Richard Seguin is principal engineer, distributed resources, system planning and engineering for Detroit Edison. He has 35 years of experience in electrical system planning, design and operation. Since 2002, he has installed 18 distributed generation projects on the Detroit Edison system totaling nearly 9 MW. He holds a BSEE degree. SeguinR@DTEenergy.com

William J. Steeley is a senior project manager in distributed resource and energy storage at EPRI. His work experience also includes 24 years at PG&E in transmission planning and in PG&E's R&D department where he was project and program manager for various generation and T&D projects. He holds BSEE and MSEE degrees from Ohio State University and is a registered professional engineer in California. WSteeley@epri.com

In these early applications, DTE Energy learned several key lessons from early distributed energy resources (DER) applications:

One of the expectations of management was to make sure that DER projects made sense economically. Therefore, an important part of the DER economic evaluation, which compares traditional T&D solutions to DER solutions, is to compare appropriately. The cost of the DER alternative should not be based on the cost per kilowatt of capacity added, but rather compared to the cost to resolve the capacity shortfall problem.

For example, consider the cost to build a new substation for an area experiencing loading problems. A new 30-MW substation will cost around $6 million, which translates to a cost per kilowatt of $200. This will usually be cheaper than any DER alternative when factoring in the cost of buying DER. However, this assumes that one will be using the whole 30 MW immediately. Generally, most overloads are not 30 MW; they are more on the magnitude of 1 or 2 MW. The cost to resolve a 1-MW capacity shortfall problem with the same $6 million substation is $6000/kW. Now comparing this cost of a 1-MW DER alternative, approximately $450/kW, it begins to look very favorable for the “DER and Defer” strategy.

After DTE Energy integrated this new measure on all new capital projects, the next step was to develop a DER capital project budget. Although the DER and Defer strategy permits better economic use of resources, it is not the only reason to use DER. After a probability analysis is performed, it becomes apparent that the load will arrive before some T&D projects will be completed. DER can be a tool to help make sure that these projects are addressed even if the final T&D solution is years away. DER can become a planned budget line item to rescue the project when and if it cannot be done (storms, right-of-way, community approvals and faster-than-anticipated load growth). DER also can be used as a “Do Nothing” alternative in the capital project budget process. This becomes not only part of a project alternative analysis, but can be used as preplanned recovery plan.

There is another way to look at the economics of using DER. The purchase of a portable substation is not based on the need to facilitate maintenance or for the change-out of a transformer for one particular instance. It would not be possible to justify its purchase on that basis alone. The portable substation is justified on repeated use over time. This is the same rationale used to demonstrate the cost effectiveness for the purchase of DER.

The DTE Energy DER team arrived at this truism after a review of the economics of its first DER installation. This project involved the use of a leased portable generator in an emergency. Over the course of a subsequent economic evaluation, the team demonstrated that purchasing the DER was more economically sound than leasing one. Once a DER is purchased, the comparison is between the DER installation cost and the cost of traditional T&D cost.

In order for DER to be successful, it takes real management support. At DTE Energy, this support came from the highest levels, specifically the CEO and president.

This management support came in the form of naming a champion to shepherd the integration. In DTE Energy's case, a small DER planning group was established and given director-level reporting.

Although utility-owned DER is sometimes a cost-effective solution to a summer peak loading situation, it is not the only answer. There may be customer-owned generation on the circuit that can be used under a joint-use arrangement with the customer.

This must always be included in the site-selection process.

Location	Day-to-Day Rating (amps)	Emer Rating (amps)	Peak Rating (amps)	2002 Hours Above	2003 Hours Above	2004 Hours Above	2005 Hours Above
Adair DC322	408	520	650	182	81	—	—
Grosse Ile DC2841	500	636	684	45	3	40	234
Shores DC1770	493	552	553	22	2	41	122
Union Lk DC1688	524	760	860	265	55	188	410
Wayne DC9435	577	789	636	27	9	24	—
Milford DC8103	590	695	695	—	—	32	58
Webster DC371	360	505	416	—	—	N/A	75
Ivanhoe DC1760	600	720	760	—	—	N/A	New in 2006
Golf DC8518	450	630	647	—	—	N/A	New in 2006
Circuits with DER circuit support (peak amps value would be the overload without DER).				26 Days over 90	3 Days over 90	2 Days over 90	20 Days over 90

EPRI and DTE Energy have recently published a report entitled Best Practices Guidebook for Integration of Distributed Energy Resources into Utility System Planning (product ID 1011250). This report provides, for the first time, a practical guidebook of industry best practices for integrating DER into the utility planning and operating process. The information presented in the report is based on DTE Energy's real-world experience in DER planning and implementation for distribution solutions and customer services.

The report includes key lessons learned, capital budget planning, financial calculations for engineers, planning and protection, system design, siting and approval, construction and in-commissioning, and methods of control and operation. It also presents five case studies of DTE Energy's DER-based distribution solutions.