• Energy-Efficient Products
• Technology Deployment
  • Technology Deployment List
  • Goals & Initiatives
  • Solid State Lighting
  • Working Group
  • Distributed Energy Resources/Combined Heat & Power
    • Distributed Energy Resource Basics
    • Combined Heat & Power Basics
    • Federal Requirements
    • Market Studies
    • Project Implementation
      • FEMP Assistance
      • Environmental Siting Guide
      • Interconnection & Permitting Guide
    • Resources
    • Contacts
  • Resources
• Renewable Energy

Utility-Connected Distributed Generation: Lessons from the Federal Sector

An ever-increasing number of Federal energy and facility managers are installing distributed generation (DG). If the DG is connected to the utility system, it needs to meet the requirements of an interconnection agreement with the utility, even if it rarely or never sends power back into the grid. Whether that agreement is 2 pages or 10 depends largely on the size and type of system installed as well as whether or not excess electricity is generated.

Interconnection Lessons Learned

Because interconnection of a DG system can be a daunting process, FEMP is hopeful that agencies can learn from one another's interconnection experiences. Valuable information from past Federal DG projects is detailed below.

If your agency or facility has completed a DG project and you would like to share your experiences, please contact Andy Walker at andy.walker@nrel.gov.

Central Utility Plant

Description: Central utility plant with 5.644 megawatts (MW) prime power, plus 2 MW standby generator

Location: Mid-Atlantic Region

Purpose: Combined heat and power (CHP) to provide both hot water and electricity for a campus

Utility point of contact: There were three specified points of contact at the utility: the site representative, the U.S. Government project representative, and the interface with the independent system operator. Throughput to engineering and construction was slow through any path.

Interconnection requirements (i.e., protective relays, switches, and so forth): The utility required electronically controlled paralleling switchgear and an expensive remote terminal unit for their SCADA system. They are also considering imposing standby fees for the capacity requirements they need to keep on hand in case the DG system goes down.

Primary delay/issue: Environmental permitting as noted in the summary

Summary: Some delays were encountered for this project. Reasons for these delays included the following:

• Interconnection standards were plentiful but not necessarily current. For example, the documentation still specified electromechanical protective relays that the utility no longer used in its own equipment.
• The 4-week review cycle specified in the interconnection documentation did not include input and output processing, which added about 2 weeks.
• Documentation submitted for review was not sent to the same person for review each time, which resulted in lack of continuity and added delays.
• After 48 weeks of utility review, utility engineers realized during a construction meeting that the switchgear did not meet requirements. The necessary equipment had to be retrofitted in the field at considerable cost and effort.
• Utility had been slow to move on the tasks they are responsible for, causing unanticipated project delays.
• Fees proposed by the utility for interconnection costs of cable and two circuit breakers amounted to $1.7 million; agency project estimators put a price tag for equivalent work at $400,000.
• The utility's Interconnect Service Agreement (ISA) had site-specific information scattered among a thick boilerplate document. This document required General Services Administration (GSA) review. Although the ISA for this project was almost identical to another project recently reviewed, GSA lawyers required 8 months to review the document because the site-specific items scattered throughout the boilerplate prevented them from being able to say: "We've seen and approved these sixty pages, let's check to make sure the address and generator size are correct on the four site-specific pages."
• The environmental permitting was a long process even for this small plant. It is anticipated that the project could encounter a minimum of 18 months for permitting of an upgrade that will expand the plant beyond 10 MW.

Gas/Oil Combustion Turbines

Description: Two 5 MW gas/oil combustion turbines

Location: Mid-Atlantic Region

Purpose: To provide combined heat and power for controlling energy costs

Utility point of contact: Single utility point of contact

Insurance requirements: None

Summary: Environmental permitting produced significant delays in contrast to interconnection delays. The project required installing current-limiting protection devices and included a utility requirement of facility control whereby the utility can trip outgoing breakers. The project encountered a certain degree of lack of understanding of requirements due to competing jurisdictions: the local utility and the independent system operator. Still, environmental permitting caused the primary delay.

Photovoltaic System (47 kW)

Description: A 47 kilowatt (kW) photovoltaic (PV) system

Location: Western Region

Purpose: Load reduction, reduction in utility costs, reduction of point source pollution, and public education

Summary: No application or interconnection fees or associated delays were involved. The project encountered no barriers from the serving utility. The only reported delay was due to this project being the first interconnection project exceeding 30 kW between the agency and the utility. The agency had executed a previous project for a smaller installation. The size of the DG system made a difference as to whom the agency dealt with at the utility for the interconnection paperwork.

Modifying an existing legal contract is much easier than creating a new one, so GSA authorized the interconnection for this project as an exhibit on the areawide contract, greatly simplifying the process. The agency suggested that other agencies go through the process and share their insights with anyone else considering such systems. They also suggested that many remote Federal installations already have permitted generators as emergency backup systems and there may be an advantage to permitting and interconnecting new DG systems when they are located "behind" the already permitted generator.

Photovoltaic System (127 kW)

Description: A 127 kW PV system

Location: Western Region

Purpose: Power generation, peak shaving, cost savings, and emissions reductions

Utility point of contact: Single utility point of contact

Summary: There were no application and interconnection fees and associated delays. The only real barrier encountered was that the utility's existing interconnection agreement was designed for large central station generation, not a small PV system. As such, the agency had to work with the utility to modify the existing interconnection requirements to fit the scale and type of project. The project manager reported no critical barriers, stating that the utility was very flexible. The project encountered no additional project cost or time barriers.

Diesel-Engine-Driven Generators

Description: Eight 1.875 MW diesel-engine-driven generators

Location: Mid-Atlantic Region

Purpose: Installed for peak shaving and backup generation as-needed

Utility point of contact: Single utility point of contact

Summary: The diesel-engine-driven generators were combined with selective catalytic reduction (SCR) technology to control exhaust emissions. In addition, the project utilized approximately 2 MW of existing diesel-engine-driven generators. The new SCR will allow additional run hours when needed.

Because no exporting of power is necessary, the utility requirement for protective relaying and coordination with the utility system did not pose a barrier. Environmental permitting produced significant delays in contrast to interconnection delays.