© PowerServices, Inc. December 2014 Presenter: Peter J Rant, PE Vice President, PowerServices 1616 E. Millbrook Road, Suite 210 Raleigh, NC 27609 Phone:

©PowerServices, Inc. December 2014

Presenter:

Peter J Rant, PE

Vice President, PowerServices

1616 E. Millbrook Road, Suite 210Raleigh, NC 27609Phone: (919) 256-5900Branch Offices: Clemson, SC Maitland, FL

A Current Perspective on Solar


PowerServices, Inc.


3

Strong Ties With Public Power

• 2001 PowerSecure becomes an ESP Partner with ElectriCities of NC as the endorsed provider of distributed generation. Fourteen years later the partnership is still strong with over 120 MW of generation installed at over 200 sites

• Hometown Connections partner since 2013


Topics

1. Overview

2. Interconnection Issues

3. Impact

4. Financial Issues

5. Case Studies

6. Conclusion

4


Looking at Both Sides

• Interconnection applicants

• Utilities

5


How to Think About Solar

• DG – Distributed Generation

• DER/DR – Distributed Energy Resource

6


Solar Building Blocks

• Panels – Around 300 watts each• Racks

Roof or Ground Fixed or Tracking

• Inverters String Micro

7



• Cabling• Combiners• Grounding• Switchgear• Transformers• Protective

Devices/Interconnection• Metering

8



9



10



11



12



13


10 kW Demonstration Project

14


OVERVIEW


Perspective on DG/DER


Why Solar? Why Now?


18

Solar Setting Growth Records

• From now until the end of 2016 “an unprecedented boom”

• July 2015 – Dec. 2016 Forecasts up 18 GW, more than the cumulative capacity built as of June 2015

• 2017 – 2019 Uncertainty over growth

• After 2020 Installed costs reach new lows “driving a new era of growth”

Source: Q2 2015 US Solar Market Insight Report

©PowerServices, Inc. December 2014 1

9

Overview

How to?• Design• Construct

What to?• Consider• Evaluate• Focus Upon


0

Overview

Dynamic Environment• Regulatory Mandates• Subsidies• Risk• Venture Capitalist• Ratepayers


1

Overview

Renewable Type• Wind• Solar• Biomass• Hydro

• Solar is attainable where others are not


INTERCONNECTION


3

InterconnectionUtility Concerns• Electric power distribution

systems designed for one-way operation

• Personnel safety and grid stability are dominant concerns

• Utilities reluctant to rely on customer-supplied protective relaying schemes that are not well-known


4

InterconnectionCustomer Concerns• Interconnection costs (e.g.,

engineering and system impact studies, system upgrades) can be disincentive for smaller-sized projects

• Most requirements not understood by customer, may appear restrictive

• Manufacturer, customer, and utility DG activities not frequently coordinated


5

InterconnectionPrimary Safety Concerns

• Utility protection scheme Impact on circuit breakers, reclosers,

and fuses Can impact clearing of faults

• Creation of unintentional island Lineman sees grid supply open, and

believes feeder is de-energized


6

InterconnectionThe Application Process

• Steps to operate in parallel with the distribution utility

• Location, technical and design parameters

• Operational and maintenance procedures

• Systemic approach of study


7

InterconnectionQueue

• Why?

• Impact to Municipality

• Purpose

• Have a process


8

InterconnectionApplication Process


9

InterconnectionScreening Process


0

InterconnectionStudy Process • To be used when DG project:

Is larger than __ MW but no larger than __ MW

Is not certified, or Did not pass the Screening Process

• Consists of: Minimum engineering review System Impact Study Facilities Study


1

InterconnectionStudy Process


2

InterconnectionInformation Requirements and Study Fees• Equipment is “pre-certified”• Capacity is 500 kW or less• Equipment is designed to export

no more than 15% of total load on feeder (based on most recent peak load demand) and

• Equipment will contribute not more than 25% of maximum potential short circuit current of feeder


3

InterconnectionUnintentional Islanding• DR is certified to pass applicable non-

islanding test

• DR installation contains reverse or minimum power flow protection

• DR contains other non-islanding means: Forced frequency or voltage shifting Transfer trip


4

InterconnectionIslanding


5

InterconnectionGrid Abnormalities• Four types:

Underfrequency – below 59 Hz Overfrequency – above 61.5 Hz Undervoltage – below ANSI Range B

< 88% PU Overvoltage – above ANSI Range B

>110% PU• During underfrequency events

Essential for DER assets to remain connected to support bulk system

Support of distribution system important, but secondary


6

InterconnectionGrid Abnormalities

• During overvoltage and overfrequency events:

DER should self regulate and attempt to reduce voltage or frequency


7

InterconnectionWhy is Ride Through Needed?

• Ride through to avoid cascade failure during severe underfrequency events and undervoltage events

• DER should remain online until local load shedding schemes have activated

• If DER is lost ahead of load, grid instability may quickly worsen and possibly lead to cascade failure


8

InterconnectionHigh Voltage Ride Through

• Reduce generation quickly Limit magnitude and duration

without tripping

• Bring DER back online quickly to minimize grid disruptions


9

InterconnectionLow Voltage Ride Through

• Improve system stability

Minimize sudden loss of DER during short duration low voltage events

Avoid desensitization of overcurrent protection during feeder faults


0

InterconnectionHigh Frequency Ride Through

• Reduce generation

Quickly to limit magnitude and duration

Bring DER back only quickly following short duration high frequency events to minimize disruptions


1

InterconnectionLow Frequency Ride Through

• Reduce Chances of Cascade Failures of Bulk System

Miminize sudden loss of DER during low frequency event

Coordinate frequency trip behavior of DER with utility frequency load shedding schemes


2

InterconnectionOperating Modes

• Historically, inverter based DER has operated only in one of two modes Normal Operation – full available

current Tripped – offline

• Ride through requirements new mode – “Momentary Cessation” Mode in which DER has ceased to

energize grid but has not tripped


3

InterconnectionOperating Modes

• Difference between momentary cessation and tripped determined by: Duration of excursion Criteria for “Return to Service” Ramp rated limitations during

“Return to Service”


4

InterconnectionReal & Reactive Power Control Functions• Real Power Control

Commanded Max Power Volt/Watt Frequency/Watt

• Reactive Power Control Commanded VAR Fixed PF


5

InterconnectionRegulatory Issues• IEEE 1547 / 1547.1 revision

considers ride through 1547 currently under revision, and

adding ride through requirements When 1547 revision complete,

1547.1 test procedures to be developed

• UL 1741 to address ride through, real / reactive power functions, and new advanced islanding as optional tests Continuing updates


6

Interconnection

NERC/RF/PJM

BES


IMPACT


8

Impact


0

Impact


1

Impact


2

ImpactOverall Trends

• Residential systems accounted for 94% of individual installations

• Residential systems accounted for only 19% of PV capacity installed


3

Impact


4

Impact


FINANCIALISSUES


6

Financial Issues


Financial Issues

Before De-regulation• Customer Charge• Energy/Demand• Facilities

After De-regulation• Customer Charge• Wires Charge• Commodity

Charge, etc. (provider last resort)

• Facilities

57

Previously…

Retail Rate Determinants


Financial Issues

Renewables Impact

All previously included Before and After De-regulation, Plus:• Backstand• Net Metering• Buy All, Sell All• Avoided Cost• On Peak/Off Peak

58

Now…

Retail Rate Determinants


9

Financial IssuesNet Meter• Generate own needs and serve

grid (retail)• Bank credits

Costs / Rate Recovery

Buy All / Sell All Retail Rate Avoided Cost


0

Financial Issues

Plans to install solar on 1,000 retail stores by 2020 (25%)

Average Annual Increase $185.00

Wal-Mart

California Utility Customer


1

Financial Issues

Distribution System

1/0 ACSR – 3Ø

(POD)


2

Financial Issues

Generation Added

1/0 ACSR – 3Ø

(POD)


3

Financial Issues

Facilities Charge

Facilities Charge

1/0 ACSR – 3Ø

(POD)


4

Financial Issues

Electric System Impact Fee

Facilities Charge


1/0 ACSR – 3Ø

(POD)


5

Financial Issues

Total Fees???

Facilities Charge


3,000,000kWh x $0.005/kWh = $15,000/yr.

$75,000 – Capital Cost@1% = $750/month= $9,000/yr.

1/0 ACSR – 3Ø

(POD)


6

Financial Issues

“We don’t have to pay this fee to the IOU”


7

Financial Issues

Inverter Cost and Reliability Impacts


CASE STUDIES


9

Case StudiesLoad Shapes


0

Case StudiesLoad Shapes

18,690,872

18,031,518

24,126,526

Annual kWh


Case Studies

• Duke Energy Carolinas Background

• N.C. Senate Bill 3 (SB3)• Established renewable energy goals

for N.C. utilities• Included service areas of Duke

Energy• Starting at 3% in 2012 and leveling

off at 12.5% in 2020• Encouraged utilities to meet goal

using energy from variety of renewable resources

• Solar photovoltaic projects have dominated Duke Energy’s efforts to comply7

1


Case Studies

• Duke Energy Carolinas Goal to determine impacts of solar

PV on ancillary services, generation production cost, and power flows and losses

Three scenarios simulated• Compliance solely with goals and

schedules of SB3• Modest increases over SB3 goals• More rapid penetration of PV

Penetration evaluated ranged from 673 MW to 6800 MW (2% to 20% of peak load)7

2


Case Studies

• Duke Energy Carolinas Findings

• Net load (load minus PV production) variability increases with PV penetration

• PV penetration increasing to 20% of peak load, system day-ahead planning reserve requirements increase 30% compared to values without PV

• Regulation reserve requirements increase to 140%

73


Case Studies


Transmission• PV supplies, real and reactive power, result

in an increase in voltage magnitude proportional to amount of PV output at sub-transmission buses

• Most affected areas in Duke Energy system in 44 kV systems – violated upper limit in spring and fall during light-load conditions

• Amount of energy loss reduction in transmission network due to distributed PV dependent upon many factors

• Transmission loss reduction due to PV between 2.6 and 5.7% as percentage of PV output

74


Case Studies


Distribution• On average, feeders show reduction in

losses, particularly during summer season• Equipment overloads tended to decrease

due to offset of local power flow by local generation

• A few cases experienced additional overloads mainly due to reverse power flows

• Feeders servicing PV installations experienced greater voltage fluctuations, and consequently more control actions voltage regulation devices

• Increased regulator operations reduce asset life

75


Case Studies

• California DG Goal Governor’s goal of adding 12,000

MW of DG to grid by 2020 creates technical challenge

At this scale, Distributed Energy Resource systems have potential to provide significant environmental and financial benefits

Achieving goal will require fundamental paradigm shift in technical operation of distribution system

76


Case Studies

• California DG Goal Core technical challenge:

• DER systems interconnected to distribution grids designed for one-way flow of power

• DG requires two-way power flows dispersed throughout system

• Source is renewable energy, where generation is intermittent

77


Case Studies

• California DG Goal Anti-islanding protection

• Current Rule 21 identifies anti-islanding protection requirements in IEEE 1547, including clearing times

• IEEE 1547 does not permit voltage ride-through and frequency ride-through functions

• While Rule 21 requirement remain the same, SIWG proposes islanding settings be changed

• Proposed expansion of high and low voltage and frequency protection limits permit I-DER systems to ride-through temporary voltage or frequency anomalies

78


Case Studies

• California DG Goal

79


Case Studies

• California DG Goal

80


Case Studies• Massachusetts DG Goal

Governor and Energy and Environmental Affairs Secretary celebrate 250 MW of solar energy installed

Reached Patrick-Murray Administration goal 4 years early

Announced new goal of 1,600 MW by 2020

81



Utility proposed smart inverter technology program to Massachusetts DPU• 20 MW at approx. $100M from

ratepayers• Three categories

• 60-200 kW• 201-500 kW• 501-1,000 kW

82



DC Rating: 1,000 kW DC Rating: 1,000 kW Array Azimuth: 180.0 Array Azimuth: 225.0

83

AC Energy (kWh) AC Energy (kWh)Month from 1 MW Month from 1 MW

1 83583 1 683702 98004 2 852333 114805 3 1028944 111403 4 1060835 119033 5 1155056 112682 6 1130687 120227 7 1164138 122071 8 1172019 110201 9 9883610 107035 10 9261111 72354 11 6085012 72282 12 72282

Year 1243680 Year 1149346



84



85



86



87


CONCLUSION


ConclusionDER– It’s Coming-It’s Here, Be Prepared• DG presents opportunities and risks for

electric utilities• Environmental benefits• May help utilities avoid ancillary

service costs• May help customers reduce electric

bills and over long term save money• Challenges

Under-recovery of costs Increased difficulties in operating electric

grid Safety issues Cross-class subsidization

89


ConclusionDER– It’s Coming-It’s Here, Be Prepared• Municipalities situated to deal with DG

Independence of utilities offers opportunity to develop more equitable rates

Do not stifle development of resources or unduly burden non-DG customers

May face pressure to encourage development of DG resources at expense of revenue and operational stability

Fully understand impact of distributed resources on your systems and explain impacts to your communities

Public outreach essential90


Conclusion

91

Municipalities should prepare

for potential outcomes from DG/DER integration


1616 E. Millbrook Road, Suite 210Raleigh, North Carolina 27609Toll-Free: (866) 231-6610Phone: (919) 256-5900Fax: (919) 256-5939

© PowerServices, Inc. December 2014 Presenter: Peter J Rant, PE Vice President, PowerServices 1616 E. Millbrook Road, Suite 210 Raleigh, NC 27609 Phone:

Documents