
The initial examination of the amount of generation rev& a resome margin that would
appear to a1lw for an increase in load without requiring construction of new generation to
maintain reiiabiiity. However, rhe economics of electricity genemti~n, not just growth in
demand, drive interest in constructing new genedon. This is evidenced by the fact that there
are 60220 MW of new capacity seeking generation interconnection studies in SPP; this marks a
93% increase over what was in the generation hterconnection queue in 2007: The factors
driving ibis imrnst in new capacity, especially in the form ofwind, include increases in fuel
costs {until recently), the potential for increasing minimunz requirements for renewabies (called
Renewable Portfolio Standards (RPS}), and global wamhg concerns. Among the active
genexaticln interconnection requests, 82.3% of the capacity (in nominal &rms) is for wind
projects, white coal accounts for 5.8% and natural gas accounts for 1 1.2%.
Generating facilities are masionally taken out of service for planned maintenance. and
they also shut down hm time to time due to unexpected equipment failures (forced outages).
Generation outages decrease the amount of electricity susly available to meet demand and,
thereby. can affect market prices.
In 2008. generation outages in the SPP footprint foliowed an expzcted pattern. When
peak load is usually at its highest (roughfy June to August). total oumges as a perccn-e of peak
load generally are at their lowest. This is mostly due to the fact that planned maintenance
outages are scheduled outside the summer peak period and coordinated by SPP, In fhct, capacity
off-line due to forced outages is higher than that due TO maintenance outages &wins the s met
period. whife the reverse is generally true for ?he reminder of the year.
Comparing 2008 to 2007, using a very conservative m&c of totaI orruses as a
percentage of the monthly peak demand. the extent of generation outages were slightly higher in
2008 than in 2007 on average. For the par. outages as a percemge of peak load increased from
an average of 1 ?.go/;, in 2007 to 13.1% in 2008.'
Trammksion outages also impact deliverability and can affect market prices. Moreover,
rransmission outages can make transmission cmgstion more likely so that die SPP Market is
balkanized with prices varying by location. Transmission elements. just like generating units.
need to be removed from service for planned maintenance. Transmission system components
also fail from time to tims and art impxed by weather, resulting in forced ouwees.
The pattern of transmission system outages for 2008 follows the same general pattern as
that for grnerating units in that outages are at snme of their lowest levels during The summer
months. The exteiit of tramsmission system oub~ges in each month was cdculated by the knyth
BOSTON PACIFIC C-OMPANY. WNC'.

Exhibit TAG5
Page 11 of 117
of outage in days fur each outage and totaled for each monrh. The number o? days of
transmission outases increased 8% from 1 1,149 days in 2007 to 12.0 1 1 days in 2008. Although
the 8% increase is much lower than last year's increase of 3096, we are still concerned about the
growing number of outages. We believe that one reason for this increase is most likely due to
the increased mount oftransmission invesment that has resulted from SPP's Transmission
Expansion PIan (STEP). However, given the current data set, we sre unabk to confirm this
hypothesis. Furthermore, the source for the data we are currtntly using, OPSl , is meant to be a
forecasting tool, and is not mcant for reporting historical outages. Atso, there does not appear to
be a consistent method for determining whether an o uxe is a forced outage or a maintenance
outage. Given all of these concerns, we recommend not only that SPP and the Market
Monitoring Unit (MMW look into the reasons for de increasing outages, bur that a new
approach to gathering trammission wage data be created in order to provide an accurate
historical record of outages
C. EIS Market ResuIts
A3 is the nature of an imbalance market. a suk is made by a Market Participant when
either {a) it generates more than it has scheduled andor (b) its actual load is less than it has
scheduled. Similarly. aprrchme is made by a Market Participant when either (a) it Senerates
less than it has scheduled and/or (b) its actual load is more than it has scheduled.
For 2008, EIS Market sales totaled 15.1 million MWh, with a total cf S858 rniilion paid
to supplizrs. To put the sizs of the ElS Market into context, ovemll €IS Market sales [ 15.1
milIion MWh) were roughly equal to 8.5% of total energy requirements within the €IS Market
footprint.fi
If we iLgore the hct that tht EIS Market operated for just 1 1 months in 2007 in contrast
to a fulI 12 months in 2008. MWh sa& were up I@; and sales revenue was up 27%. In the
alternative: if we corrected this by comparing the same 1 1 months in tach ysr. MWh sales
increased hy 6.6% and sales revenue increased by 19?'nn.
Electricity prices are a result of rhe supply and demand for el2cuicit)f and the zbiliry of
the transmission "highways" to move electricity from the SOU~CK of supply to meet demand. We
analyzred prices in the €IS Market from mo perspectives.
The first perspective is to cornpar2 EIS Market pice to those in two neiyhboring. 14-
timit energy markets: those operated by the Midww Independent Transmission System Oprator
(MISO) and the Electtic Reliability CounciI of Texas (ERCOT). W's do not expect the prices in
hese markets to be identical to thost in SPP because of differences in resource&et mix, patterns
4
BOSTOY PACIFIC COMPANY. IW.

Exhibit TAG5
Page 12 of I17
of demand, and other Eactors including inherent design aspects of each mke~' However, prices
in these two markets give us onc measure of cotlspetitiw market prices and for that reason, we
want E1S Market prices to be in-line with MISO and ERCOT real-time market prices. We take
comfort in the fact that prices in the second year of €IS Market operation were generally
behvetrl prices in MISO and ERCOT. Specificallyl the simple average price- in the EIS Market
was $53.2 1 IMWh which is 19% below ERCOT's averase price and 1 1 % above that for MISO.
Ln c~mparison to 2007. SPP's shnple average annuat price increased by %.031MWh, while
MiSO's and ERCOT's prices increased by S0.67m3U'h and Sl2.64MWh, respecctiveIy. SPP's
off-peak price remained relatively constant. increasing by less than SlIMWb, while SPP's onpeak
price increased by almost 98MWh. Both ERCOT and MISO saw a similar pattern with
their on-peak prices increasing more than their off-peak prices. We believe that increases in
naml gas prices is one reason we are seeing larger increases in on-peak electricity prices when
compared to off-peak electricity prices. Average Panhandle natuml gas prices increased by
about 15% from 2007 to 2008. This is important because. in SPP, natural -ps-fired resources are
at the margin (and therefore setting the price) more during on-peak periods than duriny off-peak
periods. In 2008 in SPP. natural p was ai the margin abut 89% of the time during on-peak
periods. while ody 54% of rht time during off-peak periods.
The second perspective rakm on EIS Market prices is to assess how they vary across the
SPP €IS Mariqet footprim. Pnces vay across locations when there is transmission congestion
which breaks the SPP-wide market hto submarkets. Looking first at the Imations represented
by the ten b&c@ authority locations in the EIS Market footprint, we see that alI of these have
load-weighted average hourly prices which differ BO more than 13% from rhz SPP-wide
weightrd average hourly price of S57.421MW3 {note this is higher than the SPP-wide simple
average price of 53.2 I !MWh). SPS (364.6 1 NWh) and Board of Public Utilities, Kansas City,
Kansas l KACY) ($5 Lj7NwR:) had the highest and lowest prices, respectively.
Another look at the variation across locations takes a more granular view. In this view.
we look at prices at every load price location - not aggregated to balancing authority locations -
and for each five-minute dispatch internal - not the hourly prices. Here rve set that 92.7% of
these locational prices. by intmal. fall within what can be seen as an expected range of zero to
SlOO.:'M\h.'h. last year97.1% fell into this
Revmue Adequacy is a metric ussit by other R?Os and [SOs. The calculation
determines whether revenue carncd in 2008 in the EIS Market would have kert adequate to
cover the total annttalized cost for new investment in generation. That is. the Revenue Adequacy
metric dcttrmines whether €IS Market prices are signaling a nced for new cappacity with prices
that equal or exceed the cost of new entry. As with anv metric. however, it must be put inro
perspective.
BOSTON PACIFIC COMPAKY.

Exhibit T.4G-5
Page 13 of I17
We performed a Revenue Adequacy calculation for de €IS Market in 2008. We found
that, wen assuming a perfect dispatch response throughout the year. the €IS Market would not
yieId sufficient revenue 10 warrant investment in EW generation. This is me for both naturaI
gasfired peaking turbines and intermediate load combined cycle units. Ths is not surprising.
given the reIatively high insmIkd resource margin descnied previously.
Fuel Tj..
We look nt fuel type used in two ways. First, we iwk at actual L-neration toEtput) by
fuel type in the EIS Market fooprinr; that is, we m e each MWh back to the fuel used in its
generation. Second, we look at which fuels are at the margin or, in other words, which fuels are
reflected h EIS Market prices. Some assumptions were necessary to cakulate these mristics
due to data limitations. so these numbers should be Seen as estimates rarher than absolutes.
We found hat coal was responsible for 65.5% of the electricity output in 2008 in the EIS
Market footprint, while natural gas and nuclear were responsible for about 25.4% and 4.7% of
the output. respectively, Renewables such 8s wind and hydro accounted for 3.4% and 0.8%.
respectively, ofthe output in the EIS Market footprint.
While coal was responsibk for the most output. natural gas units were flT the mrrrgin in
SPP for the largest pcrtion of the time. Natural gas was at the margin approximately 70% of the
time, and coal was at the marsin about 30% of rhe time.
Full participation in the €IS Market is voluntq- Therefore it is essential to determine
the extent to which Market Participants are participating. We look at participation in thm ways.
The first is to deternine the percemge of resources that are offered for dispatch in the EiS
Market. In 2008, pamcipation was consistently at a robust lev& on avverage. 88% of installed
resource capacity was made available for dispatch in rhe €IS Market.' This is up from last year
when participation was 8 1 %.
The second masure of market participation is what portion of the capacip ofa resource
w a made ~ available for dispatch. Most power plants have a minimum level of opemation that
must be maintained takin to a car sitting at idle) and monw haw a maximum that fails short of the
fulI capacity of the mourcs (perhaps to reserve capacip- to nzet ancillary service needs). For
exaniplz. say a 100 MW resource is made availabblz to the mxket with a minimum of 30 MW
and a mavimum of 80 MW' (to Iswe 2Q MM; for ancillary service reserves). in this example, the
Marker Pankipant has made 50 MW or 50% of the capaciv available to th;. EIS Market. In
realie. in 2008 the aterage portion of available capacip made available for dispatch [the

E-xhibit TAG5
Pqe I4 of 1 t?
average &spurchC~hle mnge) was 46% (it was 4F! 1st year). This is a reasonable level of
dispaEhabIe range on an overall basis.
The third measure of market particiption indicates how fast the resource can be
dispatched up and down within its dispatchable range -this js termed "ramp rate" and is
measured in MW per minute. The MMU has expressed some concern about the ramp rates being
too low. However,
the Fall of 2008, average offered ramp rates increased. This Fa11
performance increases the average rarnp rate for all of 2008 to 2.8 MWlminute? which compares
to 2.5 MWlminute in 2007. We believe this increase is at least in parf due tu a rule change made
in October 2008. This rule change allows a participant to break up irs dispatchable range into as
many as IO se-peents and to provide a different up and down ramp rate for each segment. It is
not clear yet whsther this rule change is the driving force behind the increase in ramp rates over
the last few months of 2008. In additioa it is probably too early to conclude that these higher
ramp rates will be sustained in the coming months. The MMU states they wiIl continue to
monitor this situation.
The SPP Offer Cap is the most explicit market power mitigation tool imposcd in the EIS
Market. it Is imposed only when there is mansmission congestion. The SPP Offer Cap varies by
resource and by location - it is lower (tighter) in areas with more transmission congestion.
Moreover. since it reflects the cost of entering the EIS Marker by building and operating a new
combusticn turbine power plant. it also is a measure of the competitive price level that we would
not want to be exceeded in the EIS Market. Given this. we look at how often a price affer is
accepted neat the SPP Offer Cap. If this is common. then the SPP OfTer Cap is holding prices
down just like a lid on a pot of boiling water. In contrast. if price offers are seldom acceptzd
near the SPP Offer Cap. then w-e believe this indicates prices are comfortably Mow this one
measure ofa rump&iwppr-ice led. The bottom line is that price offers w m almost ncver
accepted near the SPP Offer Cap. h 2008, such offers were accepted in a wry small portion of
the time - less than four tenths of one percent of the available resource interials.
The FERC imposed a seepame offir cap thar applies at a11 times for all rcsourcccs. The
FERC Offer C q is S 1.ooOiMMrh. Price offers were accepted near the FERC Offer Cap in a
ntgIigible portion of the time -approximately three thousandths of one percm oftlie avaitablt
resource inm-vals.
€IS Marker rcsulrs also can be used to develop mditional. stnictural measures of the
potential for market power concerns. Three traditional mmures are: thz number of market
participants. the rnark~t shares of winnins Market Participants, and an antitrust measure ded the Herfindahl-Himhman Index (HI41 which is calculated as the srim of the squares of market
shares. '!j
A high number of Market Participants indicates a competitive m arh because it (a)
undermines collusive =hemes and (bl promotes asgressive bidding. The €IS Market had 27
Market Patkip& in 1008. which is a good number of campetitors. that is up from 11 h 2007.
11)
__-.I_

Ezrhibit TAG5
ParJe15of117
f 79
A high number of Market Participants with smaller market shares aka indicates
cornpetitivenm. For example, when judging when to grant a supplier the right to charge
market-based [as oppmd to cos-bstsed) rates, the FERC uses a market share under 20% to
support a rebuttable presumption that a supplier does not have the abitity to exercise maxket
power and, therefore, should be granted market-based rak authority. For 2M18.110 Market
Participant had a market share at or above MYo. The highest market she urn 14.7% (in 2007 it
was 18.4%). A& ?his is another indicator that h e ETS Market is a competitive market
A low HHt also indicates corripeiitivenixs. For example, the FERC and &e US.
Department of Justice use the same ranges of HHIs to judge the cowithe efkct of mergers
and acquisitions: an HHI at or behw 1.W is something of a safe harbor, an HHL from 1.000 to
1.800 indicates moderate market concentration, and an HHI above 1,800 indicates high
concentmuon. The FERC also uses a higher HHI threshold of 2.m when judging whether to
granr a competitor the right to charge market-based (as opposed to cost-based) rates. For 2008,
the AH1 was 1,037 as measured by winning market shares of sales in the EIS Markq this HHI is
just slightly above the ‘safe harlmr’ level of 1.080. Thee HHIs also indicate the €IS Market is
s ~ c ~ competitive. ~ I y
SPP’s Open Access Transmission Tariff (OATT or Tariff) requires fhat the €IS Market
remain revenue neutral. This simply means that it cannot collect more money from Market
Participants than it pays out and vice versa. If SPP either over collects or under colkc&. it must
apply an uplift procedure to return to a revenue neutral sate R?; either collecting additional
money from Market Participants or returning money to Market Participants.
There are five components to Revenue Neutrality Uplift (RN U). which determine
whether SPP over collects (RKU is negative) or under collects (RNU is positive): i) €IS, (i>
self-provided losses. (iiil over-scheduling charges, (iv) under-scheduling charge. and tv)
uninstructed deviation IUD) charges. The majority of RNU occurs as a result of the €IS
component. The €IS component reprevents 78% of all RNU contribution (positive or negative)
in 2008.
Because RNU ultimately affects bow much participants pay, we cdculated an all-in price,
which represents the load-weighted SPP average price adjusted for net RNU divided by total EIS
MWh (salts plus purchases), As discussed later. the RNU adjustment (a) allows congestion
costs that were not effectively imposed on Market Participants through schedule adjmmsnts to
be accounted for and (b) allows over- and under-scheduling and LID charges to k accounted for.
The largest positive RNU adjustment occurred in November and &as S1.66MWh. which is 4-694
ofthe November averase price. The b est negatit-e RNU adjustment occurred in March due to
a very large negative €15 component. This adjustment was a negative S2.361MWk which is
3.7% of the March average price.
.’: . i- i; ,
8
BOSTON PACIFIC COMPANY. 1NI’

D. Energy Delivery
Transmission system are the “highways” that bridge suppliers to customers. As
expected in any region. the number and capability of these ‘‘highways” vary across the SPP
fOQQ&
E-uhibit TAG-5
Page IG of I 17
1 t;tl
Under its OATT. SPP grants transmission service over the transmission systems owned
by its members. In return, SFP’s transmission-owning members receive revenues for the service
granted by SPP. The total revenue received by mmission owners in 2008 was approximately
5408 million. Together, on average, the mansmission owners received roughly $34 million of
revenues each month in 2003.
SPP primarily grants access to the trammission systems of its members based on
flowgates designated by SPP and its members. Flowgates are combinations of critical
rransmissioo clemns that represent a proxy of the transmission system Flowgtes have
separate limits for firm and non-firm transmission =mice. Portions of Transmission Reliability
Margin iTRM) may be sold on a non-firm basis. but not on a firm basis. TRM is capacity
withheld for reserve sharing events. TRM Iwels can be substantial portions of the total limit €or
certain flowptes in SPP. In 2008. the flowgates in SPP wirh the highest TRM levels, as a
percentirge of the total fl owgate limit. were the Valliant Transformer (82%) and the Seminole
Transformer (63W). In comparison to 2007. bath of these transformers experienced a large
increase in 2008 in TRM as a pcrcenmge of the flowgae limit. This is the result of the TkM
value for ValIiant increasing from 70 VW In 2007 to I83 MW in 2008, and the TRM value for
Seminole increasing from 14 MU; in 2007 to 281 MW in 2008.
Through a quest process, partits who wish to movt electricity over the transmisssicn
system rcqutst this service in advance. SPP wiil approve these requests if it can do so whik
ensuring rzliabiiity and simultanmus feasibility; that is. while assuring that the capabiliy of the
tmismission systems of its members io move electricity is not exceeded. WhiIs the tutal number
of transmission service requests in SPP decrcascd by 1 1% from 2007 10 2Oi)K the number of
approved requesrs in 2008 was higher than the comsponding approvals in 2007. In addition.
SPP’s approval rate. measured as a ratio of approved requests to the sum of approved and
refused requests, also increased from 2007 to 2008 From 54% ro 67%.
Transmission congestion on the 5PP transnlission system causes locational price
divergence. Transmission congestion is pervasive in the EIS Market. indicayting relatively high
overall utilization of the existing transmission system In order to understand just how prevalent
congestion has been over time. we Iooked to see how often there was ar least one flowgate
9
BOSTON PACIFIC COMPANY. M’.

Exhibit TAG5
Pqe 17 of 117
experiencing congestion in each five-minute dispatch interval over 2008. We found that there
wa at least some congestion 56% ofthe time: this is the same percentage of time as last ym,
However. it should be noted that this could be an overly strict metric in the sense that it only
takes problem at one flowgate to indicate congestion over all of SPP.
A second way to understand the pervasiveness of congestion is to look at whether there is
congestion at many flowgates or at a small number of flowgates. In 2003, we found that 75% of
the congestion occurred on just 10 flowgates (out of a total number of over 200 flowgates2 The
same percentage was found in 2007, although four of the top ten are different in 2003 than in
2007.
We are pleased with the increasing transparency on h-ansrnission congestion. Indeed, the
biggest improvement is in how SPP links kvestment to congestion. That is. the biggest
improvement is that SPP (a) identrfies where congestion drives up EIS Market prices the most
and (b) hen identifies what actions (investment) is being planned to mitigate that congestion-
SPP has created an active transmission expansion process both to ensure rzIi&iIity and to
increase the deliverability of cost-effective (%zonornic") generation resomcs. For the period
from 2009 to 20 18, approximately 32.7 billion of transmission invesment is included in the
STEP.''
In addition to the STEP, SPP, Quanta Technologies. and Powertt'orld completed a
longer-range smtegic assessment in 2007 regarding reliability and capciv needs through th2
use of 345 kV. 500 kV, and 765 kV lines. This Extra Hi& Vdtage (EHV) OverIay Report was
updated in March 2008 to evaluate. among other things. la) the impact of higher levels of wind
devt-clopment and (b) a 345 kV overlay option rather than the 765 kV loop proposed in the first
stud?;. A new EHV smdy was compkted in December 2008. and used the prsvious EHV
Overlay studies as a starting pint. This study. however, focused on the economic impact of the
EHV Overlay. Cost dlocation discussions regsrding the EHV Oterlay are currently underway.
These decisions will be exumxly important given tht large aniounf of money that will be
required to build thtsc transmission lines.
We have encounyed SPP TO make the Transmission Market more mnsparcnt. SPP has
consistently improved thar mprency and again did so in 2008. With reqect tv transmission
investment. we were able to trace the investment funds to specific purposes and facilities. For
example. close to $800 million of investment is planned for 2009. We were able to trace $433
million to two major project types: (a) about 5243 million in for "Economic"' investments - those
aimed at delivering low cost power and (b) about SI 90 million to integrate the new Kebraska
members.
We also nme that SPP has created the Synergistic PIaming Project Team (SPPT) to
*holistically' address the coniprehensit-e transmission planning prxesses. th: allocation of

transmission costs, and related strategic issues. This high-level team reports to both the SPP
BOD and the RSC. In addition, SPP has increased its activities with other partits regarding
inter-regional expansion planning and oversight of the overall Eastern Inte~onnection. including
the Joint Coordinated System Plan (JCSP'O8) and the creation of a new inter-regional steering
commitlee and work teams."
E, Recommendations
Wc thought it wouId useful to step back from all the details presented so f&r and draw out
some recommendations. We first look back at 2008 and make six recornendations based on
that experience. We then look forward and recommend three issues that the Board will want to
be watch+ as it anticipates events that could significantly affect prices and reliability in SPP.
Remmm endaibns Looking Eack
We draw out six recommendations based on our detailed look back at 2008. First, the
€IS Market continue to be a siiccess and. concomitantly. the pmtss by which it was designed
and approved was a success. As we recommended last year. that success should give the SPP
Board and members the confidence to accelerate efforts toward creating new markets.
Second. another success for SPP is reflected in the significant new investment in
transmission that is planned over the next ten years. We recommsnded last year that. to keep and
expand suppm for that investment, the strategic or poiicy goals served by that invesmnt should
be highlighted - for example. tie it to relieving congestion at specific flowgates or to
acc-ornodating new wind power generation. SPP has made great progress in this regard.
However. in another area. SPP has not made progres in reporting the reasclcs for increzing
imnsmission outages in SfP. Once again. we recommend that a rnsthod should be developed for
collecting historical outage da!a and the reasons for outages should be routinely recorded and
published.
Third, the sitccess of wind power in the SPP area should be both celebrated and managed.
Some of the best wind resources in Anierica tic within the SPP fooQrint; wind already accounts
for 3.Wo of generation in the €IS Market footprint. Interesr in wind power development is
intensifying because of (a) State RPS (and possibly a FederaI RPS). { b) the pspects for ~tobal
climate change legislation. and (c) enhancements in tax benefits. Thc Board will continue to
face decisions on substantial transmission investment to accooimodarr wind. Some of that
investment may be to support wind power worts mcl added an5wers to 'who gays" might bs
needed;'> in this regard. we recommend reviewing the FERC's constructive decisions on
TransCanada's Chinook and Zephqr transmission lines. The Board also will face operational
ksuss: operational issues will bt addressed by SPP's Wind Integration Task Force t WTT;).
Fourth. driven primarily by the success with wind, SPP's methods for prioritimion of the
wneratioi: interconnection queue must be changed. Firstcome-first-xrvrc! is not in the best
?
interests of the consumers or suppliers. We recommend that SPP allow adymced prajects -
BOSTON PACIFIC C'OMPAYY. wc-.

projects that (a) have already secured a buyer for output or (b) have met certaio milestones - to
move past projects that are not as far along. The Generation Queuing Task Force (GQTF) is
working to refmn the current process.
Fifth, while it is not an imminent probiem. we recommend that the data some used to
update Offer Caps be changed. SPP now uses data from the Federal Government which has not
kept pace with red-wodd increases in construction costs or with changes in tEhnologies. One
alternative would be for SPP to collect and review updated, public Inteyated Resource P h
( IRPs) which routinely include capital and opemting costs of generation technologies- SPP could
dso invite cost proposals from members on their hands-on experience.
Sixth, we reconmend stricter standards for reporting seasonal capabilities for wind
generating units. CurrentIy, we calculate capacip using the summer capability of units reported
by the members. The SPP Criteria {Latest Revision: January 27,2009) states that summer
capability tests must be conducted once every 3 years, with the exception of wind plants and
"run-of-the-river" hydro plants which are not required to perform capabiIip tests. While Section
12.1.5.3 (6) of the Criteria provides the procedures for establishing net capability ratings for
wind, part (VI of this section states, -If the Member chooses to not perform or provide the net
capability calculations to SPP as described above. then the net capability fcr the resource will be
0 M W." It appears that some members have chosen this option. and therefore we think this is
one reitson why the amount of wind reporkd in the EIA 41 1 report is most Iikely underestimated.
At present, this is a relatively minor fixtor. However. as wind development continues in SPP, it
will become more important for there to bs accurate assessments ofseasonal net capabiIities for
wind units.
Recurnmenduriom Looking Forward
The Board also has to anticipate broad market and regulatory events that will affect the
performance of SPP's markets. While a lengthy discussion in this report may not be appropriate.
we would be remiss if we failed to at least identify the broad issues on the horizon. These events
include (.a) federal climate change legislation, {b) expansion of wind generation, and IC)
significant incentives for all rsnewables investment. In addirion- we make brief mention of a
possible surge in generation and tansmission investment. in a time ofrising interest rates and
inflation.
With respect to climate change. the points to not2 art that the charqe in Adminismrion
has made legislation more likely and such legislation would affect prices in the €IS Market. As
to its likslihoud. note that the President's 2010 budget includes estimates of revenues from a cap-
and-tnde program in 2U12.'4 As to price effect. the rang of estimates for different cap-and-
trade prognms is very wide. Just as a quick point of reference:. news repcm have estimated
whal the President's budget asitmes for a carbon-dioxide emission price." By our calculations,
BOSTON PACIFIC COMPANY. IN

Exhi bil TAG-5
Page 20 of 117
using the high end of the estimate in 2009 dollars. this wouId add about (a) S 181MWh to the cost
of conventional coal generation, (b) SWWh to the cost of naturai gas-fired combined cyde
generation. and IC) S 12/MWh to the cost of natura1 gas-fired combustion turbine generation.
With respect to the expansion of wind generation, SPP has already seen rapid growth. In
2008 nearly 3,000 MW of wind capacity accounted for 3.4% of the elhcity in SPP's EIS
Market footprint. The
-
point to note is that the mandates and incentives for rencwhles, in
general. and Wind. in phcuhr, are only getting stronger, Twenty-nine states and the District of
CoIumbia have RPS mandates. There is a proposed NationaI RPS which would require 25% of
America's energy to from renewables by 2025.16
In addition, as also discussed in Section V, wind generation will benefit from significant
tax hntives. It will also benefit from volatile natural gas prices and cliraac change Iegislatiun.
Finaily, the need for new generation and uansnixssion investment is becoming evident.
We have already nmd the substmtiai transmission inwstment and potentiaI wind generation
investment in the SPP foolprint. The point is that this investment could be made in a time of
rising interest mes and inflation. While we are not saying (and do not hope) this is the most
likdy scenario, there is concern that (a) many utilities will build all at thr: same time, (b) the
factors which drove up cunsmtion commodity costs (primarily Chinese dzmand} will remain or
return. and (c) the monetary and fiscal stimulus used to get the U.S. out of the current financial
crisis, might lead to higher interest rates and inflation.
13
BOSTUN PAC1 FIC COMPANY'. rNc.

A. Brief Overview of SPP
r. OVERVIEW OF THE SPP FOOTPNNT
Exhibit TAG5
Page21 of I17
The Ssuthwest Power Pool (SPP) was granted Regional Transmission Organization
(RTO) status by the Federal Energy Regulatory CommisSion (FEBC) in October 2004.” SPP
provides transmission service on the transmission facilities owned by its members under its Open
Access Transmission Tariff (OATT or Tarif€). In addition, SPP is a North American Electric
Reliabiliq CorpCraticn (NERC) Regional Entity (RE). The SPP RE area is usually what is
referred to when discussing the SPP footprint, and is the footprint discussed in this Section
(Section I>. In February 2007, SPP launched its real-time Energy ImbaIaoce Service (EIS)
Market. Thz EiS Market does not cover the whole SPP footprint. and so this is referred to as the
€IS Market footprint. SPP is also in the process of developing a Day-Ahead Market and an
Anciliary Services Market. These markets are tentatively scheduIed to be launched in the second
hatf of 20 12.
SPP is located in &e southwest portion of the Eastern Interconnwtion. lt is bordered by
the Midwest Reliability Organization (MRO) and the SERC Rehabitit), Corporation (SERC) in
the Eastern Interconnection. SPP ais0 shares borders with the Western EIectricity Coordinating
Council (WECC) and the Texas Regional Entity (TRE). Figure 1.1 shows th? four KERC
Interconnections and the eight Regional Entities.

Fignre 1.1.
MEW INTERCONNECTIONS
Exhibit TAG4
Page22af 117
As seen in the figure above, the SPP RE region is centered on Oklahoma and Kansas.
Spurs extend (a) soutl~ward into northwest TexasEastern New Mexico, (b} eastward into
Arkamas and Missuuri, and (c) Youthward into northeastern Texas and Louisianai8
SPP has 54 members who serve toad. provide generation supplies, andor own
transmission facilities. SPP's members include cmperativcs, municipals, state agencies,
independent mnsmkion companies, investor-owned utilities { IOUs], independent power
producers (IPPs), and power marketers. There bave been a few changes in membership since
2007 when there were 50 members in SPP. Since then, SPP has added five new members and
lost one member. The most notable additions were three Nebrstska entities. These companies
include the Nebraska PubIic Power District (NFPD), the U d a Public Power District (OPPD},
15
." BOSTON ... .......,.. . PACIFIC
... ...... " .... . -. COMPAN?:
,. " ," ..,,. ., ...-., *-,. IM' ,..... . .?

E~bit TAG-5
Page 23 of 117
and Lincoln € 1 6 System ~ (LES). NPPD and OPPD are state agencies, while LES is a
municipal. The tHro other new members are IPPs. These companies are Acciona Wind Energy
and Dogwood Energy, LLC. Redbud Energy, on the other hand, was an IPP in 2007, but was
purcbmed by Oklahoma Gas & Electric (OWE), Grand River Dam Authorig (GRDA), and
Oklahoma Municipal Power Authuhty (OMPA) in early 2008. A count of SPP members by
category io shown in the table below.
Table I1
SPP MEMBERS AS OF APRIL 2009
A list of SPP's members as of April 2009 is also attached to this report as Appendix B.
Balancing Authudks in W P
The SPP RE foovrint is comprised of 16 balancing aurhorities (including the
Southwestern Power Administration (SWPA)h which are operated by IOUs, cooperatives.
municipals. and state qencies." In essence, a baianciny authority is responsible for managing
the minute-to-minute supply!demand balance for electricity with in its borders to assure
retiabiiity. A rough approximation of the Iocations of these balancing authorities is shown in
Figure 1.7,.
16
BOSTON PACIFIC: COMPANY. IN('

Figure 1.2
MAP OF SPF BALANCING AUTHORITIES
._ -- -
.
r
..
. .
L - . -
17
r
..“*l. *?... ,..: . .
Exhibit TAG5
me24of 117
..
- -
BOSTON PACIFIC COMPAW, INC.
I

B. Customers - The Demand for Electricity
Peak Demand and €new Usage by MOR&
€*bit TAG5
Page 25 of 117
Table 1.2 shows that the peak demand in SPP was 42.89 1 MW. This peak occurred in
August 2008, which is consistent in timing with previous years in that the peak in previous years
aIso occurred during the summer. Ftak demand in 2008 increased by 0.734 as compared to peak
demand in 2007. This growth is equivalent to that of 2007. which also had a peak d emd
growth of 0.7%, but much slower than the 5.2% peak demand growth in 2006. Over the last 7
years SPP has experienced an average annua1 increase of 2.2% io peak load.
On average, the monthly peaks in 2008 are 0.2% lower than the corresponding peaks in
2007. The lowest peak in 2008 occurred in the spring as it did last year. The highest peaks
typically occur in $he [ate summer months as the demand for electricitqr is large due to cooling
needs on the hottest days of the year. To document this point, note that the peak h August 2008
was 69. I % higher than the peak in the lowest month of the year, April. This also ilfusb-ates the
spread in peak load across the year.
Table 1.2
MONTHLY PEAK ELECTNC
ENERGY DEMAND (MW) FOR SPP
Table 1.3 displays the total electric energy used each month for ZOO1 to 2008. In 2008.
electricity usage was 208.3 million MWh. While energy usage is highest in :he summer. it does
not peak a3 sharply as demand; the electricity used in JuIy. the month with the highest total
usage. was 48.5% higher than the lowest month November. TotaI energy usage increased by
0.5”/0. or 1.056.374 MWh. in 2008 as compared to 2007.
18
3 83
BOSTON PACIFIC COMPAYY. r x .

Exhbiit TAG-5
Pqe 26 of 117
A comparison of the number of heating and cooling degree bays, which serve as an
indicator of the demand for electricity due to extreme weather, was made for two of SPP's
largest load centers, Kansas City, Missouri and Oklahoma City. Oklahom"' The total number
of heating and cooling degree days increased fmm 2007 to 2008 by 3.2% in Kansas City and
1.3% in Oklahoma City. However, the overall increase in hating and cooling days was due to
an increase in heating degree days as the number of cooling degree days actually declined in
2008. This is the second year in a row that we have seen the number of heating degree days
increase and the number of cooling &gee days decrease. This could help explain why total
usage in the winter (January, February, and December] increased by 30/, while the total usage in
the summer (June, July, and August) only increased by 0.6%.
Over the last 7 years. SPP's total electric energy usage has increased. on average. by
almost 2% a year. This is higher than the national merage annual increase of 1.3% over the
same period according to EIA data. It is also interesting to note that the EM przdicts a national
decrease in usage of 1 .F% in 2009, while an overall increase of 1% annually from 2007 to 2030.
To put SPP's usage in perspective, the national usage in 2008 ww around 3.9 bilIion MWh.
meaning SPP's total usage accounted for about 5?4~ of all the electric energ consumed in the
The load factor was 55.3% for SPP as a whoie in 2008. Load factor is the total electric
tnersy usage (208,348.298 MWh). dividzd by the product ofthe peak electric energy denrand
141,891 MW) and the number of hours in h e year ( 8.784).12 This means tha: in SPP the 2008
average hourly demand was 55.3% of the annual peak demand. The purpose of a load Facror is
to assess the amount of entrp consumed. in fern of an average demand le\

Table 13
TOTAL ELECTRIC ENERGY
USAGE IMWHj WITHM SPP BY MONTH AND YEAR
Exhibit TAG5
Pqe 27 of I17
Table 1.4 displays each balancing authority’s peak demand and energy usaze in 2008. In
SPP. American Electric Power (A€€‘%’) is the balancing authority with the most electric energy
usage with 22.3% of rhe SPP total in 2008, Oklahoma Gas & Electric (OKGE] f 14.5%),
Southwestern Public Service Company (SPS) ( 14.4%). Westar Energy, Inc. I, WE RE) 14.1 %I).
and Kansas City Power & Light (KCPL} (7.8%) are the next largest in terns ofetemic energy
usage. Together. these five balancing authorities account for 73.1 YO of the SPP total in 2008,
which is comparabk to the 73.1% and 73.0% in 2006 and 2007, respectively. These same five
balancing authorities also had the highest peak demands. ranging from 10,080 MW for AEPW to
3.61 5 MU’ for KCPL.
20
191
BOSTON P AiiW COMPAW. IW

Pattern of Demand
Table 1.4
BALANCING AUTHORITY DEMAND AND
ELECTRIC ENERGY USAGE IN 2008
Exhibit TAGS
Page 28 of 1 I7
Figure i.3 provides a graph ofrhe mrtlrimum and minimum hourly clecrricig demand per
day. As could be expected from the discussion above, the daily maximum electric demand
varies significantly across the seasons of the year. Similarly, the daily minimum electric demand
varizs by season in the same manner as the daily maximum clcctric energy demand throughour
the year. In addition. the difference betwetn rhz maximum and minimum daily electric demand
widens during the summer with a maximum swing over the three-year span of 17.438 M W.
occurring in July 2008. This difference narrows durin: the rest of the year and reached the
lowest daily demand swing of 2,590 h4W in April 2007. The avenge daily difference for the
threeyear period is over 8.OOO MCI;'. and over 13,OOO MW if we just include the summer montk.
It is these swings acms seasons and across the hours of the day. plus the fact that electricity
cannot bt: stored. that necessitate moment-by-moment balancing of suppIy and demand by
balancing aurhoritks in SPP.
21
BOYfON PACIFIC COMPANY. RJC"

Table 1.4
BALANCING AUTHORITY DEMAND AND
ELECTRIC ENERGY USAGE M 2008
Sr HJRCB: SPP: Srlf-rzprtud data by thc mcmbcr;; and eDN.4
Pamm of Demnnd
Exhibit TAG5
Pagetgof 117
Figure 1.3 proTildes a graph of the maximum and minimum hourly electricity demand per
day. As could be expected from the discussion above, the daily maximum electric demand
vanes significantly across the seasons of the year. Similarly. the daily minimum elscrric demand
varies by season in the same manner as the daily maximum electric energy demand throughour
the year. In addition. the difference beti$ etn the maximum and miniinurn daiIy electric denland
widens during the summer t~ ith a maximum swing over the threr-year span af 17.438 MW.
occurring in Juiy 2008. This differencz narrows during the rest oftht year and reached the
lowest daily dsmand swing of 2.590 MW in April 2007. The average daily difference for the
three-year period B over 8.000 MW, and over lj.Oo0 M W if we just include the summer months.
it is these swings across seasons and across the hours of the day, plus the fact that electricity
cannot be stored. rhat necessitate moment-by-moment balancing of supply and demand by
balancing authorities in SPP.
21
3 92
BOSTUN PACIFIC COMPANY. IN('.

Figore L3
SFF DAILY MAXIMUM AND MINIMUM
ELECTRIC ENERGY DEMAND BY HOUR FROM 2006 TO 2008
Exhibit TAGS
Page28of117
193
A load duration c m , which is a distribution of hourly electric energy demand by
demnding order m&er than by chrooological order, is shown in Figme 1.4. It is designed to
show the numb of hom on the horizontal axis in which bad is eqd to or exceeds the MW
level on the vertical axis. This bad duration cwe for SPP in 2008 shows that laad ranged from
a kow of approxim?eIy 15,000 MW to a high (the peak) of 42,891 MW. In order to display how
often the load is within certain MW ranges, we b e broken the ddon curve into colors for
each 5,000 MW range. Looking at he figure, going from right to kft, we can see that SPP's
load was beween 15,ooO MW and 20,OOO MW in 20% of the hours in 2008. The next part of
the curve flattens out signXcmtly where we see &at lmd was between 20,OOO MW and 25,OOO
MW for half of &e burs. We scc load was between 25,OOO MW and 3O.W MW €or 1o"h of
the hours in the year. The next two pats of the cum kgh to display how demd reaches
certain load tevels for only a sdl number of hours in the yea. This is impmiant because SPP
needs to have anough capacity @Ius reserves) to meet these high demd teveIs even if they
occur only a few hours a year. Looking again at the figure, we see hat for 7% of the hours load
is between 30.000 MW and 35,000 MW, and, for the top 3% of hours when laad is at its greatest,
22
BOSTON PACIFIC COMPANY, IKC.

Ehbh TAG-5
Page 30 of 117
we see a range from 35,W MW to 42,891 MW. Note that this range for th~ top 3% of hours
(7,89l~~isgreaterthanzhe5,000MWrange.
45,000
40,000
35,000
g 25.000
2 20,000
9
d
I5;OOO
10,000
5,000
0
Figure 1.4
SPP ELECTRIC LOAD DURATION CURVE FOR 2008
I
A. c
I . . 4 I I a , 7---7 T z , r 1 , r I
0 1,000 2,000 3,000 4,000 5,GOO 6,000 7,000 8,000
C. Generation - The SuppIy of Electricity
Number ofFimrs
As seen in Table 1.5, the total installed gemming capacity within SPP's fmprint is
57,765 MW; 39,439 MW of which, or 68%, is located in the following five balancing
authorities: AEPU', OKGE, WERE, SPS, and KCPL." The same five balancing authorities have
the highest total MWR usage and peak.
23
BOSTON PACIFIC: COMPANY, INC.
!
I
!
f 94

Exfii bi t TAG5
Page 31 of 1 I7
Table 1.5
CURRENT INSTALLED GENERATION CAPACITY BY BALANCING AUTHORITY
As previously noted. in 2008, SPP had a peak demand of42,891 MW. Given 57,765
MW of generating capacity. this means that here is 14.874 MW of generating capacity in excess
of peak load within the SPP footprint. This excess generating capaciv above peak load is called
a resource margin. Expressed as a percentage, ths installed mource margin in the SPP fooQrint
is 35% of peak load.
It is important to note, however. that this capacity includes some generating units that are
not necessarily dedicated to serve load or, due to finite transmission capability. are not
deliverable to meet all loads at all times. This capacity presently consists primarily of I PP
capaciry which is nor included within dzliverabiiity (transmission expansion) studies, and as such
reflects ‘less firm‘ deIiverability to nemork load. The EIA 4 1 1 report data r em this capaciry as
“uncemin capacity”, and estimates that about 9,OOO MU: of the total falls into this category.
24
BOSTOK PACIFIC COMPAXY, INC.
.I 95

Exhibit TAG5
Page 32 of 1 17
.t 9;
Furthermore, the installed total does not account for firm purchases and sales of capacity. If we
adjust our total for net fm purchases and sales (approximately positive I$jO MW) and remove
the "uncertain capacity" N-e can calculate a different, albeit highly conservative perspective of
resource margin. Doing this we get B total capacity number of about 50,600 MW. When we
compare this to &e peak demand of 42,89 1 MW. we get a resource margin of 18%. A robust
resource margin has important potential ramifications for both reliability, economic delivery, and
for mitigation of the potential exercise of market power within SPP.
Gerreration Capaeify by Fue! Type
As seen in Figre 1-5, natural gas is the primary fuel for 55%, or 3 1,488 MW, of the total
generating capaciq in SPP. Ofthis natural gas-fired capacity, 31% can be found in the AEPW
balancing authority and 1 W o is located in the OKGE balancing authority. Cod is the secondmost
prevalent fuel source of capacity in SPP representing 35%, or 20,088 -MW. AEPW
contains 18% of the coal generation capaciw, while KCPL, OKGE, and WERE each have IS%.
While hydro generation capacity is just 5% of the total, W/O of the hydro generation is hated in
the SWPA bdancing authoriq. Wolf Creek is the onIy nuclear facility in SPP; it is located in
WERE'S bdancing aurhoriry." See Appendix C for a complete breakdown of capacity by
balancing authority.
25

Figure L5
CURRENT IPr'STALLED GENERATION CAPACITY BY FUEL TYPE
Figure 1.6 meals that 73% of the generation capaciw currently opted in SPP was buiIt
prior to 1990. Nearly ail of the coal units in SPP were built prior to 1990. The 1970s was the
decade with the most consmtion, with approximately 16,900 MW of SPPs cmmt on-line
generation having been built. Very little capacity was built in the 1990s: but there has been a
surge through the 2000s. Most of these new gznemhng units are natural gas-fired facilities and
are primarily responsible for the substantial insralled resource margin in SPP. Jkre has also
been an emergence of windgowered generation in recent ytm. With the potential for new wind
generation facilities in SPP, cmstruction during the 2oooS is expected to continue to increase.
However, as mentioned previmsiy. due to the fact that some ofthe wind capacity in SPP was
attributed 0 MW of summer capability in the EIA 41 1 data the mount of wind in this figre is
most likely understated. It is also important to note that over 12.500 MW of capacity in SPP was
built prior to 1970- After more than 39 years of operatim. some retirements might be
considered. Retirements could redwe he substantial resource margin in the region.
26
BOSTON PACIFIC COMFAW, INC.
f 97

.if
I
MOD -I
I I
Figure 1.6
CURRENT IPJSTALLED GENERATION
CAPACITY 3Y INSERVICE YEAR
-
SOURCE: Prr- 2009 SPP HA 41 1 dnto
Exh~bit TAG5
Page34of 117
The earlier examination of the amount of generation reveals, at the surface, a resource
margin that would appear to allow for an increase in load without requiring the construction of
new genenition. However, the economics of electricity generation, not jw a growth in demand,
drive interest in constructing new generation. This is evidenced by over 60,000 MW of new
capacity seeking gemtion intercomedon studies, of which over half entered the queue in
2008 alone. We believe upward pressure on fuel costs (until recearly) and global warming
co~lcem have been prime contributors towards interest in new capacity, especially in the form of
wind and more efficient namd gas generation. In addition, there is also the potential for a
mtional Renewable Portfolio Standard ( WS) mandate, which could also be increasing interest in
wind generation development in SPP.
S P P’ s Guidelks for Generutbn In fercom&m request^ to SPP 5 T~umrnission System
outlines he curcent procedure and process for applicants to request generation interconnection.
In order to execute a Generation Interconnection Agreemmt. three studies must be completed. A
Feasibility Study assesses the practicality and costs involved to incorporate the proposcd
generating mi+) into the SPP Transmission System. The esdts of this study may be a list of
27
BOSTON PACiFlC COMPANY, INK.
f 9s

Exhibit TAG-5
Page 35 or I17
proposed system upgrades needed along w!ith initial cost estimata. A System Impact Study is 399
primarily a Transient Snbility Study of the Generation Interconnection Request. FinalIy. a
Facility Study consists of SPP or the Transmission Owner specifying and estimating the cost of
equipment engineering, and construction to implement the interconnection. Upon completion of
the Facility Study, an applicant may proceed to execute a Generation Interconnection
Agreement.
The high d emd for generation interconnection has put stress on the cmnt generation
intercomechon process causing longer process times for requests and, as a result, a backlog in
the queue. Other RTOs and ISOs hve also been facing similar problems. so much SO that the
FERC heid a technical conference on interconnection queuing practices on December 1 I, 2007
in response to concerns about the effectiveness of queue management. Following the technical
conference, on March 20,2008, the FERC issued an order directing the RTOs and IS& to fiie a
status report on their efforts to improve the interconnecrion process - SPP filed its status update
on April 2 1.2008. In its filing, SPP gave several reasons for the backlog in the queue. These
include, but are not limited to, the fact that projects that are not yet commercially viable have
been progressing slowly through the queue and the large increase in the volume of requests
making it difficult to process all of the requests in a timely fashion.
SPP has formed the Generation Queuing Task Force (GQTF) to help refarm the prwes.
We understand that thr GQTF is currently working on solutions to improve t3e process. We
recornend that instead of ~ shg a "first come, first served" msrhod, SPP shculd allow advanced
project< - projects that (a) have already secured a buyer for output or (b) have met certain
milestones - to move past projects that are not as far along.
Table 1.6 show-s die tota1 number of projects and capacity that ate curranly in the queue.
We see that 252 pmjzuts are currently active or have executed an interconnection agreement.
representing 60.220 MW ofcapacity.25 This is a significant amount ofcapacity. To put this
number in perspective, the peak demand in SPP in 2008 was only 42.891 MW. Of all the
projects in the queue. 9.368 MW of capcity have fully exzcuttd an interconnection agreement,
and are nor on suspension. Historically, as would he expected, not all of the capacity that enters
the queue ends up being built. Since 2000.405 requests have been submittee for I 12.258 MW.
Of those, 153 (or 38?4 ofthe total requests) have ken withdrawn, accounting for 52.033 MW (or
46% of the total MW).
28
BOSTON FACIF;C COMPANY. LM'

herconnection
Table 1.6
STATUS AKD CAPACITY OF ACTIVE
GENE RATION INT E RCUNN ECTION REQUESTS
Exhibit TAG-5
Page 36 of 1 17
Figure 1.7 illusrratrs that of the capacity in the generation interconnection queue, the
largest share is in SPS. which represents roughly one-third ofthe capacity in the queue.
29
BOSTON PACIFIC COMPANY. IF('

Fgure 1.7
ACTIVE REQUESTS FUR GENERATION INTERCONNECTION:
CAPAC€TY BY BALANCING AUTHORITY FROM 2001 TO 2008
Eshibit T.4G-5
Page37of 117
As seen in Figure 1.8. among current requests, 82.3% of the capacity in the qwue is for
wind projects, while natural gas and coal represent 1 LZ0h and 5.8?4 respectively. Appendix D
breaks down the capcity of all interconnection requess by fuel type and year ofthe request
(Note that here. wind capacity is stated in nominal terms.)
30
201
BOSTON PACIFIC COMPANY, INC.

Figure I.%
TYPE OF ACTNE GENERATION INTERCONNECTION REQUESTS
Generadian Capmity - Outages
Exhibit TAG5
Page 38 of 1 17
Generatrng facilities are occasiondly taken out of service for maintenance (maintenance
outages), and they are dso shut down from time to time due to equipment failures. These sudden
outages due to equipment failures are called forced outages. Generation outages decrease the
amount of electricity supply wailable to meet demand. Therefore. the reason we look at
genemtiun outages is to make sm that participants are not physically withholding generation,
specially during peak periods, which could cause prices to increase.
Table 1.7 repom the extent of generation capaciry oumges that occurred on the same day
as the monthly peak load in SPP during 2008. The table reveals an expected pattern. During the
summer period (June to August), when peak load reaches its hi@est, maintenance outages are at
their lowest levels. This is mostly due to the fact that planned maintenance outages are
3t
BOSTON PACIFIC COMPANY. TXC.

E&bh TAGS
Page39of I17
scheduled outside the swer peak period and coordinated by SPP in order to maximize
available capacity during the periods it is needed most. In fact, the amount of capacity
unavaiIable due to forced outages exceeds that for maintenance oueagts during the summer
period, whereas in most other months maintenance oubges exceed forced oubges. As seen
below. the average total outage (average of the 12 days) as a percenwe of avera e eak load
(averase of the 12 peaks) for 2008 was 13.1%. This compares to t2.8% in 2007.
$6
Table L7
GENERATION OUTAGE DATA COINCIDENT
WiTH PEAK LOAD BY MOhTH FOR 2008
D. Transmission - The Bridge bemeen Supply and Demand
There are primarily sewn transmission voltages used in 5PP: 500.345,230, 151, 138.
115. and 69 kV.
The 64 kV voltage is the most prevalent voltage level in use throughcut SPP, Most of the
Transmission Owners in the SPP region use 69 kV systems to deliver power to lower voltage
transmission and distribution systems."
32
BOSTON PACIF!C COMPANY. IM'.

Exhibit TAG5
Page 40 of I17
At the opposite end oftbe specnum is a 500 kV transmission bus. The 500 kV line is
used to interconnect the OKGE balancing authorhy with Entergy’s 500 kV high-voltage system
Transmission facilities at 345 kV form the backbone of the -mission system in much
of SPP. This backboae prhady connects h e transmission sysfems in the AEPW, OKGE,
WERE, and KCPL balancing authontim in eastern SPP. Certain balancing authorities in eastern
SPP, such as Missouri Public Service WPS) and Grand River Dam Authority (GRDA), also use
345 kV facilities to interconnect with the AEPW, OKGE, WERE. and KCPL balancing
authorities-
Transmission facilities at 230 kV form a secondary backbone that is used in SPP
primarily h tbe SPS, Cleco Power LLC (CLEC), and WERE balancing autho&es. Other
balaucing authorities nearby, such as Louisiana Energy & Power Authority (LEPAj and City of
Lafayette (LAFA). a h use 230 kV lines to hterconncct with the CLEC balancing authority.
The figure below indicates the locatitions of the 500 kV, 345 kV, and 230 kV buses in the
SPP region.
Figwe 1.9
REGIONS OF HIGH-VOLTAGE
(23W KV) CONNECTIVITY IN SPP
33
204
BOSTOV PACIFlC COMPANY. :?IC‘.

Exhi bit TAG5
Page41 or117
205
Between the 230 kV and 69 kV voltage systems, there are three voltages used in SPP:
1 15 kV, 13 8 kV, and 115 1 kV. These thrz voltage levels serve a mid-level power transfer
function in SPP, and typically only one of these three voltage levels is used in any specific
location. A review of mmission busts in SPP show that 115 kV Is typicaIly used in western
SPP, 138 kV in southem SPP, and 161 kV in northeastern SPP. This is indicated in the figure
below.
Figure 1.10
REGIONS OF MEDIUM-t'OLTAGE
( I I5 KV TO I61 KV) CONNECTIVITY lK SPP
ERCOT
SPP Trunst#is~wn Connectivi& with ERCOT a ~ WECC d
A tml of five Direct Cumnt (DC) ties connect SPP to ERC'OT and \n;ECC. Two DC
tis, known as ERCOT East and ERCOT North. or Welsh and Oklaunion Er;pectiveIy. connect
SPP m ERCOT for 820 MW of n-ansrnission capabiliry. On the SPP side, these ties are located
in the AEPW balancing authority, and thy are owned and operated by AEPW-
Three DC ties. known as Eddy County. Blackwetcr. and tam. coniiect SPP ta WECC
for 6 10 M W of transmission capabiliry . The Eddy Count). tie is owned by El Pas0 Electric
I EPE 1 arid T ~as - New Mexico Power (TNP). but operated by SPS. The Blackwater tie is
owned and operated by the Public Service Company of New Mexico (PNM 1. The Lamar tit is
owned and operattd by Public Semtce Company of CoIorado (PSCO). an affdiate of SPS. The
transmission capability of each DC tic is shown in Tabk 1.8.
34
BOSTON PACIFIC COMPANY. IN('.

Tabte I.8
DC TIE TRANSMISSION CAPABILITY
E~bit TAG-5
Page42oTIt7
Transmission outages can impact deliverability and affect market prices. Moreover,
transmission outages can make transmission congestion more likely $0 that the SPP Market is
balkmized with prices v@ng by location. Transmission elements. just like generating units.
need to be reniowd hm service for occasional maintenance. Transmission system components
aIso fail from time to time. resulting in forced outages. The following figure shows that the
pattern of mnsmission system outages for 2008 follows the same general pattern as that for
generating units in that outages were at some of their lowest levels during the summer months.
Less rhan 1 % of oumge days in 2008 on the SPP =ammimion system were forced outages.
35
BOSTON PACIF.lC
............. - ........ COMPANY. . INC'.

Figure 1.11
DAYS OF TRANSMISSION OUTAGES BY MONTH FOR 2006 TO 2008
Jan Feb Mar Apr
I
I
I
Eshibit TAG-5
Page 43 of 117
Figure I. f 1 above shows the extent of lransmission system outages for each month from
2088 to 2008, calculated by the length in days of each outage. For example, 100 transmission
lines out of service for three days equaf 300 outage days in the fibwre &we. tn addition, if a line
was out for any portion of a day, it was considered one outage day. The number of days of
transmission outages increased significantly from 2006 to 2007: in 2007 the rod was 1 1,149
days 5ts compared to a total of 8,581 days in 2006, a 30% increase. In 2008, the number
increased once again from 11.149 10 12,Ol I days. This marks an 8% increast over last year‘s
total.2s
Over the last fiw years we have seen an increasing trend in the number of transmission
outages. While this year’s increase is not as exweme as last year’s, we are still concerned abuut
&e growing number of outages. We believe that om reason for this increase is most likdy due
to the increased amount oftransmission investment that has resulted from SPP’s Transmission
Expansion Plan. However, given the current data set, we are unable to confirm this hypothesis.
36
BOSTON PACIFTC COMPANY. I&[-.
207

Exhibit TAG5
Page 44 of 117
Furthermore, the sow for the data we are currently using, OBI, is meant to be a forecasting
tool, and is not meant for reporting historical oms Also, there does not par to be a
consistent method for detmnhhg whether an outage is a forced outage or a maintenance outage.
Given all of these COIIC~~, we recommend not only lhat SPP and the MMU look into the
reasons for he increasing outages, but that a new approach to gathering transmission outage data
be created in order to provide an accurate historical record of outages-
The location of transmission outages in SPP during 2008 are shown in Figure I. 12,
below, by balancing authority. The AEPW, OKGE, and WERE balancing authorities all
expetienced over 1,500 days of tmmnissioa kilry outages during 2008 accounting for 5 8% of
all outages-
Figure L12
DAYS OF TRANSMISSION
OUTAGES BY BALANCING AUTHORITY FOR 2008
- . .
. .
-
Figure 1.13 shows the ratio of days of hnsmission outages to the number of transmission
branches at 1 OO+ W for each balancing authority shown in Figure 1-12. SWPA balancing
authoriq had the highest level of outage duration per transmission fine- Again, as mentioned
previousIy. less than I% of outage days in SPP were as a result of forced ouuges. Therefore, we
do not see this as a reliability issue, but the reasons for the increases should be transparently
reported by SPP.
37
BOSTON PACIFIC COMPANY. INC.

EshibitTAG-5
Page 45 of 117
Figure 1.13
RATIO OF DAYS OF TRkNSMISSIQN OUTAGES TO
MJMBER OF TRANSMISSION BRANCHES BY BALANCING AUTHORITY FOR 2008
12
1
IO i
I
li I i
Ii
SMRCE SPP OPSi
38
- -
BOSTON PACIFIC COMPANY, tKC.
W9

A. Brief Overview of the €IS Market
TI. EIS MARKET RESULTS
Exhibit TAG-5
Page 46 of 1 17
SPP launched its Real-Time Energy Imbalance Service (€IS) Market on February I,
2007; therefore, this is the second year of EIS Market operation. The EIS Market footprint,
which contains ten balancing authorities, is a sukt of SPP's footprint.2q The EIS Market is an
unbalance market in which all resource and load imbalances are settled. SPP is also in the
process of developing a Day-Ahad Market and an Ancillary Services Market. These nmrkets
are tentatively scheduled to be Iaunched in the second half of 2012. As these markets are yet to
be in operation, this section focuses on the EIS Market. To give an overview of the 2008 results,
we report on seven topics: ti) Market Activity, (ii) Market Prices, Iiii) Iteveme Adequacy (Net
Revenue Calculation). (iv) Fuel Type, (v) Market Participation, (vi) Market Power Measurement
and Mitigation. and (vii) Revenue NeutraIiry Uplifr (RNU). Given that this is the second year of
market operation, we also. in many cases. compare the results from 2008 to those from 2007.
B. Market Activity
The EIS Makt is mfindirtoJy in rhhe sense that all resource and load imbalances must be
settled in the €IS Market However. the market is vdzmfui~ in the sense that a Market
Participant can decide for itself w-hether to (a) self-dispatch its rzsomes or ('b) participate fully
by making its resources available for SPP to dispatch in the EIS Market.
TabIrs 11.1 and Ii.2 show, for 2007 and 2008. the volume of sales and purchases in the
market and the dollars received and paid by Market Participants for those transactions. A snk is
made by 8 Market Pamcipant when either (a) it generates more than it has scheduled and/or tbl
its actd load is lcss than it has scheduled. Sirmlarly-. apudi~~ce is made by a Marker
Participant when cither (a) it generate less than it has scheduled and/or (b) its actual load is
more than it has scheduled.
For example. say a Market Participant schedules and offers 100 MWh of generation fmm
a power plant; by scheduling and offering. this power plant becomes dkpatctable by the EIS
Market. Lf the power pfanr is dispatched at 125 M%k it made a 25 MWh sale to the EIS Market.
In contrast. if it is disFatched at only 70 MU%. it made a 30 MWh purchase from the EIS
Market [fit was dispatched at 100 MWh then 0 MWh would be considered to be in the €IS
Market since the reso~rrce's actual production was equal to its schedule. On the load side. if a
Market Participant schedules IO0 MWh of load. but actually uses 125 MW-h. it has purchased 25
MiP%; if its actual use is only 70 MWh. it sold 30 MWh to the €IS Market.
Tabk I[. 1 and Table 11.1 show that there were over 15 rnilIion MWh both sold and
purchased in the E1S Market in 2008. This compares to over 13 million MWh sold and
purchased in 2007. which marks roughly a 14% increase from 2007 to 2008. However. it is
important to note that there were only 1 1 months of mket operation in 2007. so we must
BOSTOV PACIFIC COMPAYY. IX('.