Distributed Generation Interconnection Manual

Exhibit CSG-3Page 6 of 43

Distributed Generation Interconnection Manual

Public Utility Commission of Texas

Prepared by:

Distributed Utility Associates Endecon Engineering1062 Concannon Blvd. 347 Norris CourtLivermore, CA 94550 San Ramon, CA 94583925-447-0604 925-562-1330dua(Qix.fletcom.cc^m wauw.endecon.com

May 3, 2002

U.S. Department of EnergyOffice of Energy Efficiency and Renewable Energy

50


2. SAFETY REQUIREMENTS

This section reviews the variety of interconnection-related safety requirements thatthe DG designerfinstaEler and the utility must take into consideration. Therequirements are divided by jurisdiction: State (PUCT), local, and national. Theserequirements are intended to ensure that DG is designed and installed in a way that

• is not a safety hazard to utility personnel or equipment or to other customers,• does not disturb other customers or degrade the quality of the distribution

system,• provides reliable service to the DG owner and the utility.

To make certain that these expectations are met, it is critical that the TDUunderstand the characteristics and requirements of the DG and vice versa.

2.1. PUCT Rules

State regulations regarding the generation, transmission, and distribution ofelectricity are set by the Public Utility Commission of Texas (PUCT). The PUCT'aWeb site provides access to all Rules at http:/fvuww.puc.state.bc,us under "Rules andLaws". Of technical interest to DG are the following.

Substantive Rules - Chapter 26Applicable to Electric Service Providers

Subchapter A General Provisions§25.5 * Definitions

Subchapter C Quality of Service§25.51 Quality of Service.

Division 2. Transmission and Dilstribution Applicable to All Electric Utilities§25.211 * Interconnection of On-Site Distributed Generation§25.212 * Technical Requirements for Interconnection and Parallel Operation Of On-

Site Distributed Generation

The specific requirements of §25.211 and §25.212 are covered in subsequentsectionsof this manual. These rules detail the operational responsibilities of boththe TQU and the applicant.

The PUCT's rules may, in some cases, be superseded by local requirements ormodified in the future.

2.2. TNRCC Rules

A distributed generation emissions rulemaking is in progress. This subsection willbe updated after a DG emissions rule is adopted by TNRCG.

PUCT t'3G Interconnection Martrel OW1102 2-1

51


2002.

Table 5-11: DG Ownership and Structural Options

Customer Ownership * Self-generation DG and storage

^ Cost-et#'ectiue EE, storage

# ESCO provision of ©G, EE

TDU Contracting + T&D supplements(in lieu of ownership) . DG location support -EEK DG dispatch

I & Customer partnership (?G, EE, storage {co-

TDU Rebates & Incentives * EE incentives

a T[?U or ISO purchase (demand-responsive

TDU Oiit-Sourcing 9 Aggregation of demand reduction, DG• ESGOif3G vendor places and operates DG

where wireco needs it

• Thin:1-partv EE programs

A DG applicant has the responsibility to pay fctc the reasonable costs of system studies.A customer has the responsibility to make full disclosure of the DG project and itsoperation to the 1'Rt.1. A DG applicant also has the responsibility of ensuring that theDG project meets all applicable national, state, and local construction and safety codes(see §26.211(b)); that operation of DG does not cause undesirable effects on othercustomers (see §25.211(c)); and that the necessary protection equipment is installedand operated to protect both its equipment and the TDU's system, If the DG applicantdoes not fulfill these obligations, the host TDU need not interconnect or it maydiscxannect, the DG project.

5.2. TDE! Rights and Responsibilities

A TDU must respond to applications for interconnection expeditiously, within the timeperiods specified in this Manual. A TDU has the right and responsibility to safeguard itssystem, other customers, and the general public, subject to the RUCTs rules, and mustshow good cause why a DG appiioation that satisfies the PUGT`s requirements shouldnot be interconnected to its system. A TDU does not have the right to unilaterally refuseto connect a DG project. A TDU is under no obligation to purchase the energy from acustomer's DG. A TDU is, however, required to assess and recognize the benefits ofadding DG to the distribution system during the application process (see PUCT Rule§25.211(g){1}(G)}.

PUGr DG hiterco . Manual O&WX2 5-2

52

umb bto54a swi i^^ ^^ti-i044 u Exhibit CSG-3

Texe3

Xcelirf JerW- Re& P 6 t# S t B t P By MATURE*

Distributed Generation Guidelines for Customer-OwnedGenerationThis information applies to Xcei Energy service territories in Texas only.

e at I a= All

FERC Rules

Federal Energy Re âtg^ or Commission (°FERC"j provides standards for small generation(iess then 20 MW) Interconnection for faciiittes within the jurisdiction of the commisslomThis generally applies to tronsmission-levol Interconnection, Distribution-levelInterconnection is usually regulated by each states public utilities commisslort

FERC - Small GorteratOr Intemormection Procedures

FERC Process htfarmation

Affected System Impact Studies: Interconnection 5 MW or greater

Generator interconnections to the Southwestern Public Service Company ('SPS"}distribution system, not subject to Southwest Power Pool ("SPPJ Open AccessTransmission Thrill ("C1ATT'ji may still require studies to identify impacts on SPS*stransmission system. SPS will notify SPP of Interconnection requests of 5 MW or moreto be studied pursuant to SPP's Affected System Generation Interconnection Impactstudy process ("impact Study or Studies). SPP andror SPS will evaluate eachinterconnection request not subject to QATf requirements and will make the finaldetermination whether the intercannection impact study will be performed by SPP. InInstances where further study is warranted. such studies will be performed by SPP, atthe dtrecUon of SPS. Non-Jurlsdictional generator interconnection customers may berequired to enter Into the appropriate study agreements with SPP to facilitate an AftotedSystem Agreement. Additionally, requests for nonjurtsdict{onal genmatorinterconrtectkuts may be required to be coordinated with SPP in accordance with NorthAmerican Electric Reliability Corporation ('AtERC") standards.

Although such studies may be performed within SPP's Generation InterconnectionProcess ("GIP') for planning purposes, the non jurisdictional generator Interconnectioncustomer will not be subject to the OA7T. In such instances, the falloWng shell apply:

1. When notititxt, SPP Is responsible for conducting any required studies to determine dthe request may lmpact the Transmission System.2. Should SPP determine that the generator interconnection may impact theTransmission System, SPP shall no* SPS of such impacts and protifde to SPS anysystem impact studies that dotal such impacts.3. As an impacted system, SPP will determine what additional studies will be required tocoordinate the impacts, up to and inducting studying the impact in the DefinitiveInterconnection System Impact Studies SPS shall require as a condition ofInterconnection with the generation customer making request (or Intemonnectim that allSPP required studies be completed. SPS shall have the option to enter into theapplicable Affected System study agreements and to be financially responsible for suchstudies, or as a condition of Interconnection, to require the Interconnection customer tosubmit a request to enter the DS19 process or other SPP study process as applicable.4. It shelf remain SPS's nssponstbitity to complete any generator interconnectionagreements in accordance with SPS's generator interconnection procedures regardingthe completion of Network Upgrades required on the Distribution System and on SPS'sTransmission System.

I

Aî'erêd System tmpact Stucliesc Interconnectiona tess thart S MW

Requirements for Affected System impact Studies

Impact Studies are perfarmed in a"ctuster" method twice a year in April and October.SPS will require the party requesting interconnection to protde Initial Nnding in theamount of $30,000 to determine if upgrades will be needed to the affected transmissionsystem: All funding and 00 generator interconnection information must be Provided to

AMfiM*8 ibr-OM m-W&W W4-ii}i[ I T680tHa Sia tW dWO-tk 6} 4 qtt NO

of 43

53

t^ uAtft aidi tWd ` i4 u

5PS no less than 30 days prior to April or October, Impact Studies typically take W tosix months to be completed. Multiple studies and additional funding are always apossibility. Aker the SPP 6npact StaxtS! process is completed and WoWed to SPS, SPS

wit oor*act the party *v IrAercortriection with any transmission system Wyadesrequired along with the ^sti^but^n system u^. If any funding Is not used for ftImpact Study, It wilt be mhxxW to the patty requesting htteteoaartectiat.

Steft Rules

Tariffs

interconnection Fonns and lgreerimonts

3Lce1 Enera Ts 1on kiltwrconwdim Quklalf>ws

Contacts for Southwestern Public $Service Camparly

in,

^^^A 1, AUSAM •1 QM=Ft3±^syPnl^vr ( Akh=ng Tema ad Qw"M

Copyright* 2012 Gael Energy, inc All Role Reserved.

Exhibit CSG-3 5Page 10 of 43

ij ibhNN W56-MF*j I r A&MA ^ JW a^*4 4 ^u Cto

54

.- - -ExTiiit-CSG-3

Page 11 of 43

xce.IEnergyM

July 16, 2012

DESIGN GUIDE I EMMEERING ESTIMATE

Source: County Line Substation, Ct^I 10 Feeder,Project Tide: County Line Wind DG Interconnection for Ascendant

Renewable EnergyProject Location: PCC in proximity of the Southwest corner of County Road Et

& Farm-to-Market Road 54, 33°52`29.9"N, 102'03'47.62"WIn-Service Date: Requested: 12-30-2012Passport WOParent #.Program Manager. Julius HeslopProject Manager. Zac Thrasher

11. ProJect Purpose and Scope

Ascendant Renewable Energy (Customer) is requesting interconnection of five(5) 2 MW Sany Electric, Ltd. generators in Hale County, Te)msT This generationis to be connected to the County Line Substation 12 W CLI 90 feederapproximately 3.0 line-miles from the substation.

U. Project and Operating Concerns

The proposed five (6), 2 MW Sany Electric, Ltd. double fed induction generatorswith reactive power control have been reviewed and approved by SouthwesternPublic Service Company r!lbta Xcel Energy for this application.

Modifications will be made to the distribution substation to prevent the reclosingof Xcel Energy's substation into the County Line Wind Farm while it is inoperation. A radial 69kV transmission line serves Xcel Energy's County LineSubstation. The rectosing scheme on Xcel Energy's 69W transmission system isset to automatically high speed rectose in 18-22 cycles after tripping. A potentialproblem exists that the County Line wind generator would not trip before thetransmission line is reotosed. XceP Energy's Transmission Operations group isrequesting that your engin^eding firm study this issue to determine if this is aconcern. If this is a concern, determine if modifications can be made to yourdesign to mitigate the pratential problem.

This installation shall be operatedin a safe manner, and not be a safety hazardto Xcel Energy personnel or equipment, or to other customers. The proposedwind generation shall not disturb other customers or degrade the quality of the

^ 55

hibit -3Page 12 of 43

distribution system in any way. The installation shail provide rabble service forthe Customer and to Xcel Energy. The Customer shall be financially responsiblefor all modifications necessary to maintain operation within these guidelines.

111. Physical Feattires and Engineering Estimate of Costs

The following changes will be required in order to accommodate this proposedwind generator

SMbI _ A40A; ($4,970,000)

• Install an adjacent 6.25 MVA 69612.5kV substation transformer and transformerrelays.

• Install, supporting steel structure for extending existing low (12.0k1l) and high(69.OkV) side bus.

• Upgrade relaying on the two (2) breakers in the County Line Substation with amicroprocessor relaying to company standard of SEL-351 R.

• Install two sets of voltage sensing potential transformers on the load side of thethree-phase breaker at the substation for voltage supervision during breakerclosing.

• Routing the microprocessor relay SEL-351 R to the existing RTU at the CountyLine Substation.

E3istrila on, ($110,000)

• Re-conductor a 100-foot overhead primary tine from existing three-phase of #2AS primary to #336 ACSR. primary and #2l0 ACSR neutral. Install a 100-fool: ofoverhead primary line consisting of #336 ACSR primary and #210 ACSR neutralextending County Line Substation's CL110. Distribution tap starting at guyed poletakeoff structure, transformer pole, one ('f) recloser pole, overhead primary meterstructure, one (1) three-phase G4AR pole and stack span to the Customees

Pole.

• Install one (1) three-phase 15 kV rating gang operated air-break switch.

• Install one (1) 25-tcVA distribution transformer for AC power to RTU and reclosercontrol.

• Install one (1) 27 W electronic recloser with remote SCADA controls.

•Install one (1) regulator station consisting of three (3) 15kV regulators.

56

Exhi bit -3Page 13 of 43

e An & C i-d2n: ($80,000)

• Install one (1) 12 1cV overhead primary metering station at the site, includinginstrument transformers, billing meters and metering cabinets.

• Install one (1) Remote Terminal Unit (RTU) cabinet, conduits, control and powerconductors, business & data phone lines. Business & data phone lines to beterminated in a communication cabinet provided by SRS. This cabinet will belocated next to RTU cabinet and will ,apjy be occupied by a telephone companyand SPS equipment

• Install one (1) breaker box, for power to the RTU and for the communicationcabinet

M:

• The Customer shall install an electronic breaker or other interrupting device atthe point of interconnection. This device placement should be Installed just pastthe Customer's visible disconnect.

• The Customer shall trip the vvind turbine main circuit breaker within 6 seconds, ofa County Line substaition Ci;.11O feeder circuit breaker hip, The Customer shalltrip the wind farm main circuit breaker with loss of AC power from County LinesFeeder CLI 10 to avoid back feeding the existing customers on the circuit.

• During an under frequency condition on the SPS system, the turbines need tostay online down to 58.5 HZ

• The Customer is solely responsible for property synchronizing with the utility. Theexcitation system response ratio shall not be less than 0.5.

• The Customer shah automatically disconnect from the utility system within ten(90) cycles If the voltage on one or more phases falls below -30% of nominalvo[tage.

• The Customer shail furnish and install concrete pad for primary metering station,and provide trenching from riser poles to metering cabinet for primary conductorsand from the electronic rectoser to the RTU cabinet for control cable & AC power.The Customer shall also provide trenching from RTU cabinet to primary meteringfor data cables and business phone line.

• The Customer shall furntsh and install a three-pipe pedestal with an adequatenumber of unistrut channels spaced to mount the RTU cabinet on one side, atelephone box for SPS, and any customer equipment on the backside.

57


• The Customer shall furnish and install concrete pad for primary meter station,and provide trenching from riser poles to metering cabinet for primary conductorsand from the electronic recloser to the RTU cabinet for control cable & AC power.The Customer shall also provide trenching from RTU cabinet to primary meteringfor data cables and business phone tine.

• The primary meters will be read by phone. The Customer shall furnish and installaharc! -wired business phone line to the SPS telephone box located adjacent tothe RTU cabinet at their expense. Monthly cost for the business phone line willbe the responsibility of the Customer.

• The Customer shall provide trenching and beckfiiting from the telephone pedestalto the SPS communication cabinet

• Ordering of the business phone line by the Customer and the data circuit by SPSshall be coordinated with the phone provider and the SPS communication group.

* Specifications for the three-pipe pedestal " ditching details will be provided bySPS.

• The Customer shall coordinate main switchgear circuit breaker and turbinereactive power control settings with SPS.

• The Customer shall coordinate turbine main circuit breaker and reactive powercontrol settings with SF'S.

. The Customer shall coordinate their protective relaying package with settings forthe SPS electronic recloser.

• The interconnection recioser between the Customer and SPS shall be trippedopen by relay atenyttme that the County Line substation's ioad is below theCustomer's generation and reverse-flow to transmission may occur.

Engineering Estimate of Costs: $2,'t60p00O

This estimate is valid for E30 days frrorrt the date shown below.

58


QUESTION NO. RFI 1-6:

(i) Please explain in detail how the interconnection of generation to a distribution feeder from thesubstation might cause voltage fluctuations at the substation distribution bus? (ii) Would anypossible fluctuations at the bus be significant? (iii) Would any possible fluctuations be discernible bythe customer? (iv) If so, would it be significant? (v) How would fluctuations at the bus be likely toharm SPS's customer? (vi) Would the quantity of generation interconnected to a distribution feederfrom the substation affect voltage fluctuations? (vii) If so, how? (viii) At what threshold of busvoltage fluctuation could the customer be significantly harmed?

RESPONSE:

(i) As the wind farm increases its generation, the voltage and power on the distribution feederwill increase. This, in turn, will cause the VARs to increase. This problem is magnified as thedistance between the generating facility and the substation increases. The proposed distance of thewind farm to the County Line Substation is approximately 3 miles and, thus, high wind speeds canrapidly cause a 5-7 % increase in voltage. Following a predetermined delay of increased voltage,devices must be installed to stabilize the Substation's voltage within the utility's acceptable servicevoltage range.

(ii) Yes. SPS modeled the proposed generating facility at its maximum voltage, and measured a5-7 % increase in voltage. This increase is a significant voltage fluctuation.

(iii) SPS cannot state what level of fluctuations would be discernible by any particular customerson the low side of the Substation bus, as it depends on variables such as the lessee's equipment, tripsettings, and customer's primary system.

(iv) SPS cannot state what level of voltage fluctuations would be discernable to the lessee.

(v) SPS cannot state what harm would be caused to a customer's equipment based on themodeled voltage fluctuations; however, if SPS's service voltage fluctuates out of range, the lessee'sequipment can trip offline. For example, if high winds cause the wind farm to generate its maxi,,,umof 10 MW, and is suddenly tripped off to 0 MW, this instantaneous event could cause the customer'sprotective equipment to trip faster than the Substation regulating relay could react to the largefluctuation, which could affect its operations or damage equipment.

(vi) Yes. The quantity of generation interconnected to a distribution feeder from the substationwould affect voltage fluctuations.

(vii) As mentioned above, increased generation increases VARs on the system. SPS modeled theproposed generator at 10 MW, and measured a 5-7 % voltage increase. When the proposedgenerator was modeled at 4 MW, SPS measured a 2.5% voltage increase.

(viii) SPS cannot state the bus voltage fluctuation threshold at which a customer would be harmed,as it depends on variables such as customer equipment, trip settings, and customer's primary system.

P UCT Docket No. 40499Southwestern Public Service Company's Response to

Staff'' s First Requestfor Information

59 Page 9


Preparer: Julius Heslop

PUCT Docket No. 40499Southwestern Public Service Company's Response to

Staff's First Requestfor Information60 Page 10


QUESTION NO. STAFF 3-5:

Has the interconnection of Ascendant's generation facility at the Hendricks Substationcaused the quality of service and/or power received by other customers served by thatsubstation to fail to meet any required standards? If "yes", please describe the standards andexplain how those standards have not been met and to what extent they have not been met.

RESPONSE:

Currently, customers served from the Hendricks Substation have not notified SPS of anyquality of service issues. It should be noted, however, that a lack of customer complaintsdoes not necessarily mean that service quality has not dropped below standards in someinstances.

In addition, the absence of service issues at the Hendricks Substation does not mean that noservice issues accompany the connection of distributed generation. For instance, SPS has asituation where wind turbines are connected to an SPS distribution line with other end-usecustomers interconnected and high voltage has been experienced causing damage tocustomer-owned equipment.

Further note that there was no lease agreement or electric service agreement relating to theHendricks Substation that needed to be considered when interconnecting Ascendant to theHendricks Substation.

Preparer(s): Seth Thomason

PUCTDocket No. 40499Southwestern Public Service Company's Response to

Staffs Third Request for Information

61 Page 8


QUESTION NO. ASCENDANT 1-2:

Identify any other wind generation facility 10 MW in size or less interconnected with theSPS distribution system in Texas (i) at which SPS interconnection studies predicted voltagefluctuations resulting from the installation and operation of the wind facility and (ii) for eachsuch facility, the voltage fluctuation actually caused by the installation and operation of thewind facility before taking into consideration any voltage regulation or other equipmentinstalled at the interconnection point.

RESPONSE:

(i) SPS evaluates the impacts to the distribution system of all wind facilities that havemade requests to interconnect. In the majority of cases, it is necessary to makesystem upgrades and modifications to accommodate the increased load on thedistribution circuit and maintain adequate quality of service for existing retailcustomers. SPS was required to conducted voltage studies after wind facilities wereinterconnected when it received customer complaints of voltage fluctuations at thethree wind facilities listed below in part (ii) of this response.

(ii) The wind generation facilities, Little Pringle 1& 2, John Deere Wind 3, and HighPlains Wind 1, all caused voltage fluctuation after the interconnection was made andthe wind facility began normal operations. Prior to each interconnection for itsrespective circuit, the study indicated that voltage fluctuation was within ANSIC84.1 standards. After SPS received a customer compliant of voltage fluctuation,equipment modifications were required on the distribution system to correct theseproblems as shown in SPS's response to Ascendant 1-3 below.

Preparer(s): Julius HeslopSponsor(s): Mitch Elmore


Ascendant's First Requestfor Information

62Page 5



Identify all other wind generation facilities 10 MW in size or less interconnected with the SPSdistribution system in Texas at which SPS required installation of voltage regulators to addressprojected voltage fluctuation arising from operation of the facility.

RESPONSE:

Little Pringle 1& 2 are two separate 10 MW wind generation facilities that created voltagefluctuations effecting irrigation customers within close proximity of the interconnection tapto the wind facilities. Voltage regulators were required after the wind facility begancommercial operation at Little Pringle 1& 2, to address these voltage fluctuations.

John Deere Wind 3, LP a 10 MW wind generation facility, created an extreme voltage riseaffecting dairy customers on the distribution circuit the wind facility was connected to. Avoltage regulator, a capacitor bank, and modifications to wind facility operation wereimplemented to provide nominal voltage after commercial operation began and SPS receiveda customer complaint that involved failed equipment at his facility due to high voltage.

High Plains Wind 1, a 10 MW wind generation facility, created high voltage affecting thewind farm and other customers. On the circuit to High Plains Wind 1, a voltage regulatorwas added to the distribution circuit and additional modifications to wind facility operationwere implemented to solve the high voltage issue.

Preparer(s): Julius HeslopSponsor(s): Mitch Elmore



63Page 6



Is SPS taking the position that the existence or terms of the lease of substation capacity toOPL supersedes, or otherwise excuses SPS's compliance with, the obligations of PURA andrelated regulations of Section 25.211 and the obligations of the federal Public UtilitiesRegulatory Policies Act and related regulations, with respect to the interconnection of theproposed County Line wind facility?

RESPONSE:

For reasons discussed in SPS's Response to the Complaint of Ascendant Renewable EnergyCorporation, dated July 12, 2012, SPS believes that it is complying with PURA

requirements. However, the existence of the OPL lease at the County Line Substationreduces the capacity for interconnection purposes. In addition, SPS's obligations under thelease must be considered in determining what capital upgrades are necessary to allow theinterconnection to occur without degrading the character and quality of service provided toOPL.

To SPS's knowledge, Ascendant is not a Qualifying Facility. Therefore, anySPS obligations under the Public Utilities Regulatory Policies Act and related regulations arenot relevant to the issues in this proceeding.

Preparer(s): Seth ThomasonSponsor(s): Seth Thomason


Ascendant's First Request for Information

64Page 10


RESPONSES


Identify all other locations on the SPS system at which SPS leases substation equipment orcapacity to an SPS retail or wholesale customer, and for each such location, identify whetherthere are generating facilities of any size connected with the SPS distribution system withinfifteen miles of the applicable substation.

SUPPLEMENTAL RESPONSE:

The following response replaces SPS's initial response in its entirety:

Below, SPS identifies other substations that have leases and whether generation facilities areconnected to the substations.

Location of Leased GeneratingSubstation Substation (County) Facilities?

Texaco Hockley NoFlanagan Gaines No

Ozark Mahoning Gaines NoMcLean Rural Gray No

Etter Rural Moore YesPrentice Terry No

County Line Hale NoC2 Yoakum NoC3 Yoakum No

Coble Hockley NoPacific Hockley No

Highland Park Potter NoDeaf Smith Deaf Smith No

Prentice Terry NoLea Road Lea No

Allred Yoakum NoRussell Gaines NoTweedy Chaves No

S. Hobbs Lea NoNavajo I Eddy NoNavajo 2 Eddy NoNavajo 3 Eddy NoNavajo 4 Eddy NoNavajo 5 Eddy NoMaljamar Lea No

PUCT Docket No. 40499Southwestern Public Service Company's First Supplemental Response to

Ascendant's First Requestfor Information65 Page 4

4


It should be noted that SPS does have a leased substation located in Moore County with twowind farms interconnected. The substation has two transformers, where one is a 20 MVAtransformer and the other is a 28 MVA transformer, for a total of 48 MVA. SPS leases 28MVA of the substation to a customer. The wind generation is connected to the substation,but SPS has segregated it so that it is connected to the 20 MVA transformer, thus electricallyseparating it from the leased transformer. This arrangement is identical to SPS's requirementof Ascendant for the interconnection of a 10 MW wind farm to the County Line Substationand will avoid interference with the lease of OPL.

Preparer(s): Seth ThomasonSponsor(s): Seth Thomason

P UCT Docket No. 40499Southwestern Public Service Company's First Supplemental Response to


66 Page 5 5


RESPONSES

QUESTION NO. OPL 2-1:

If Ascendant were interconnected as it proposes, would this result in SPS delivering electricenergy to OPL [in part] at distribution-level voltage?

RESPONSE:

Yes. Ascendant's generated electricity would be purchased by SPS at 12.5 kV and it wouldflow to customers' loads, including OPL, that are connected to the County Line Substation12.5 kV buss. SPS would thereby be supplying service to OPL at both 69 kV (transmissionlevel) and 12.5 kV (distribution level).

Preparer(s): Seth Thomason, Kevin BrimeyerSponsor(s): Seth Thomason


OPL's Second Request for InformationPage 4

67



If OPL were to install its own substation and remove its load from the County Line Substation

(i) what would be the remaining distribution load on the County Line Substation and (ii) whatwould be the limit on the output of Ascendant's facility under the terms of Ascendant'sinterconnection agreement with SPS and the Commission's distributed generation rules?

RESPONSE:

(i) With OPL installing its own substation and OPL's load removed from the CountyLine Substation and thus no longer leasing any portion of the substation, theremaining maximum distribution load on the substation would be approximately 2.9MVA and a minimum distribution load would be approximately 0.5 MVA.

(ii) The current maximum available generation for the SPS distribution circuit, CL 110, is12 MW without upgrades. The Commission's distributed generation rules limit eachdistribution meter to 10 MW of generation. If OPL were to construct its ownsubstation and terminate the lease for facilities at County Line Substation, Ascendantwould be limited to approximately 0.5 MVA, assuming it filed and paid for thenecessary SPP study to determine the impact of 9.5 MW of generation flowing backonto the 69 kV transmission system serving County Line Substation and the newOPL substation contemplated by this question, as required in SPP's OATT BusinessPractices, Section 7300(C).

Preparer(s): Mitch Elmore, Julius HeslopSponsor(s): Mitch Elmore


OPL's Second Requestfor InformationPage 6

68



If OPL were to install its own qualifying facility connected to its private distribution system,sized to serve the entire OPL load interconnected to the County Line Substation, (i) what wouldbe the remaining distribution load on the County Line Substation and (ii) what would be thelimit on the output of Ascendant's facility under the terms of Ascendant's interconnectionagreement with SPS and the Commission's distributed generation rules?

RESPONSE:

(i) If the distribution configuration stayed the same and OPL installed generation to meettheir load, the load on the County Line Substation would be at maximumapproximately 2.9 MVA and at minimum approximately 0.5 MVA.

(ii) Please refer to the response to OPL 2-3(ii).

Preparer(s): Mitch Elmore, Julius HeslopSponsor(s): Mitch Elmore


OPL's Second Requestfor InformationPage 7

69

Exhibit CSG-3Ascendant Renewable Energy CorporationPage 26 of 43Docket 40499SPS's RFI Set No. IRequest No. SPS 1-1Page 1 of 1

RESPONSES

QUESTION NO. SPS 1-1:

On Page 9, line 9, of his Direct Testimony, Mr. Paul Thompson states ARE submitted theinterconnection request at issue on May 15, 2012. On page 2 of ARE's complaint against SPS,ARE states "On May 18, 2012, ARE submitted its formal Application for Interconnection andParallel Operation of Distributed Generation with the Utility System. . ." Please clarify on whatdate ARE submitted its request for interconnection at issue in this proceeding.

RESPONSE:

ARE completed and signed its Application for Interconnection and Parallel Operation ofDistributed Generation on May 16, 2012, and the Application was personally delivered to SPS'sLubbock office by Paul Thompson and given to Julius Heslop. SPS has indicated that the studyperiod with respect to the Application commenced May 18, 2012.

Preparer: Paul ThompsonSponsor: Paul Thompson

70 000005

Exhibit CSG-3

Ascendant Renewable Energy Corporation Page 27 of 43Docket 40499OPL's RFI Set No. IRequest No. OPL 1-4Page 1 of I


Referring to Mr. Thompson's Direct Testimony at 8, describe the circumstances thatcause an SPP cluster study to be necessary.

RESPONSE:

Such a study would be required in all circumstances set forth in SPP's tariffs, as are therequirements describing when a particular proposed generating facility is required to be includedin a particular cluster study. In general, if a proposed facility is larger than 10 MW, it will bestudied by SPP. In addition, in circumstances where a proposed generation facility interconnectson the distribution system, but is expected to produce more energy than the minimum load on thedistribution system, creating the possibility of material injections of energy into the transmissionsystem, the facility may be required to be studied by SPP.

Recent amendments to SPP's business practices also attempt to outline certaincircumstances in which generation facilities interconnecting on the distribution system andgreater than 5 MW in size may be required to be studied by SPP. The precise interactionbetween these new practices and existing distributed generation rules for qualifying facilitiessubject to PUCT jurisdiction is still unclear.


71000008


Ascendant Renewable Energy CorporationDocket 40499OPL's RFl Set No, 2Request No. OPL 2-1Page I of I

RESPONSES


Please identify the partner of Ascendant mentioned on page 2 of the Complaint filed onJune 20, 2012 in this docket. Is this partner the same entity with which Ascendant developed theRalls Wind Project? Is this partner an affiliate of Sany Group, the wind turbine manufacturer?

RESPONSE:

Ascendant provided certain services to Sany, the manufacturer of the wind turbines, withrespect to the development of the Ralls Wind Farm, including, in particular, assistance withinterconnection of the facility to the SPS system. Ascendant has been retained by Sany to assistwith the development of the proposed County Line project, including necessary interconnectionarrangements.


72 000005

Exhibit CSG-3

Ascendant Renewable Energy CorporationPage 29 of 43

Docket 40499OPL's RFI Set No. 2Request No. OPL 2-2Page 1 of I


Please identify the retail customer behind whose meter Ascendant proposes tointerconnect each wind turbine. If none are identified, please indicate that Ascendant will not beinterconnecting behind any specific retail customer's meter.

RESPONSE:

As indicated in Ascendant's application for interconnection service, and all relevantfilings in this matter, Ascendant is proposing to interconnect on SPS's distribution line and not"behind the meter" of any retail customer,


73 000006

Exhibit CSG-3


Ascendant Renewable Energy Corporation Page 30 of 43Docket 4o499OPL's RFl Set No. 2Request No. OPL 2-6Page 1 of I

Referring to page 2 of the Complaint, Ascendant states that "Ascendant requested tointerconnect 10 MW in distributed renewable generation capacity to one of two 12.5 kVdistribution lines leading into the County Line Substation." Explain in detail how Ascendantqualifies as distributed renewable generation under each aspect of the definition in PURA§39.916(a)(1).

RESPONSE:

PURA Section 39.916(a)(l) states:

"Distributed renewable generation" means electric generation with a capacity of not morethan 2,000 kilowatts provided by a renewable energy technology, as defined by Section39.904, that is installed on a retail customer's side of the meter.

The proposed wind facility is a renewable energy technology as defined by Section 39.904. Asproposed here, the facility will be more than 2,000 kW in capacity and will not be installed on aretail electric customer's side of the meter, It therefore does not meet this definition.


974 000010

Exhibit CSG-3Ascendant Renewable Energy Corporation Page 31 of 43Docket 40499OPL's RFI Set No. 2Request No. OPL 2-7Page I of I

QUESTION NO.OPL 2-7:

Does Ascendant intend to register the County Line Project as a qualifying facility?

RESPONSE:

It is expected the ultimate project owner will self-certify the project as a qualifyingfacility at the appropriate time.


4748376.160987.1

10

75 000011


PUBLIC UTILITY COMMISSION OF TEXAS PAGE I OF 76SUBSTANTIVE RULES. CHAPTER 25. ELECTRIC

The Public Utility Commission of Texas (commission) adopts new §25.211 relating to

Interconnection of Distributed Generation (DG) and §25.212 relating to Technical Requirements

for Interconnection and Parallel Operation of On-Site Distributed t".xeneration. with changes to the

proposed text as published in the September 24, 1999 issue of the Texas Register (24 TexReg

8011). This section was adopted under Project Number 21220. The commission began an

investigation into distributed generation in 1998 as part of Project Number 19827, Irtvestigativn

into the Adequacy of f C,"apaeity for 1999 and 2000 Peak Periods in Texas. In part, the

commission initiated this project because it was interested in utilizing distributed generation

(DG) as a beneficial resource to help meet the States growing capacity shortfall during the

summer months of 1999 and 2004. As part of this project, a task force was formed to develop

interconnection guidelines for distributed generation. On February 4, 1999, the commission

adopted interconnection guidelines for distributed generation and requested tfiat staff continue its

investigation of distributed resources.

In adopting this rule, the commission's objectives are to clearly state the terms and conditions

that govern the connection and operation of small power generation and to establish technical

requirements to promote the safe and reliable operation of distributed generation resources, while

the customer is connected to both its own distributed generation facility and the utility

distribution system (referred to as parallel operation). Implementation of these rules (1)

promotes the use of distributed resources in order to provide electric system benefits during

76


PUBLIC UTILITY COMMISSION OF TEXAS PAGE 2 OF 76SUBSTANTIVE RULES. CHAPTER 25. ELECTRIC

periods of capacity constraints; (2) enhances both the reliability of electric service and economic

efficiency in the production and consumption of electricity; and (3) provides customers greater

opportunities to control the price and quality of electricity within their facilities.

Senate Bill 7 (SB 7), Act of May 21, 1999, 76tlt Legislature, Regular Session, chapter 405, 1999

Texas Session Law Service 2543, 2561 (Vernon) {to be codified as an amendment to the Public

Utility Regulatory Act (PURA), Texas Utilities Code Annotated §39.101(b)(3)) now entitles all

Texas electric customers to access on-site distributed generation. Project Number 21220 was

established to implement this provision. On July 21, 1999 staff held a workshop to begin the

evaluation of issues related to distributed generation. During this workshop three sub-groups

were formed relating to: 1) technical standards, 2) standard interconnection agreement, and 3)

tariff and policy issues, The rules reflect the work products of these three subgroups. At an open

meeting on September 9, 1999, the commission voted to publish a rule for comment in the Texas

Register, On October 14, 15, and 19, 1999, a total of l.1 interested parties filed comments on the

proposal. On October 25, 1999, commission staff held a public bearing pursuant to §200 1.029 of

the Administrative Procedure Act. Thirty-four parties attended the public hearing, of which six

provided comments that either addressed provisions set forth in the proposed sections, replied to

written comments from other parties, or, both. The parties represented at the public hearing

included: the Office of the Attorney General (OAG), Enron, El Paso Electric (EPE), Entergy Gulf

States (EGS), Texas-New Mexico Power Company (TNMP), Automatic Switch Company

(Automatic Switch), Central Power and Light Company, Southwestern Electric Power Company,

and West Texas Utilities Company, which are the Texas electric operating companies of Central

77



Comments on 25.211(d)

Regarding §25.211(d) (relating to obligation to serve), TXU argued that this section requires a

utility to modify existing tariffs or propose a new tariff for interconnection that ensures that

certain services are available to all customer classes that desire such service. TXU stated that it

should not be required to significantly modify existing tariffs simply to meet the style of the

proposed form. when more minor modifications will produce the same result. TXU suggested

that the language contained in this subsection be changed to reflect this fact.

The commission declines to revise the language set forth in §25.211.(d), requiring each utility to

modify existing tariffs or offer new tariffs for interconnection and parallel operation of

distributed generation customers,. The purpose of this requirement is to ensure that all customers

in Texas have access to distributed, generation as set forth in PURA §39.101(b)(3). This

provision should make the l^''x tariff provisions more accessible to prospective DG customers.

As noted in a report submitted by the DG task force addressing tariff and policy issues a review

of utility tariffs revealed that a majority of the utilities have one or more commission-approved

tariffs to provide electric service to qualifying facilities (QF) or non-QF cusiomers. However, it

was also reported that some utilities offer multiple tariffs that may apply to all DG customers,

while others may offer tariffs applicable only to QFs. For example, all utilities in Texas have

tariffs to provide standby service to QFs, while not all utilities have tariff; to provide standby

service to non-QF customers. Additionally, the parties noted that a number of existing standby

78



These new sections are adopted under the Public Utility Regulatory Act, Texas Utilities Code

Annotated §14.002 (Vernon 1998) (PURA), which provides the Public Utility Commission with

the authority to make and enforce rules reasonably required in the exercise of its powers and

jurisdiction, and PURA §39.101{b}(3) which requires the commission to easure that customers

have access to providers of energy efficiency services, to on-site distribuwd generation and to

providers of energy generated by renewable energy resources.

Cross Reference to Statutes: Public Utility Regulatory Act: ff 14.0()1, 14.002, 31.002, 39,101{a},

39.101(b)(3).

79


PROJECT NO. 39797

RULEMAKING TO IMPLEMENT SB § PUBLIC UTILITY COMMISSION365 & SB 981 RELATING TO § OF TEXASDISTRIBUTED GENERATION §

ORDER ADOPTING AMENDMENTS TO §25,211 AND §25.217AS APPROVED AT THE MAY 18, 2012 OPEN MEETING

The Public Utility Commission of Texas (commission) adopts arrtendments. to §25111, relating

to interconnection of On-Site Distributed Generation (DG), with changes to the proposed text

and §25.217, relating to Distributed Renewable Generation without changes to the proposed text

as published in the December 23, 2011 issue of the Texas Register (36 TexReg 8694). The

amendments implement statutory changes resulting from the passage of Senate Bills 365 and

981 of the 82d Legislature, Regular Session in 2011 (SB 365 and SB 991). Specifically, the

amendments to §25.211 limit the applicability to cooperatives to the requirements outlined in

subsection (cz}, modify the definition of parallel operatian to recognize third-party DG

ownership; place the burden on the DG owner to report any changes in ownership or cessation

of operations to the electric utility; and modify subsection (o) to more accurately track the

language in PURA §35.036(b) and (#). The amendments to §25.217 constitute a competition

rule subject to judicial review as specified in PURA §39.001(e). These amendments are adopted

under Project Number 3979'T.

The commission received comments on the proposed amendments from City of Houston

(Houston), City of El Paso (El Paso), Oncor Electric Delivery Company LLC, El Paso Electric

Company (EPE), Solar Energy Industries (SEIA),lnterstate Renewable Energy Council (IRE Q,

CenterPoint Energy Houston Electric (CenterPoint), L:L,C, Golden Spread Electric Cooperative,

80


PROJECT NO. 39797 ORDER PAGE 7 OF 67

electric utilities except where they are preempted by federal law. In addition, although the

specific impetus for the original adoption of §25.211 and §25.212 was the enactment of

PURA. §39.101:(b)(3) in 1999; the commission had approved DG interconnection guidelines

before the adoption caf.PURA §39.10ii(b){3} under its pre-existing authority and requested

that staff continue its Investigation of 1}G: Sections 25.211 and 25.212 were originally

adopted in the November 18,19" open meeting in Project No. 21220 and applied to most

non-ERCOT utilities. Since then, various exemptions from parts of PURA Chapter 39 for

non-ERCOT utilities have been added. However, it is in the public interest for customers

to have the right to DG even for utilities that are not currently subject to PURA

§39.101(b)(3)s because DG is an important source of generation.

Subsection (c)(4),• Definition of Distributed Natural Gas Generation Facility

SETA suggested that there may be an inconsistency in the definition of facilities. SEIA stated

that the addition of the new statutory definition of "distributed natural gas gen.eraticrn facility'' in

this subsection may be construed to conflict with the existing definition of 'facility" in

subsection (c)(5). Specifically, the strict 2,000 kilowatt limit for distributed natural gas facilities

behind the customer's side of the meter in proposed subsection (c)(4)_ could possibly be

construed to conflict with the existing definition: offacility's allowance that "the total capacity of

a facility's individual on,-site DG units may exceed ten megawatts (MW); however, no more than

ten MW of a facility's capacity will be interconnected at any point in time at the point of

common coupling under this section." SEIA suggested that these two paragraphs taken together

could be interpreted such that a facility may include 10 or more megawatts from a variety of DC`i

81



Subsection (c) (11); Definition of Parallel Operation

SEIA proposed that staff clarify the definition of "parallel operation." The current rule defines

parallel operation as "the operation of on-site distributed generation by a customer while the

customer is connected to the company's utility system" and subsection (c)(6) defines

"interconnection" as having the intended result that a customer qualifies as a DRG owner if

DRG is located on the customer's side of the meter. SEIA maintained that the parallel operation

and interconnection definitions imply that a customer must operate the DRG to be a DRG

owner. SEIA suggests clarifying the proposed language by changing the definition of parallel

operation to state "the operation of on-site distributed generation located on the customer's side

of die meter while the customer is connected to the company's utility system."

Commission response

The commission agrees that with the modifications to §25.217, which add third-party

owners to the definition of DRG owner, the reference in the definition of parallel opemtioa

to operation by a customer should be deleted. The commission has changed the definition

accordingly.

Subsection (d),. Terms of Service

STEC and Golden Spread commented that the commission has limited authority over

cooperatives for purposes of wholesale transmission rates and services, including terms of

access. STEC argued that the commission has exceeded its authority in trying to apply

§25.211(d)(2)-(3) of the proposed rule to cooperatives. STEC argued that the commission

exceeds its authority under:PURA §41.{}04, which authorizes the commission to establish terms

82



This development may result in the, installation of more DRG facilities for larger, nonresidential

customers. If the recent change is successful, the commission could consider applying the same

rules to third-party ownership of DTtCa at residential premises, too. Ownership of the DRG by a

third party could provide economies of scale or tax benefits to the third-party owner of the DRG

that would not be otherwise available to the customer. Another optton,f'orfvstering DRG would

be to amend PURA to remove the obstacles to third-party ownership ofDRGfor all customers."

See Report to the 82"d Texas Legislature-. Scope of Competition in Electric Markets In

Texas (January 2011) at 92 (emphasis added).

Senate Bill 981, enacted by the 82md Legislature, addressed DRG ownership and other

obstacles to the installation of DRG. The House bill analysis for SB 981 stated: "Interested

parties consider distributed generation to be electricity produced on-site and connected to a

utility distribution system and contend that there is a need for classification of distributed

generation in state policy as technological advances have made such generation more affordable

and desirable. The parties contend that statute is unclear with regard to small-scale distributed

generators and does not adequately address whether such generators are required to register with

the Public Utility Commission, of Texas. C.S.S.B. 981 seeks to clarify such issues by

establishing provisions relating to the regulation of distributed renewable generation of

electricity" See House Comm. on State Affairs, Bill Analysis, C.S.S.B. 981, 82 ad Leg., R.S.

(2Q11).

Both Senate bill analyses stated that "Recent technological advances make distributed generation

more affordable and desirable than ever before, but statewide policies do not exist for

83



the ca mission if at the time distributed renewable ene 'i installed, the

estimated annual amount of electricity to be produced by the distributed

renewable generation is less than or .. ual to the retail electric cusLptngr's

estimated annual electricity cvns=ptjn.

The purpose of SB 981 was the elimination of obstacles to use of DRG, with the bill

enacted by the Legislature without any vote against it. SB 981 creates, a new exception to

the definition of electric utility for an owner of. DRG, so long as the DRG meets the

requirements of PURA §39.916(k), which requires the amount of electricity produced by

the DRG to be less than or equal to the retail electric customer's estimated annual

electricity consumption. Subsection (k) exempts qualifying DRG from licensing

requirements "for purposes of this title," meaning the entirety of PURA. The Legislature's

manifest intent was to establish a statewide policy for DRG ownership. It is important to

note that subsection (k) addresses customers and owners of DRG, not electric utilities.

Because subsection (k) applies to customers and owners of DRG "tor the purposes of"

PURA, it applies in all electric utility service areas. Subsection (k)'s application is not

eliminated in an electric utility service area by other provisions of PURA that exempt

certain electric utilities from PUR.A §39.916.

There are five electric utilities providing retail service in areas in which customer choice

does not currently exist: Sharyland Utilities, L.P.; EPE; SPS; ETI; and SWEPCO. These

electric utilities are addressed below.

84


PROJECT NO. 34890

RULEMA.IMG PROCEEDING § PUBLIC UTILITY `COMMISSIOIYRELATING TO NET METERING AND §lltlTERCf)1"+1NECT1t7N OF § OF TEXAS61Si]WUTEI}-GENERATION §

ORDER ADOPTING NEW §25.217 AND AMENDMENT TO §25.242AS APPROVED AT THE DECEMBER 18, 2008, OPEN MEETING

The Public Utility Commission of Texas (commission) adopts new §25.217, relating to

Distributed Renewable Generation (DRG), and an amendment to §25.242, relating to

Arrangements between Qualifying Facilities and Electric Utilities with changes to the proposed

text as published in the June 20, 21108 issue of the Texas Register (33 TexReg 4771). Project

Number 34890 is assigned to this proceeding.

The new §25.217 addresses interconnection, renewable energy credits, and the sale of out-flows

for distributed renewable generation.. The amendment to §25.242 establishes metering

requirements for DRG. The rules are competition rules subject to judicial review as specified in

PURA §39.001(e).

A public hearing was held on August 5, 2008, in which comments were received from Texas

Energy Efficiency Partnership (TEEP), Public Citizen, and ,the Sierra Club. The commission

also received written comments from. James and Annette Hetrington; the Solar Alliance (Solar

Alliance); the Texas Renewable Energy Industries Association (TREIA); the, Texas Solar Energy

Industries Association (TXS.EIA),`TXU Energy (TXU); the Alliance for Retail Markets (ARM);

Henry B. Williams;. Jeff and Donna Beaver; Reliant Energy (Reliant); .13elib'.Volt; Oncor Electric

Delivery Company (Oncor); Southwestern Electric Power Company, AEP Texas North.

85


PROJECT NO. 34890 ORDER. PAGE 5 OF 56

However, even though PURA §39.914 and §39.916 do not apply to Entergy and SPS, PURA,

§§14.001,35.061, and 38.002 give the commission the authority to limit the use of roil baekt

meters by Entergy and SPS in the same manner as Pf.TRA §39.914 and §39.916 limits their

use for all other electric utilities. The commission adopts this approach for Eutergy and

SPS, because it advances the goals for renewable energy as provided in PURA §39.904 and

in order to consistently treat all similarly situated DRGOs.

P[TRA §39.914 and §39.916 do not specify a deadline to eliminate the use of roll-back

meters. As a result, the commission has discretion in the manner that it transitions existing

QFs away from roll-back meters. The commission concludes that a QF operating under

existing §25.242(h)(4) in an area without customer choice will be allowed to continue to use

a roll-back meter until its existing contract requiring the use of a roll-back meter expires.

This approach avoids affecting existing contractual rights. However, the rolt-6ack meter...^.^ ^must be replaced prior to the introduction of customer choice because, as discussed above,

the separate metering of in-flows and out-flows are necessary to meet the requirements of

PUPA §39.914(c) and §39.916(i). In addition, for a QF whose contract does not require the

use of a roll-back. meter, the commission has established a deadline of June 30, 2009 for the

electric utility to replace the meter, which is a reasonable period of time for the electric

utility to meet this requirement.

General Comments

In their initial comments, ARM and AEP expressed support for §25.217, finding it

straightforward, simple, and consistent with PURA §39.914 and §39.91 6. They went on to state

E:LI,



Commission Response

The commission agrees with ARM and Reliant that PURA §39.914(c) does not make sale of

surplus electricity obligatory for school districts and adopts ARM's proposed language.

ARM recommended that the term "facility" be replaced with the term "premise" given that the

REP serves the location rather than just a building or facility.

Commission Response

The commission agrees that use of the term "premises" is more appropriate, because the

ISD-DG may be separate from the consuming facility served by the REP.

Solar Alliance stated that the DRGO may not necessarily be the retail customer who has the

relationship with a REP or an electric utility. Solar Alliance stated that it is not appropriate to

refer to the DRGO in subsections (fi} and (g) in the context of sale of out-flows because it is the

owner of the DRG who is the entity that has the right to sell the out-ftbws - not the retail

customer.

Commission Response

The commission declines to address at this time whether a person other than the end-use

customer may own DRGCI or ISIS-SG. Having third parties own DRG and ISD-SG may

have a number of benefits, including tax benefits and economies of scale. However, it is

unclear whether a third party could own the facilities without becoming an electric atility,

with all the associated duties and responsibilities, and the commission will refer the matter

87

Distributed Generation Interconnection Manual

Documents

Transcript of Distributed Generation Interconnection Manual