Transmission for Renewable Energy

1Law of Renewable Energy WEBINAR SERIES

Transmission for Renewable Energy:Efficient Solutions to Integration Issues

Law of Renewable Energy

WEBINAR SERIES

PRODUCED BY EUCI ● June 23 , 2011

To order any of these books please contact

Angel Giovannone at (503) 294-9422 or amgiovannone@stoel.com

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Jason A. Johns

Associate

Portland, OR

(503) 294-9618

jajohns@stoel.com

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Marcus Wood

Partner

Portland, OR

(503) 294-9434

mwood@stoel.com

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Jennifer H. Martin

Partner

Portland, OR

(503) 294-9852

jhmartin@stoel.com

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Timothy L. McMahan

Partner

Portland, OR

(503) 294-9517

tlmcmahan@stoel.com

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Agenda

• Interconnection

• Reliability

• Transmission Service

• Market Changes

• Permitting

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Interconnection

• Which interconnection procedures apply?– First, you need to determine if your interconnection is subject to

state or federal jurisdiction

– If Federal, the procedures that apply may depend on thefacility’s size

• Small Generator = ≤ 20 MW

• Large Generator = > 20 MW

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Interconnection Services

• What types of interconnection service are available?– Energy Resource service = Allows generator to connect to the

transmission system and be eligible to deliver electric outputusing existing firm or non-firm transmission on an “as available”basis

– Network service = Allows generator to connect to thetransmission system:

• In a manner comparable to that which the TP integrates its owngenerating facilities to serve native load customers; or

• In an RTO or ISO with market-based congestion management, inthe same manner as all other Network Resources

• Which service should I choose?

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Negotiating theInterconnection Agreement

• Under FERC’s LGIA, the terms are standard and changes must beapproved by FERC

• Negotiations focus on:

– Milestones (schedule and payments)

– Cost allocation (contingent facilities)

– Operational Characteristics

• Facilitating use of one interconnection capacity by more than oneproject or owner

– Phasing

– Joint Ownership Agreements

– Partial Termination

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Queue Congestion

• Small financial commitment to enter queue ($10k)

• Three serial studies

– Feasibility Study

– System Impact Study

– Facilities Study

• Little disincentive to withdraw; restudies were common

• So was suspension

• Little tied an interconnection customer to its LGIA,resulting in some walking away

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Interconnection Queue Reform

• December 2007 Technical Conference– Serial study practices being slowed by new entry into queues &

speed at which projects could develop

– Interconnection delays causing trouble in meeting RPS obligations

• March 2008– Order issued as a result of technical conference

– RTOs/ISOs ordered to report status of respective queues

– Identified three needed changes:

• Increased requirements for entering the queue

• Eliminate the Feasibility Study

• First-ready, first-served vs. first-come, first-served

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Queue Backlogs

• California ISO

– 361 pending interconnection requests (105,000 MW)

– 68,000 MW of renewable energy

– CAISO’s historic peak demand: 50,270 MW

• Southwest Power Pool

– 255 pending interconnection requests (57,000 MW)

– 50,000 MW related to wind generation (176/196 requests over twoyears)

• Midwest ISO

– 348 pending interconnection requests (80,000 MW)

– 65,000 MW related to wind generation

– Could not clear queue until 2050

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The Results

• California ISO– Clustering with queue windows (two per year)

– 2 studies (Phase I and Phase II)

– Increased, non-refundable financial requirements

• Southwest Power Pool– 3 queues, your choice (IFS, PISIS, DISIS)

– Suspension only allowed for 18 months after Effective Date

– Shared Network Upgrades will be built upon execution

• Midwest ISO– Milestones provide “first-ready, first-to-proceed”

– No suspension for economic reasons (force majeure only)

– Once a GIA is signed, Network Upgrades will be built

– ABSOLUTELY NO AMENDMENT TO ISD

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Risk Analysis

What are the risks in filing unexecuted?

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Interconnection Capacity Rights

Aero Energy, 116 FERC ¶ 61,149

• Developer sought interconnection and transmissionservice on jointly-owned transmission line

• Transmission line joint owners intended to developgeneration that would use respective capacity rights

• Sagebrush claimed all but 3 MW of transmissioncapacity was reserved

• FERC stated Sagebrush partners have capacity rights, if:– Demonstrate pre-existing contractual obligations; or

– Specific expansion plans, including definitive dates, and milestones met

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Milford Wind Corridor

129 FERC ¶ 61,149

• Milford’s Request:– 88-mile, 345 kV interconnection line with 1,000 MW capacity

– Built to serve multi-phase wind development

– Closed financing for entire line; PPA for 200 MW

– Accelerated 100 MW of Phase II

– All phases to be operational by 2015

• FERC approved request based on specific expansionplans, and material progress toward meeting milestones

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Terra-Gen Dixie Valley

132 FERC ¶ 61,215

• Owner of the Dixie Valley Line

• 60 MW existing geothermal facility

• Sought priority rights to 360 MW

• FERC Ruling– Awarded priority to 60 MW capacity

– Remaining 300 MW subject to open access

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Boundary Tested

Puget Sound Energy, 133 FERC ¶ 61,160

• Developing multi-phased 1,250 MW wind project

• 1,250 MW interconnection built with 350 MW Phase I

• Environmental studies; EIS; conditional use permit

• Interconnection agreement signed for 1,250 MW

• Phases IV and V targeted for 2029

• FERC Ruling– Puget may reserve to serve native load

– Line must be placed under OATT

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Reliability Standards

• Are reliability standards mandatory?– YES10

– Generators are obligated to register

• Who is subject to registration?• Single 20 MVA unit

• Multiple units at 75 MVA

• Regardless, are you material to reliability?

• Who oversees compliance? NERC, RROs

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WECC vs. Gen Ties

Cedar Creek Wind

• 76-miles, 230 kV tie

• Ownership change 4 milesfrom POI

• TO operatedrelaying/protection systemsat POI

• 10 x 34.5 kV, 3 x 230 kVbreakers at generator

• Registered as TO/TOP

Milford Wind Corridor

• 88-mile, 345 kV tie

• Full ownership

• Interconnecting at sub with2 GW connected

• 2 x 168 MVA GSUs on siteat generator

• Registered as TO/TOP

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FERC Decision

Cedar Creek Wind

• Material to reliability

• CC owns/controlsequipment on one end ofthe tie line

• Must be coordinated withequipment at remote end

• Fault could lead to loss of600 MW CCGT

Milford Wind Corridor

• Material to reliability

• Owns/operates equipmentat generator

• Must be coordinated withequipment at remote end

• Fault could lead to loss of1800 MW

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Nobody wants responsibility for a blackout

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Transmission Service

• My facility is already interconnected, why do I needtransmission service?

– Interconnection service provides no delivery rights

– Unless your purchaser is taking power at the busbar, you willneed to purchase transmission service

• Where do I reserve and buy transmission service? OASIS

• What types of service are available?

– Point-to-point vs. Network

– Short-term vs. Long-term

– Firm vs. Non-firm

– Conditional firm

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Transmission Service

• Are transmission providers required to treat everyone bythe same rules?– Yes, FERC Order 888 requires that transmission service be

provided on an open, non-discriminatory basis

– Transmission providers particularly may not favor affiliates

• What are the types of transmission providers?– RTOs/ITCs are independent because they do not actually own or

control electric generation resources

– Many transmission owners, however, remain as integratedtransmission and generation utilities

– Some types of transmission providers (e.g., BPA, TVA, WAPA) aresubject to limited FERC authority

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Obtaining Transmission Service

• Are there costs associated with requesting transmission?– If the system does not have available capacity, a developer may

have to pay to upgrade the transmission system toaccommodate the requested service

• How much will transmission cost?– Integrated transmission/generation utilities may charge the

higher of:

• Incremental costs; or

• An embedded cost rate

Associated with the requested transmission service

– RTO transmission service may be priced on a different basis

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Imbalances

• When do imbalances occur?– When the hourly generation as scheduled is different than the

actual hourly generation delivered from a facility

– Someone has to make up the difference

• How are imbalance penalties assessed?– The charges are tiered, i.e., the larger the deviation from your

schedule, the larger the charge

– Variable generators are exempt from the most expensive tier

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Imbalances (cont.)

• How can I avoid imbalances?– Good forecasting

– Shaping & Firming arrangements whereby the supplier will takeor provide energy, as applicable, in hours when the actualgeneration differs from the scheduled amount

– Participating in applicable RTO intermittent generation protocols

– Delivering to the purchasing utility at the generation projectbusbar

– Delivering using network transmission service

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Ancillary Services

• Purpose = products designed to maintain reliability onthe grid

• Types of Ancillary Services

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Intra-Hour Wind Integration

• What is intra-hour wind integration service?– Some transmission providers claim that intra-hour variations in

output of intermittent resources impose added costs on thetransmission system operator

– Integration service follows variable resources with dispatchablefacilities in order to make up moment-to-moment differences ingeneration output within the scheduling hour

• Example: BPA

• Best Approach: pass the costs to your purchaser

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FERC VER NOPR

• Issued November 18, 2010

• Comments were due March 2, 2011

• Issued to address barriers to the integration of variableenergy resources

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FERC VER NOPR (cont.)

• FERC proposed to revise the current pro forma OATTand LGIA in three ways to address VER integration:– Intra-hour scheduling, at intervals of 15 minutes (TPs can permit

shorter scheduling intervals)

– Power production forecasting

• TP – those TPs who propose volumetric differences in the Schedule10 rate would be required to provide VER power productionforecasting

• ICs – requirement to provide meteorological and operating data tointerconnecting TPs; requirement to report forced outages reducinggenerating capacity by 1 MW or more for 15 minutes or more (SGIAexempted)

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FERC VER NOPR (cont.)

– New Generator Regulation Service, Schedule 10, to give TPs amechanism to recover the costs of capacity used to providedgenerator regulation reserves , both for the transmissioncustomer serving load within the transmission provider’s BAAand for exports

• Applicable to all generators, but a TP may apply to FERC to chargea volumetric difference for VERs if the TP can justify that the VERsimpose a different per unit impact on the system

• BUT, no volumetric difference permitted without intra-hourscheduling and power production forecasting

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• Pre-2009– No separate service or rate

• FY 2009– Within Hour Wind Balancing Service Rate

• $.68/kw.-mo.

• FY 2010-2011– Within-Hour Wind Balancing Service Rate

• $1.29/kw.-mo.

• Initially proposed at $2.72/kw.-mo

The Rapid Revolution of BPA’sWind Balancing Service

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• Three components– Regulation

– Following

– Imbalance

• Based on a pre-established amount of balancingreserves

• DSO 216

• Persistent Deviation Penalty

A Closer Look at BPA’sCurrent Wind Balancing Service

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DSO 216

• How does this fit in?– BPA monitoring inc or dec reserves deployed from the FCRPS

– Requires different responses:

• 85% deployed (warning)

• 90% deployed

– Overgeneration: wind plants must limit wind generation to theirschedule plus proportional allocation of dec reserves

– Undergeneration: wind plant schedules curtailed to actualoutput plus proportional allocation of inc reserves

• 100% deployed

– Overgeneration: wind plants limited to schedule

– Undergeneration: schedules cut to actual output

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Source: www.bpa.gov, as of May 3, 2011

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Source: www.bpa.gov, as of June 20, 2011

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Source: www.bpa.gov, as of June 20, 2011

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Environmental Redispatch

• Background – the “June Event”

• BPA issues proposal to address high water / high windevents; seeks comments

• Final Interim Record of Decision issued May 13, 2011

• Challenge pending at FERC

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CAISO Market Changes

• Renewable Integration Market & Product Review –Phase 1; proposal:– Lower energy bid floor from -$30/MWh to -$300/MWh

– Elimination of PIRP after end of 2014; limited grandfathering

• Renewable Integration Market & Product Review –Phase 2; early stages

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Queue Reform, Rd. 2

• Cal ISO GIP– Clearer financial security posting requirements

– Scalability issues addressed

• Midwest ISO– Tougher to proceed to DPP

– Net Zero Interconnection Service

– Dispatchable Intermittent Resource

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Generation Transmission Linesand Permitting

• What if it’s part of generation facility?

• What if it’s an independent energy facility?

• The “but for” test: “related and supporting” or “stand alone”?

• When does a line upgrade become a new facility? Ramifications?

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Ramifications in Permitting

• Interrelated and interdependent facilities-NEPA and otherunpleasantness

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Locating Transmission Lines

• The pressure to co-locate transmission lines within existing corridors(new lines on existing poles; new poles)

• Logic from the perspective of permitting agencies-land disturbanceand environmental considerations

• Issues of facility control, outages and O& M

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What’s In It for the Land Owner?

Lost opportunities, costs and agricultural impacts

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Partnering with Utilities

• Land control – advantages of partnering with utility

• Off-site substation construction costs, engineering anddesign, and practical capabilities of “going it alone”

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QUESTIONS?

Law of Renewable Energy

WEBINAR SERIES

PRODUCED BY EUCI ● June 23 , 2011

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