As used in this chapter, unless the context otherwise requires:

(1) “Aggregator” means any person or entity who contracts with an electric distribution company, electric supplier or PJM Interconnection (or its successor) to provide energy services, which facilitate battery storage systems for grid-integrated electric vehicles and related technologies.

(2) “Ancillary services” means services that are necessary for the transmission and distribution of electricity from supply sources to loads and for maintaining reliable operation of the transmission and distribution system.

(3) “Broker” means a person or entity that acts as an agent or intermediary in the sale or purchase of, but that does not take title to, electricity for sale to retail electric customers.

(4) “Commission” means the Delaware Public Service Commission.

(5) “Community-owned energy generating facility” means a renewable energy generating facility, located in the service area of a utility under the regulation of the Public Service Commission, that has multiple owners or customers who share the output of the generator, which may be located either as a stand-alone facility or behind the meter of a participating owner or customer. The facility shall be interconnected to the distribution system and operated in parallel with an electric distribution company’s transmission and distribution facilities.

(6) “DEC” means the Delaware Electric Cooperative and its successors.

(7) “Demand-side management” means cost effective energy efficiency programs that are designed to reduce customers’ electricity consumption, especially during peak periods.

(8) “Direct access” means the right of electric suppliers and their customers to use an electric distribution company’s transmission and distribution system on a nondiscriminatory basis at rates, terms and conditions of service comparable to the electric distribution company’s own use of the system to transmit or distribute electricity from any electric supplier to any customer.

(9) “Distribution facilities” means electric facilities located in Delaware that are owned by a public utility that operate at voltages of 34,500 volts or below and that are used to deliver electricity to customers, up through and including the point of physical connection with electric facilities owned by the customer.

(10) “Distribution services” means those services, including metering, relating to the delivery of electricity to a customer through distribution facilities.

(11) “DP&L” means Delmarva Power & Light Company and its successors.

(12) “Electric distribution company” means a public utility owning and/or operating transmission and/or distribution facilities in this State.

(13) “Electricity demand response” has the same definition set forth in § 1501 of this title.

(14) “Electric supplier” means a person or entity certified by the Commission that sells electricity to retail electric customers utilizing the transmission and/or distribution facilities of a nonaffiliated electric utility, including:

a. Municipal corporations which choose to provide electricity outside their municipal limits (except to the extent provided prior to February 1, 1999);

b. Electric cooperatives which, having exempted themselves from the Commission’s jurisdiction pursuant to §§ 202(g) and 223 of this title, choose to provide electricity outside their assigned service territories; and

c. Any broker, marketer or other entity (including public utilities and their affiliates).

(15) “Electric supply service” means the provision of electricity and related services to customers.

(16) “Fuel cell” means an electric generating facility that:

a. Includes integrated power plant systems containing a stack, tubular array, or other functionally similar configuration used to electrochemically convert fuel to electric energy, and

b. May include an inverter and fuel processing system or other plant equipment to support the plant’s operation or its energy conversion, including heat recovery equipment.

(17) “Grid-integrated electric vehicle” means a battery-run motor vehicle that has the ability for 2-way power flow between the vehicle and the electric grid and the communications hardware and software that allow for the external control of battery charging and discharging by an electric distribution company, electric supplier, PJM Interconnection, or an aggregator.

(18) “Integrated resource planning” means the planning process of an electric distribution company that systematically evaluates all available supply options, including but not limited to: generation, transmission and demand-side management programs, during the planning period to ensure that the electric distribution company acquires sufficient and reliable resources over time that meet its customers’ needs at a minimal cost.

(19) “Marketer” means a person or entity that purchases and takes title to electricity for sale to customers in this State.

(20) “Retail competition” means the right of a customer to purchase electricity from an electric supplier.

(21) “Retail electric customer” or “customer” means a purchaser of electricity for ultimate consumption and not for resale in this State, including the owner/operator of any building or facility, but not the occupants thereof, that purchases and supplies electricity to the occupants of such building or facility.

(22) “Returning customer service” means the electric supply service offered to customers with a peak monthly load of 1000 kW or more, which have left standard offer service as of April 30, 2007, and later decide to receive electric supply service from their electric distribution company. For purposes of determining customers eligible for returning customer service, peak monthly load shall be measured by the electric distribution company’s separate customer account, not by facility or service location or by customer, in aggregate or otherwise.

(23) “Standard offer service” means the provision of electric supply service after the transition period by a standard offer service supplier to customers who do not otherwise receive electric supply service from an electric supplier.

(24) “Standard offer service supplier” means the electric distribution company serving within its certificated service territory.

(25) “Transition period” means the period of time beginning with the implementation of retail competition and ending on the dates specified in § 1004 of this title.

(26) “Transmission facilities” means electric facilities located in Delaware, developed by public utilities or companies that are not public utilities, including those in offshore waters, and integrated with onshore electric facilities, and owned by a public utility that operate at voltages above 34,500 volts and that are used to transmit and deliver electricity to customers, including any customers taking electric service under interruptible rate schedules as of December 31, 1998, up through and including the point of physical connection with electric facilities owned by the customer. The term includes “offshore wind interconnection facilities” and “renewable energy interconnection facilities” as defined in § 203F of this title.

(27) “Transmission services” means the delivery of electricity from supply sources through transmission facilities.

72 Del. Laws, c. 10, §  3;  73 Del. Laws, c. 157, §  4;  75 Del. Laws, c. 242, §  2;  77 Del. Laws, c. 188, §  3;  77 Del. Laws, c. 212, §  1;  77 Del. Laws, c. 453, §  1;  81 Del. Laws, c. 205, § 3;  83 Del. Laws, c. 178, § 3;  84 Del. Laws, c. 401, § 12; 

The General Assembly declares that the following interdependent standards shall govern the Commission’s review and approval of each public utility’s restructuring plan, oversight of the transition process and regulation of the restructured electric utility industry pursuant to this chapter.

(1) The reliability of electric service to all customers in this State shall be maintained.

(2) On and after the implementation dates set forth in § 1003 of this title, customers shall have the right to choose among electric suppliers.

(3) Nothing contained herein shall have the effect of abrogating or amending contracts between public utilities and any of their customers in place on February 1, 1999.

(4) On or after May 1, 2006, it is the policy of the State that electric distribution companies subject to the oversight of the Commission and as part of their obligation to be standard offer service suppliers shall engage in integrated resource planning for the purpose of evaluating and diversifying their electric supply options, efficiently and at the lowest cost to their customers.

72 Del. Laws, c. 10, §  3;  75 Del. Laws, c. 242, §  3; 

General rule. — Except as otherwise expressly provided for in this chapter, on and after May 1, 2006, the generation, supply and sale of electricity, including all related facilities and assets, used to serve standard offer service and returning customer service, shall be treated as a public utility service or function. Customers of electric distribution companies in this State shall continue to have the opportunity, but not the obligation, to purchase electricity from their choice of electric suppliers as expressly provided for in this chapter.

72 Del. Laws, c. 10, §  3;  75 Del. Laws, c. 242, §  4; 

(a) The transition period for DP&L shall begin on October 1, 1999, and shall end on September 30, 2002, for nonresidential customers and shall begin on October 1, 1999, and end on September 30, 2003, for residential customers.

(b) The transition period for DEC shall begin on April 1, 2000, and shall end on March 31, 2005, for all customers.

72 Del. Laws, c. 10, §  3; 

(a) Restructuring plan for DP&L. — (1) Filing and contents of plan. — On or before April 15, 1999, DP&L shall file with the Commission a detailed plan for implementing retail competition in DP&L’s commission-designated service territory. Such plan shall include:

a. Separate prices or rates for electric supply, transmission, distribution and other services (which may later be combined for billing purposes);

b. Procedures for providing direct access for all electric suppliers;

c. Revised tariffs and rate schedules;

d. An optional residential time of use rate with three daily time of use periods to be available for any residential customer who elects such a rate structure; and

e. Standards for reliability sufficient to measure variations in service reliability after the implementation of retail competition.

(2) Commission review of plan. — The Commission shall review DP&L’s restructuring plan and, after an evidentiary proceeding, issue an order by August 31, 1999, adopting the plan as filed or modifying the plan as appropriate.

(b) Restructuring plan for DEC. — (1) Filing and contents of plan. — On or before September 15, 1999, DEC shall file with the Commission a detailed plan for implementing retail competition in DEC’s Commission-designated service territory. Such plan shall include:

a. Separate prices or rates for electric supply, transmission, distribution and other services (which may later be combined for billing purposes);

b. Procedures for providing direct access for all electric suppliers;

c. Revised tariffs and rate schedules;

d. DEC’s proposed competitive transition charge, including the proposed method, recovery plan and determination of DEC’s stranded and transition costs, as such terms are defined in [former] § 1007 of this title; and

e. Standards for reliability sufficient to measure variations in service reliability after implementation of retail competition.

(2) Commission review of plan. — The Commission shall review DEC’s restructuring plan and, after an evidentiary proceeding, issue an order by February 28, 2000, adopting the plan as filed or modifying the plan as appropriate.

72 Del. Laws, c. 10, §  3; 

(a) Rates for customers within DP&L’s service territory.

(1) DP&L is required to offer both standard offer service and returning customer service, except that returning customer service shall only apply to customers meeting the definitional load characteristics for such service. Customers on returning customer service may return to standard offer service after receiving returning customer service for a minimum of 12 consecutive months.

(2) After May 1, 2006, rates for customers taking standard offer service shall be adjusted in accordance with subchapter III of Chapter 1 of this title. The Electric Utility Retail Customer Supply Act of 2006, 75 Del. Laws, c. 242, shall not have any effect on contractual arrangements between the standard offer service supplier and successful bidders entered into as a result of the recently conducted bidding process for standard offer service in Public Service Commission Docket No. 04-391. Any rates derived from that process shall be determined by the Commission pursuant to that docket, except as permitted in paragraph (a)(3) of this section.

(3) With respect to rate increases for standard offer service to be effective on May 1, 2006, residential and small commercial customers of DP&L, depending on rate classification, shall have the ability to opt out of the following rate deferral plan:

The limitations on rate increases specified in this section shall be accomplished by applying appropriate credits/charges per kilowatt hour to customer bills. The same credits/charges per kilowatt hour shall be applied regardless of whether the customer is receiving standard offer service or purchasing electricity from an electric supplier.

a. A customer not opting out of the deferral plan will be placed on a nonbypassable tariff, under which the customer will be responsible for all of that customer’s incurred deferral amounts including carrying costs of the plan.

b. Customers will have from April 1, 2006, to April 28, 2006, to affirmatively opt out of this plan.

c. Upon completion of the deferral plan, customers on the plan will be returned to their original rate classification, subject to any past due amounts owed while on the plan. The “True-up/Balance” to be instituted on January 1, 2008, shall provide for equal monthly installment amounts designed to recover all deferral amounts by each customer by not later than June 1, 2009, as well as the full standard offer service charges and all other tariff charges then in effect.

d. Except as otherwise provided for in the Electric Utility Retail Customer Supply Act of 2006, 75 Del. Laws, c. 242, customers enrolled in the deferral plan will be able to purchase electricity from an electric supplier and will continue to receive the same credits/charges specified in this section.

e. If determined to be in the public interest, the Commission shall have the authority after January 1, 2007, to adjust the deferral plan to take advantage of any downward movement of standard offer service rates.

(4) Rates for customers on returning customer service shall be based on the regional spot market plus DP&L’s reasonable costs of procuring such supply for this group of customers.

(5) In addition to the standard offer service price or the alternative electric supplier’s supply price, each customer shall pay the separate applicable rates for transmission, ancillary, distribution, nuclear decommissioning and other services. Such rates shall not include any generation or electric supply costs.

(6) Customers who obtain transmission and/or ancillary services directly from the PJM independent system operator or from their electric supplier shall receive a credit against DP&L’s retail delivery rates equal to the then-applicable Federal Energy Regulatory Commission equivalent retail transmission and/or ancillary services rates paid by that customer or its electric supplier.

(b) Rates for customers within the DEC service territory.

(1) DEC is required to offer both standard offer service and returning customer service, except that returning customer service shall only apply to customers meeting the definitional load characteristics for such service.

(2) After May 1, 2006, rates for customers taking standard offer service shall be adjusted in accordance with subchapter III of Chapter 1 of this title.

(3) Rates for customers on returning customer service shall be based on the regional spot market plus DEC’s reasonable costs of procuring such supply for this group of customers.

(4) In addition to the standard offer service price or the alternative electric supplier’s supply price, each customer shall pay the separate applicable rates for transmission, ancillary, distribution, nuclear decommissioning and other services. Such rates shall not include any generation or electric supply costs.

(5) Customers who obtain transmission and/or ancillary services directly from the PJM independent system operator or from their electric supplier shall receive a credit against DEC’s retail delivery rates equal to the then-applicable Federal Energy Regulatory Commission equivalent retail transmission and/or ancillary services rates paid by that customer or its electric supplier.

72 Del. Laws, c. 10, §  3;  70 Del. Laws, c. 186, §  1;  75 Del. Laws, c. 242, §  5; 

(a) All electric distribution companies subject to the jurisdiction of the Commission shall be the standard offer service supplier and returning customer service supplier in their distribution service territories. Customers on returning customer service may return to standard offer service after receiving returning customer service for a minimum of 12 consecutive months.

(b) Subject to the approval of the Commission, the standard offer service provider to meet its electric supply requirements shall have the ability to:

(1) Enter into short- and long-term contracts for the procurement of power necessary to serve its customers;

(2) Own and operate facilities for the generation of electric power;

(3) Build generation and transmission facilities (subject to any other requirements in any other section of the Delaware Code regarding siting, etc.);

(4) Make investments in demand-side resources; and

(5) Take any other Commission-approved action to diversify their retail load.

In order to take such action, DP&L as a standard offer service supplier must file an application with the Commission or have had such action approved as part of its integrated resource plan pursuant to subsection (c) of this section. If DP&L as a standard offer service supplier files an application under this subsection, then the Commission shall hold an evidentiary hearing on DP&L’s request and shall approve the request if the Commission finds that such action is in the public interest. If the Commission approves such a request, the Commission shall review all reasonable incurred costs of the contracts, facilities or programs in accordance with subchapter III of Chapter 1 of this title. Costs from these projects which have been approved by the Commission shall be included in standard offer service rates.

(c) (1) DP&L is required to conduct integrated resource planning. On December 1, 2006, and on the anniversary date of the first filing date of every other year thereafter (i.e., 2008, 2010 et seq.), DP&L shall file with the Commission, the Controller General, the Director of the Office of Management and Budget and the Energy Office an integrated resource plan (“IRP”). After the filing of DP&L’s December 2016 IRP, an IRP filing shall be made when DP&L elects to change its source of supply pursuant to paragraphs (b)(2)-(5) of this section or as the Commission may otherwise direct. In its IRP, DP&L shall systematically evaluate all available supply options during a 10-year planning period in order to acquire sufficient, efficient and reliable resources over time to meet its customers’ needs at a minimal cost. The IRP shall set forth DP&L’s supply and demand forecast for the next 10-year period, and shall set forth the resource mix with which DP&L proposes to meet its supply obligations for that 10-year period (i.e., demand-side management programs, long-term purchased power contracts, short-term purchased power contracts, self generation, procurement through wholesale market by RFP, spot market purchases, etc.).

a. As part of its IRP process, DP&L shall not rely exclusively on any particular resource or purchase procurement process. In its IRP, DP&L shall explore in detail all reasonable short- and long-term procurement or demand-side management strategies, even if a particular strategy is ultimately not recommended by the company. At least 30 percent of the resource mix of DP&L shall be purchases made through the regional wholesale market via a bid procurement or auction process held by DP&L. Such process shall be overseen by the Commission subject to the procurement process approved in PSC Docket #04-391 as may be modified by future Commission action.

b. In developing the IRP, DP&L may consider the economic and environmental value of:

1. Resources that utilize new or innovative baseload technologies (such as coal gasification);

2. Resources that provide short- or long-term environmental benefits to the citizens of this State (such as renewable resources like wind and solar power);

3. Facilities that have existing fuel and transmission infrastructure;

4. Facilities that utilize existing brownfield or industrial sites;

5. Resources that promote fuel diversity;

6. Resources or facilities that support or improve reliability; or

7. Resources that encourage price stability.

The IRP must investigate all potential opportunities for a more diverse supply at the lowest reasonable cost.

c. The Commission shall have the authority to promulgate any rules and regulations it deems necessary to accomplish the development of IRPs by DP&L. Commencing in 2009, DP&L shall submit a report to the Commission, the Governor and the General Assembly detailing its progress in implementing its IRPs.

d. The costs that DP&L incurs in developing and submitting its IRPs shall be included and recovered in DP&L’s distribution rates.

(2) The DEC shall annually prepare a 10-year plan detailing its energy supply requirements and planned procurement strategies to meet forecasted demand. Said plan shall be submitted to the Public Service Commission, Controller General’s Office and Office of Management and Budget. Said plan shall be filed by January 31, 2007, and January 31 of each subsequent year thereafter.

(d) As part of the initial IRP process, to immediately attempt to stabilize the long-term outlook for standard offer supply in the DP&L service territory, DP&L shall file on or before August 1, 2006, a proposal to obtain long-term contracts. The application shall contain a proposed form of request for proposals (“RFP”) for the construction of new generation resources within Delaware for the purpose of serving its customers taking standard offer service. Such proposed RFP shall include a proposed form of output contract which shall include capacity and energy and may include ancillary electric products and environmental attributes between the electric distribution company and developers of new generation facilities, which contract shall have a term of no less than 10 years and no more than 25 years. Such RFP shall also set forth proposed selection criteria based on the cost-effectiveness of the project in producing energy price stability, reductions in environmental impact, benefits of adopting new and emerging technology, siting feasibility and terms and conditions concerning the sale of energy output from such facilities.

(1) The Commission and Energy Office may approve or modify the elements of the RFP prior to its issuance. The Commission and Energy Office shall ensure that each RFP elicits and recognizes the value of:

a. Proposals that utilize new or innovative baseload technologies;

b. Proposals that provide long-term environmental benefits to the state;

c. Proposals that have existing fuel and transmission infrastructure;

d. Proposals that promote fuel diversity;

e. Proposals that support or improve reliability; and

f. Proposals that utilize existing brownfield or industrial sites.

Such RFP shall be issued no later than November 1, 2006. Proposals will be due no later than December 22, 2006.

(2) DP&L shall publish such request for proposals in 1 or more newspapers or periodicals with general circulation, as selected by the Commission, and shall post such request for proposals on its web site. The Commission, the Director of the Office of Management and Budget, the Controller General and the Energy Office shall retain the services of an independent third-party entity with expertise in the area of energy procurement at the expense of DP&L to oversee the development of the request for proposals and to assist them in their review of proposals pursuant to paragraph (d)(3) of this section. Public service companies shall be eligible to participate in such RFP process through unregulated affiliated companies that meet the Commission’s criteria to ensure that such affiliates are sufficiently financially and functionally separate from the regulated utility operations to prevent subsidization of the generation project by the regulated operations and to eliminate any other advantages from the affiliation with regulated operations.

(3) The Commission, the Director of the Office of Management and Budget, the Controller General and the Energy Office shall, on or before February 28, 2007, evaluate such proposals and may determine to approve 1 or more of such proposals that result in the greatest long-term system benefits, including those identified in paragraph (1) of this subsection, in the most cost-effective manner. Once 1 or more of the contracts have been finalized and approved by the Commission, the Director of the Office of Management and Budget, the Controller General and the Energy Office, then DP&L shall enter into such contract or contracts.

(e) Electric distribution companies are required to provide returning customer service to qualifying returning customers.

72 Del. Laws, c. 10, §  3;  75 Del. Laws, c. 242, §  6;  81 Del. Laws, c. 315, § 1; 

(a) Each electric distribution company shall maintain its facilities and provide products and services which are safe, efficient, sufficient, adequate, and reliable. Each electric distribution company shall implement procedures to require all electric suppliers to deliver energy to the electric distribution company at locations and in amounts which are adequate to meet each supplier’s obligations to its customers.

(b) (1) The Commission is hereby granted the authority to require DP&L subject to its jurisdiction to develop and implement demand-side management programs designed to reduce overall electricity consumption by its customers and/or to reduce usage by customers during peak periods, such as time of use rates, advanced metering infrastructure, central air-conditioning and hot water heating cycling off and on programs, interruptible rates, etc. However, in no such instance shall electric distribution companies subject to the Commission’s jurisdiction be authorized to implement peak time billing. Upon development of such demand-side management program or programs, DP&L shall file such program or programs with the Commission for the Commission’s review and approval.

a. The costs that DP&L incurs in developing and implementing their demand-side management programs, as well as the costs incurred by DP&L in administering all demand-side management programs approved for implementation by the Commission, shall be included and recovered in DP&L’s distribution rates.

b. By June 5, 2006, the Commission shall open a docket to evaluate the desirability, feasibility and cost effectiveness of requiring advanced metering technology, including time of use metering to be utilized throughout or selectively in the service territories of DP&L. The Commission may require that such a technology be deployed in a cost effective manner after such evaluation has been made and hearings have been held. As part of the evaluation, the Commission shall review all customer pricing implications of any particular metering technology investigated. The Commission shall not authorize such technology to be deployed in a manner that permits 30-day peak demand billing except as approved by the General Assembly.

c. The Commission shall have the authority to promulgate any rules and regulations it deems necessary to accomplish the development and implementation of demand-side management programs by DP&L.

(2) DEC shall, at a minimum, maintain its current efforts in providing demand-side management programs. DEC shall report on its demand-side management efforts to the Public Service Commission, Controller General and Director of the Office of Management and Budget by January 31, 2007, and January 31 of each subsequent year thereafter.

72 Del. Laws, c. 10, §  3;  74 Del. Laws, c. 73, §  3;  75 Del. Laws, c. 242, §  7; 

Notwithstanding any other provision of this chapter, unless an electric utility, including a municipally-owned electric utility or a municipal electric company, has implemented a restructuring plan that provides for retail competition in its Delaware service territory, such electric utility may not use the transmission or distribution facilities of a nonaffiliated electric utility to make sales to customers in such nonaffiliated electric utility’s Delaware service territory; nor shall such electric utility own or receive, directly or indirectly, any economic interest in any entity which uses the transmission or distribution facilities of a nonaffiliated electric utility to make sales to customers in such nonaffiliated electric utility’s Delaware service territory.

72 Del. Laws, c. 10, §  3; 

(a) The standard offer service supplier shall provide standard offer service which is safe, efficient, adequate and reliable. The Commission may take appropriate actions to ensure that the standard offer service supplier provides such safe, adequate, efficient and reliable standard offer service.

(b) The Commission shall promulgate rules and regulations governing the amount of notice that a customer who desires to return to the standard offer service supplier must provide, the minimum amount of time that a customer must take service from a standard offer service supplier, and the amount of charges that may be assessed against a customer who leaves the standard offer service supplier and later returns to the standard offer service supplier, including the appropriate retail market price, which may be higher than the standard offer service price.

(c) After hearing and a determination that it is in the public interest, the Commission is authorized to restrict retail competition and/or add a nonbypassable charge to protect the customers of the electric distribution company receiving standard offer service. The General Assembly recognizes that electric distribution companies are now required to provide standard offer service to many customers who may not have the opportunity to choose their own electric supplier. Consequently, it is necessary to protect these customers from substantial migration away from standard offer service, whereupon they may be forced to share too great a share of the cost of the fixed assets that are necessary to serve them as required by the Electric Utility Retail Customer Supply Act of 2006, 75 Del. Laws, c. 242.

72 Del. Laws, c. 10, §  3;  74 Del. Laws, c. 73, §§  4, 5;  75 Del. Laws, c. 242, §  8; 

(a) The following provisions shall govern metering and billing for customers in DP&L’s service territory:

(1) Each customer shall have the right to choose to receive separate bills from DP&L and from its electric supplier, or to receive a combined bill from either DP&L or its electric supplier, for electric supply, transmission, distribution, ancillary and other services, consistent with the regulations of the Commission.

(2) If the customer does not elect a billing option, DP&L shall be responsible for billing customers for all electric supply, transmission, distribution, ancillary and other services, regardless of the identity of the provider of electric supply service.

(3) Customer bills shall contain sufficient detail to enable the customer to determine the basis for all charges.

(4) During the transition period, DP&L shall continue to own all meters and perform all meter-reading functions. After the transition period, or earlier if requested by DP&L, the Commission may permit others to provide some or all of such metering functions on a competitive basis.

(b) The following provisions shall govern metering and billing for customers in DEC’s service territory:

(1) DEC shall continue to bill each Customer for:

a. That customer’s electric supply service, regardless of the electric supplier, and

b. Transmission, distribution, ancillary and other services.

(2) All customers in DEC’s service territory shall continue to be members of DEC and the revenues for DEC’s services shall continue to be treated as member revenue to DEC.

(3) DEC shall continue to own and operate meters and perform meter reading functions in its Commission-designated service territory.

72 Del. Laws, c. 10, §  3; 

(a) Certification requirements. —

Prior to doing business in Delaware, every electric supplier seeking to provide electric supply service to customers shall obtain a certificate from the Commission. The Commission shall promulgate rules and regulations governing the information that electric suppliers shall be required to provide and requirements to be satisfied in order to obtain such certificate. The failure by any electric supplier to comply with any of the requirements promulgated by the Commission shall result in penalties, including monetary assessments, suspension or revocation of the electric supplier’s certificate, or other sanctions.

(b) Rules and regulations. —

The Commission may promulgate rules and regulations with respect to electric suppliers and electric supply service to protect customers after the implementation of retail competition, including those related to standardized customer information billing, service terms and conditions, dispute procedures, changing suppliers and standards for suppliers who offer environmentally-advantageous “Green Power” options, such as electricity generated from renewable resources, biomass, hydroelectric and other such generating sources. All electric suppliers shall consent to the jurisdiction of the Delaware courts for acts or omissions arising from their activities in the State. Electric suppliers shall not solicit customers by means of telemarketing where such telemarketing is prohibited by applicable laws and regulations.

(c) Fees and assessments. —

(1) Electric suppliers required to obtain a certificate to provide retail electric supply service shall pay an application fee of $750.

(2) For purposes of §§ 114 (Charges and fees; costs and expenses of proceedings), 115 (Public policy; regulatory assessment; definition of revenue; returns; collection of assessment), and 116 (Delaware Public Service Commission Revolving Fund; deposit of moneys collected) of this title, an electric supplier shall be deemed to be a “public utility” as defined in § 102(2) of this title.

72 Del. Laws, c. 10, §  3;  75 Del. Laws, c. 242, §  9;  82 Del. Laws, c. 11, § 9; 

(a) On or after October 1, 1999, upon complaint or upon its own motion, for good cause shown, the Commission may conduct an investigation of the retail electric supply service market and whether the function of that market is being adversely affected by market power arising from the ownership or control of facilities and equipment used to provide electric supply service.

(b) If, as a result of an investigation conducted under this section, the Commission has reason to believe that market power in the relevant market under the Commission’s jurisdiction is preventing retail electric customers in the State from obtaining the benefits of retail competition, the Commission may take remedial actions to mitigate the impact of such activities, including ordering divestiture. However, in the case of divestiture, the Commission may only order divestiture of generating assets of a public utility and only in an extreme situation and as a last resort measure.

72 Del. Laws, c. 10, §  3; 

(a) In separating the rates or prices for DP&L’s services under § 1005(a) of this title, the Commission shall reassign to the separate transmission and distribution rates of each rate class from the total base rates $0.000356 per kilowatt-hour to be deposited each month by DP&L into an environmental incentive fund effective on October 1, 1999. Such fund shall be known as the “Green Energy Fund” and all moneys deposited into the Green Energy Fund shall be transferred in their entirety on the July 1 of each year to the State Energy Office to fund environmental incentive programs for conservation and energy efficiency in the State. The State Energy Office shall submit to the General Assembly by May 30 of each year a written accounting of moneys received from the fund during the previous year and how those moneys were used or disbursed during that year.

(b) The Commission shall further reassign to the separate transmission and distribution rates of each rate class from the total base rates $0.000095 per kilowatt-hour to be deposited each month by DP&L into a Low-Income Pogram Fund effective on October 1, 1999. Such fund shall be administered by the Department of Health and Social Services, Division of State Service Centers and shall be used to fund low-income fuel assistance and weatherization programs within DP&L’s service territory.

(c) The Commission shall establish a working group by June 1, 1999, comprised of representatives of the Commission, electric utilities, electric suppliers, the Division of the Public Advocate, environmental community, consumers, a member of the House of Representatives appointed by the Speaker of the House, a member of the House of Representatives appointed by the Minority Leader of the House, a member of the Senate appointed by the President Pro Tempore of the Senate, a member of the Senate appointed by the Minority Leader of the Senate and other interested parties to design and implement a consumer education program, including “Green Power” options, to prepare the citizens of Delaware for retail competition. The Commission shall direct the payment of up to a total of $250,000 from DP&L and DEC (apportioned on the 1998 kw Delaware retail sales of each entity) for the purpose of providing customer education materials to citizens of Delaware in connection with retail competition.

(d) The Commission, municipal electric companies, and electric cooperatives during any period of exemption under § 223 of this title shall each promulgate rules and regulations that provide for net energy metering for customers who own and operate, lease and operate, or contract with a third party that owns and operates an electric generation facility that:

(1) Has a capacity that:

a. For residential customers of DP&L, DEC, and municipal electric companies, has a capacity of not more than 25 kW;

b. For farm customers as described in § 902(3) of Title 3 who are customers of DP&L, DEC, or municipal electric companies that receive distribution service under a residential tariff or service offering, does not exceed more than 150 kW. On a case by case basis the Delaware Department of Natural Resources and Environmental Control shall review a farm’s application for a system above 150 kW by comparing the output of the system to the energy requirements of the farm and may grant a waiver to increase the size of the system above the 150 kW limit. The Delaware Department of Natural Resources and Environmental Control shall promulgate rules and regulations for such waivers in consultation with any commission-regulated electric utilities. Such waivers for DEC or municipal electric company customers shall be approved by DEC or the municipal electric company serving said customer;

c. For nonresidential customers, is not more than 2 megawatts per DP&L meter, and 500 kW per DEC or municipal electric company meter. DEC and municipal electric companies are encouraged to provide for net-metering up to a capacity of not more than 2 megawatts for nonresidential customers.

(2) Uses as its primary source of fuel solar, wind, hydro, a fuel cell, or gas from the anaerobic digestion of organic material;

(3) Is located on the customer’s premises;

(4) Is interconnected and operated in parallel with an electric distribution company’s transmission and distribution facilities; and

(5) Is designed to produce no more than 110% of the host customer’s expected aggregate electrical consumption, calculated on the average of the 2 previous 12-month periods of actual electrical usage at the time of installation of energy generating equipment. For new building construction, electrical consumption will be estimated at 110% of the consumption of units of similar size and characteristics at the time of installation of energy generating equipment. Subject to the effective dates in subsection (e) of this section, commission-regulated electric utilities, municipal electric companies, and electric cooperatives during any period of exemption under § 223 of this title, shall not, at the end of the annualized billing period, reimburse, credit, or otherwise remunerate the net energy metering customer for any Excess kWh Credits. However, any utility may enter into a power supply agreement with a farm customer described in § 902(3) of Title 3; provided that nothing in this subsection or subsection (e) of this section shall prohibit electric distribution companies from entering into contracts with farm customers that allow or provide for the procurement, crediting, or carryover of Excess kWh Credits at the end of an annualized billing period.

(e) The rules and regulations promulgated for net energy metering by the Commission, municipal electric companies, and electric cooperatives during any period of exemption under § 223 of this title must consider the reliability, safety, and capacity of the electric distribution system and:

(1) a. Provide for customers to be credited in kilowatt-hours (kWh) for any excess production of their generating facility that exceeds the customer’s on-site consumption of kWh in a billing period (an “Excess kWh Credit”). Excess kWh Credits shall be credited to subsequent monthly billing periods to offset a customer’s consumption in those billing periods. Excess kWh Credits at the end of the annualized billing period shall revert to the electric distribution company providing electric distribution to the customer; for commission-regulated utilities, this section shall take effect on May 31, 2023. A commission-regulated utility may continue to make payments for annual Excess kWh until May 31, 2023.

b. Effective January 1, 2024, for commission-regulated utilities for existing and future net energy metering customers, both residential and nonresidential, the monthly Excess kWh Credit shall be valued at the sum of the volumetric (kWh) components of the supply service charges and distribution service charges, not including the charges for societal benefits programs, according to each participating customer account’s rate schedule. Any Excess kWh Credits shall not reduce any fixed monthly customer charges imposed by the electric distribution company. The customer-generator retains ownership of all renewable energy credits (RECs) associated with electric energy produced unless the customer has relinquished such ownership by contractual agreement with a third party or by other means. This paragraph (e)(1) does not apply to customers participating in a community-owned energy generating facility, as the provisions regarding community-owned energy generating facilities are addressed elsewhere in the Delaware Code. “Societal benefits program” means a program required by law in which a benefit to the public at large accrues as a result of its implementation. Societal benefits programs include:

1. Green Energy Fund under subsection (a) of this section.

2. Low-Income Program Fund under subsection (b) of this section.

3. Charges incurred by the utility in complying with the state mandated renewable energy portfolio standard under § 358(f)(1) of this title.

4. The charge imposed under § 364 of this title for qualified fuel cells.

5. Energy efficiency programs under § 8059(h)(1)e. of Title 29.

(2) Excess kWh Credits for supply service are the responsibility of the entity providing supply to the customer rather than solely the responsibility of the electric distribution company.

(3) In the event that a net-metering customer abandons the property where the energy generating equipment is located, the equipment may remain connected to the electric distribution system, unless the equipment presents a risk to the safety and reliability of the electric distribution system.

(4) Ensure that electric suppliers provide net-metered customers electric service at nondiscriminatory rates that are identical, with respect to rate structure and monthly charges, to the rates that a customer who is not net-metering would be charged. electric suppliers shall not charge a net-metering customer any stand-by fees or similar charges, with the exception that the Delaware Energy Office shall promulgate rules that allow DEC and municipal electric companies to request to assess nonresidential net-metering customers a fee or charge if the electric utility’s direct costs of interconnection and administration of net-metering for these customer classes outweigh the distribution system, environmental, and public policy benefits of allocating the costs among the electric supplier’s entire customer base.

(5) Require that all generating systems and grid-integrated electric vehicles used by eligible customers meet all applicable safety and performance standards established by the National Electrical Code, and those of the Institute of Electrical and Electronic Engineers, UL, or the Society of Automotive Engineers, to ensure that net metering customers meet applicable safety and performance standards and comply with the electric supplier’s interconnection tariffs and operating guidelines. An electric supplier’s interconnection rules must be developed by using as a guide the Interstate Renewable Energy Council’s Model Interconnection Rules and best practices identified by the U.S. Department of Energy. Municipal electric companies shall establish interconnection rules no later than July 24, 2008. An electric supplier may not require eligible net-metering customers who meet all applicable safety and performance standards to install excessive controls, perform or pay for unnecessary tests, or purchase excessive liability insurance.

(6) Net energy metering shall be accomplished using a single meter capable of registering the flow of electricity in 2 directions. To maintain system safety and reliability, an additional meter or meters to monitor the flow of electricity in each direction may be installed with the consent of the net-metering customer, which consent may be waived by the customer. The additional metering shall be used only to provide the information necessary to accurately bill or credit the customer pursuant to paragraph (e)(1) of this section, or to collect system performance information. If an additional meter or meters are installed, the net energy metering calculation shall yield a result identical to that of a single meter. Nonresidential customers shall be responsible for paying the reasonable cost of any new, replacement, or modified meter or meters installed or caused to be installed for net-metering purposes. Residential customers shall not be responsible for paying more than $200 toward the reasonable cost of any new, replacement, or modified meter or meters installed or caused to be installed for net-metering purposes. Nonresidential customers and residential customers shall not own the meter or meters, which shall remain the property of the electric supplier.

(7) If the total generating capacity, measured in megawatts (MW) of alternating current (AC), of all customer-generation using net-metering systems served by an electric utility exceeds 8% of the capacity necessary to meet the electric utility’s average Delaware transmission peak demand for the preceding 3 years, the electric utility may elect not to provide net-metering services to any additional customer-generators.

(8) In instances where 1 customer has multiple meters under the same account or different accounts, regardless of the physical location and rate class, the customer may aggregate meters for the purpose of net energy metering regardless of which individual meter receives energy from the energy generating facility, provided that:

a. Electric suppliers, DEC, DP&L, and municipal electric companies shall only allow meter aggregation for customer accounts of which they provide electric supply service; and

b. The customer’s energy generating facility is designed to produce no more than 110% of the customer’s aggregate electrical consumption of the individual meters or accounts that the customer wishes to aggregate under this paragraph (e)(8) of this section, calculated on the average of the 2 previous 12-month periods of actual electrical usage at the time of installation of energy generating equipment. For new building construction, electrical consumption will be estimated at 110% of the consumption of units of similar size and characteristics at the time of installation of energy generating equipment; and

c. The customer’s energy generating facility shall not exceed a capacity as defined under paragraph (d)(1) of this section; and

d. At least 90 days before a customer commences construction of an energy generating facility or a customer desires to aggregate multiple meters, the customer shall file with the electric supplier, DP&L, DEC, or the appropriate municipal electric company the following information:

1. A list of individual meters the customer desires to aggregate, identified by name, address, and account number, and ranked according to the order in which the customer desires to apply credit;

2. A description of the energy generating facility, including the facility’s location, capacity, and fuel type or generating technology; and

3. A complete interconnection application to facilitate a transmission and distribution analysis, including an evaluation of potential reliability, safety and stability impacts and determination of whether infrastructure upgrades are necessary and appropriate allocation of applicable interconnection costs;

e. The customer may change its list of aggregated meters no more than once annually by providing 90 days’ written notice; and

f. Credit shall be applied first to the meter through which the energy generating facility supplies electricity, then through the remaining meters for the customer’s accounts according to the rank order as specified in accordance with paragraph (e)(8)d. of this section; and

g. Credit in kWh shall be valued according to each account’s rate schedule and the rules and regulations promulgated for net energy metering under paragraph (e)(1) of this section; and

h. An electric supplier, DP&L, DEC, or the appropriate municipal electric company may require that a customer’s aggregated meters be read on the same billing cycle; and

i. The rules and regulations promulgated for net energy metering under this section shall also apply to net energy metering aggregation.

(9) [Repealed.]

(f) Individual customers may aggregate their individual meters in conjunction with a community-owned energy generating facility provided that:

(1) The Commission promulgates rules and regulations that provide for customers participating in a community-owned energy generating facility to be credited for the customers’ subscribed percentage of generation valued at the sum of the volumetric (kWh) components of the distribution service charges and supply service charges for residential customers and the sum of the volumetric energy (kWh) components of the distribution service charges and supply service charges for nonresidential customers according to each participating customer account’s rate schedule. At the end of the annualized billing period, a customer may request a refund from the electric distribution company.

(2) A customer may not receive credit for more than 110% of the customer’s expected aggregate electrical consumption, calculated on the average of the 2 previous 12-month periods of actual electrical usage at the time of subscription with the community-owned energy generating facility. For new building construction, electrical consumption will be estimated at 110% of the consumption of units of similar size and characteristics. On an annual basis, an electric distribution company shall be permitted to audit individual customer’s subscribed amounts to ensure the associated usage does not exceed 110% of the customer’s annual usage. The community-owned energy generating facility shall provide updated individual customer’s subscribed percentage as required. In the event the community-owned energy generating facility does not provide the required update within 30 days after notification by the electric distribution company, the electric distribution company shall be permitted to set the customer’s percentage to zero. Customers of a community-owned energy generating facility shall only pay for credits received. A community-owned energy generating facility may update customer allocation percentages on a monthly basis.

(3) Any unsubscribed energy that constitutes 10% or less of the community-owned energy generating facility shall be compensated using the average annual locational marginal price of energy in the DPL Zone based on the prior calendar year. Any unsubscribed energy that is greater than 10% of the community-owned energy generating facility not allocated shall not be compensated by the electric distribution company.

(4) An electric distribution company shall use energy generated from a community-owned energy generating facility to offset purchases from wholesale electricity suppliers for standard offer service.

(5) Excess credits shall be credited to subsequent billing periods to offset the customers’ charges in those billing periods.

(6) The community-owned energy generating facility shall ensure that the net-metering credits from the community-owned energy generating facility are accurate. The amount of electricity generated each month available for allocation as subscribed or unsubscribed energy shall be determined by a revenue quality production meter installed and paid for by the owner of the community-owned energy generating facility. Further, the community-owned energy generating facility shall be responsible for any additional costs incurred by the electric distribution company, including billing-related costs associated with community-owned energy generating facility customers.

(7) The community-owned energy generating facility will retain ownership of all RECs and SRECs associated with the electric energy it produces unless it has relinquished such ownership by contractual agreement with a third party or its customers.

(8) The community-owned energy generating facility shall not have subscriptions larger than 200 kilowatts constituting more than 60% of its capacity. The community-owned energy generating facility host’s self-consumption is not included in this calculation.

(9) The electric distribution company shall only allow meter aggregation for customer accounts for which they provide electric distribution service.

(10) A community-owned energy generating facility shall not exceed a capacity of 4 megawatts and all costs associated with the interconnection are the responsibility of the community-owned energy generating facility.

(11) Community-owned energy generating facilities may include technologies defined under § 352(8)a.-h. of this title.

(12) A community-owned energy generating facility seeking to provide service to customers must apply for and obtain a certificate to operate from the Commission, and pay an application fee of $750. Community-owned energy generating facilities are not required to obtain a certificate of public convenience and necessity from the Commission. To obtain a certificate to operate, a community-owned energy generating facility must provide the following:

a. A completed interconnection study or signed interconnection agreement with the electric distribution company.

b. Proof of site control.

c. Evidence that it possesses the financial, operational, and managerial capacity to comply with all state and federal regulations.

(13) If a community-owned energy generating facility fails to comply with orders, rules, or regulations promulgated or issued by the Commission governing such a facility, or any other laws, rules, or regulations that apply to such a facility, the Commission may impose penalties, including monetary assessments, and may suspend or revoke the certificate to operate, and impose other sanctions permitted by law.

(14) Every 3 years, the community-owned energy generating facility must certify to the Public Service Commission in writing that it meets the low-income eligibility criteria provided in this chapter.

(15) Community-owned energy generating facilities are subject to the fees and charges in § 114 of this title. In addition, community-owned energy generating facilities are required to pay the annual gross revenue assessment in § 115 of this title, and the “gross operating revenue” shall equal the sum of the net-metering credits produced by the community-owned energy generating facility and the revenue derived from unsubscribed energy.

(16) Before a community-owned energy generating facility receives permission to operate pursuant to the interconnection process from the electric distribution company, a community-owned energy generating facility shall provide the electric distribution company with the following information:

a. A list of individual meters the community-owned energy generating facility desires to aggregate identified by name, address, and account number.

b. A description of the energy generating facility, including the facility’s host location, capacity, and fuel type or generating technology.

c. The subscribed percentage of generation attributed to each customer, which the electric distribution company shall true-up at the end of the annualized billing period.

d. Certification that the subscription level of each customer does not exceed 110% of that customer’s expected aggregate electrical consumption calculated on the average of the 2 previous 12-month periods of actual electrical usage at the time of subscription with the community-owned energy generating facility.

e. Before a community-owned energy generating facility receives permission to interconnect with an electric distribution company, the community-owned energy generating facility must certify to the electric distribution company and the Commission that participants in the community-owned energy generating facility include at least 15% low income customers whose gross annual income, by family size, is at or below 200% of the federal poverty guidelines, or 60% of the state median household income published by the United States Census Bureau, whichever is greater.

(17) A community-owned energy generating facility may change its list of aggregated meters no more than monthly by providing 30 days written notice to the electric distribution company.

(18) An electric distribution company may require that customers participating in a community-owned energy generating facility have their meters read on the same billing cycle.

(19) Neither customers nor owners of community-owned energy generating facilities shall be subject to regulation as either public utilities or an electric supplier, except as set forth in this section.

(20) Community-owned energy generating facilities shall be subject to regulation under the purview of the Commission, and the Commission will engage in rule-making in consultation with the Consumer Protection Unit of the Delaware Department of Justice. In addition to the promulgation of rules and regulations pursuant to this section relating to net energy metering, the Commission may promulgate rules and regulations with respect to community-owned energy generating facilities and this section to protect customers, including provisions related to standardized customer information billing, service terms and conditions, dispute procedures, and portability and transferability of contracts. Community-owned energy generating facilities shall not solicit customers by means of telemarketing where such telemarketing is prohibited by applicable laws and regulations.

(21) All community-owned energy generating facilities shall consent to the jurisdiction of the Delaware courts for acts or omissions arising from their activities in the State.

(22) Community-owned energy generating facilities must adhere to state and the Federal Energy Regulatory Commission rules.

(23) The Commission shall open a rule-making docket to promulgate the rules and regulations for community-owned energy generating facilities called for in this section by August 1, 2021, and the rules and regulations must be promulgated no later than March 11, 2022, unless the deadline is extended by law.

(24) A violation of any provision of this chapter related to community-owned energy generating facilities, and any rules or regulations promulgated pursuant to this section shall be deemed an unlawful practice under § 2513 of Title 6 and a violation of subchapter II of Chapter 25 of Title 6.

(g) The Commission shall periodically review the impact of net-metering rules in this section and recommend changes or adjustments necessary for the economic health of utilities.

(h) A retail electric customer having on its premises 1 or more grid-integrated electric vehicles shall be credited in kilowatt-hours (kWh) for energy discharged to the grid from the vehicle’s battery at the same kWh rate that customer pays to charge the battery from the grid, as defined in paragraph (e)(1) of this section. Excess kWh credits shall be handled in the same manner as net metering as described in paragraph (e)(1) of this section. To qualify under this subsection, the grid-integrated electric vehicle must meet the requirements in paragraphs (d)(1)a., (d)(1)b. and (d)(4) of this section. Connection and metering of grid integrated vehicles shall be subject to the rules and regulations found in paragraphs (e)(4), (5), and (6) of this section.

(i) The Commission may adopt tariffs for regulated electric utilities that are not inconsistent with subsection (h) of this section. Such tariffs may include rate and credit structures that vary from those set forth in subsection (h) of this section, as long as alternative rate and credit structures are not inconsistent with the development of grid-integrated electric vehicles.

(j) Nothing in this section is intended in any way to limit eligibility for net energy metering services based upon direct ownership, joint ownership, or third-party ownership or financing agreement related to an electric generation facility, where net energy metering would otherwise be available.

(k) Disputes shall be resolved by the Commission or appropriate governing body.

(l) Rules, regulations and programs for paragraphs (e)(8) and (9) [repealed] of this section shall be promulgated by the Commission or the appropriate local regulatory authority not later than July 1, 2011.

72 Del. Laws, c. 10, §  3;  74 Del. Laws, c. 38, §  2;  76 Del. Laws, c. 164, §§  1-4;  76 Del. Laws, c. 166, §  1;  76 Del. Laws, c. 200, §  2;  77 Del. Laws, c. 146, §§  1-3;  77 Del. Laws, c. 212, §§  2, 3;  77 Del. Laws, c. 453, §§  2-11;  82 Del. Laws, c. 24, § 1;  83 Del. Laws, c. 178, § 4;  83 Del. Laws, c. 355, §§ 1, 2;  84 Del. Laws, c. 7, § 1;  84 Del. Laws, c. 125, § 1;  84 Del. Laws, c. 401, § 6; 

(a) The Commission is authorized to enter such orders and adopt such regulations as may be needed to implement retail competition in accordance with this title. In order to allow the Commission to implement retail competition on the implementation dates set forth in [former] § 1003(b) of this title, the Commission may waive procedures required by §§ 1131-1136 and §§ 10111-10128 of Title 29 with respect to proceedings or rulemakings authorized by this chapter which must be completed prior to the implementation dates. In case of such waiver, the Commission shall provide notice in such a manner to allow all interested and affected persons an opportunity to comment upon and participate in the proposed action or rulemaking and shall conduct such proceedings or rulemakings in accordance with the principles of due process and fundamental fairness. All regulations shall be published in the Delaware Register of Regulations. Such orders and regulations shall become effective on a date designated by the Commission consistent with the requirements of this chapter. Judicial review of such final orders or regulations shall remain available under §§ 10141 and 10142 of Title 29.

(b) Matters relating to either DP&L’s or DEC’s restructuring plans may also be resolved by stipulation and settlement pursuant to § 512 of this title.

72 Del. Laws, c. 10, §  3; 

(a) The Commission’s regulatory authority over DP&L and DEC shall not be affected by a subsequent change in stock ownership of either utility. In approving any proposed merger, mortgage, transfer, issue, assumption or acquisition, the Commission shall, in addition to considering the factors set forth in § 215 of Title 26, take such steps or condition any transfer in such a manner as to insure that any successor will continue safe and reliable transmission and distribution services. Any proceeding reviewing a change of control or transfer shall conclude within 120 days from the date of filing, unless agreed to by the Commission and the applicant.

(b) Section 706 of Title 19 shall apply to any business combination, as defined therein, including without limitation, the sale, merger or acquisition of DP&L or of DP&L’s generating plants or utility assets in this State. This shall mean, without limiting the provisions of § 706 of Title 19, that:

(1) No such transaction shall result in the termination or impairment of the provisions of any labor contract negotiated by a duly certified or recognized labor organization, collective bargaining agent or other representative of the DP&L employees affected by such a transaction.

(2) Any such labor contract shall continue in effect with respect to all DP&L employees covered thereby until its termination date, unless otherwise agreed by the parties thereto or their legal successors;

(3) The sale, merger or acquisition of DP&L’s generation or other utility assets in this State shall include a provision that the purchasing, merging or new entity shall offer to hire its initial union-represented employee complement from among DP&L’s union-represented employees at the facilities being sold, merged or acquired at the time of the sale, merger or acquisition;

(4) The other party to the transaction shall bargain in good faith with the duly certified or recognized labor organization, collective bargaining agent or other representative that is the signatory to the labor contract referred to in paragraph (b)(2) of this section above in advance of the termination date of that labor contract for the purpose of extending or modifying such contract, as the parties thereto may agree.

(5) DP&L and the existing collective bargaining agents shall bargain in good faith to assure that any adverse effects on union-represented employees affected by such transaction are reasonably and satisfactorily mitigated. Such mitigation measures may include, but are not limited to, benefits such as training or re-training, severance pay and continued health care coverage.

72 Del. Laws, c. 10, §  3; 

Nothing in this chapter shall be construed to limit or constrain in any way the right of the Division of the Public Advocate to receive information pursuant to § 8716(d)(5) of Title 29.

72 Del. Laws, c. 10, §  3; 

Notwithstanding any other provision of this chapter, any electric cooperative, while exempt from the supervision and jurisdiction of the Commission pursuant to §§ 202(g) and 223 of this title, shall be exempt from all provisions of this chapter except as specified in § 224 of this title.

73 Del. Laws, c. 157, §  3; 

(a) If after hearing, upon notice the Commission determines that any standard offer service supplier, electric supplier or electric distribution company has, as a matter of past or present fact arising after enactment of this section:

(1) Failed to comply with or violated any term or condition in any certificate, permit, or other instrument or authorization granted by the Commission;

(2) Failed to comply with or violated any of the provisions of this title or any rule, or regulation, promulgated by the Commission;

(3) Failed to comply with or violated any order entered by the Commission; or

(4) Materially failed to provide facilities, products or services which are safe, efficient, adequate or reliable.

Then such standard offer service supplier, electric supplier or electric distribution company shall be liable to the State for a civil penalty; provided however, that no penalty shall be assessed under paragraph (a)(4) of this section unless the material failure is of the type that the standard offer service supplier, the electric supplier or electric distribution company knew or should have known as a result of standards, policies or procedures previously articulated by the Commission or through generally accepted industry standards or practices that its action(s) or inaction(s) would have been reasonably likely to cause the material failure. Such penalty shall not exceed $5,000 for each violation, with the overall penalty not to exceed an amount reasonable and appropriate for the violation. Each day of noncompliance shall be treated as a separate violation.

(b) The Commission shall determine the amount of any penalty to be assessed under subsection (a) of this section. In making such determination, the Commission shall consider:

(1) The nature, circumstances, extent and gravity of the violation;

(2) The standard offer service supplier, electric supplier or electric distribution company’s level of culpability, history of prior violations, and ability to pay;

(3) The good faith efforts of the standard offer service supplier, electric supplier or electric distribution company in attempting to resolve the violation after notification of noncompliance;

(4) In the case of an electric cooperative, the Commission shall not assess any monetary penalty that would adversely impact the financial stability of such an entity and any monetary penalty that is assessed against an electric cooperative shall not exceed $1,000 for each violation, which each day of noncompliance shall be treated as a separate violation.

(c) Any penalty imposed under this section may be recovered by an action instituted in the name of the State in the Superior Court. In such an action for recovery, the validity and amount of such penalty shall not be subject to review. In any such action, the State may recover the penalty, interest, costs and reasonable attorneys’ fees.

(d) If the Commission determines that a standard offer service supplier, electric supplier or electric distribution company will, as a result of present conditions or future threatened or contemplated action:

(1) Fail to comply with or violate any term or condition in any certificate, permit, or other instrument or authorization granted by the Commission;

(2) Fail to comply with or violate any of the provisions in this Title or any rule or regulation, promulgated by the Commission;

(3) Fail to comply with or violate any order entered by the Commission; or

(4) Materially fail to provide facilities, products, or services, which are safe, efficient, adequate or reliable;

Then the Commission may after hearing, upon notice, enter such orders to ensure compliance by the standard offer service supplier, electric supplier or electric distribution company. In exercising this authority, the Commission may enter immediate or prompt preliminary orders, to ensure compliance pending a final determination and order, in those instances where the public interest requires immediate or prompt action or relief. In its process for considering whether to issue a preliminary order, the Commission shall conduct an appropriate proceeding, upon appropriate notice, given the relief sought. If such a preliminary order is issued, the Commission shall thereafter, promptly schedule and begin the process to consider a final determination and order, which proceeding for final determination and order shall be conducted with notice and hearings consistent with the requirement of § 101 of Title 29.

(e) If after hearing, upon notice, the Commission determines that any standard offer service supplier, electric supplier or electric distribution company has, as a matter of past or present fact occurring after June 30, 2003:

(1) Failed to comply with or violated any term or condition in any certificate, permit or other instrument or authorization granted by the Commission;

(2) Failed to comply with or violated any of the provisions of this title or any rule or regulation, promulgated by the Commission;

(3) Failed to comply with or violated any order entered by the Commission; or

(4) Materially failed to provide facilities, products or services, which are safe, efficient, adequate or reliable.

Then the Commission may enter an order modifying, suspending or revoking any certificate, permit or authorization previously granted by the Commission to such standard offer service supplier, electric supplier or electric distribution company. Such remedy shall only be applied when the gravity of the violation warrants such relief. Revocation of a certificate, permit or authorization shall only be permitted, when there is a finding of a gross violation or violations or a pervasive pattern of conduct in violation of this section. Additionally, such remedy shall only be applied with respect to paragraph (e)(4) of this section if the material failure is of the type that the standard offer service supplier, the electric supplier, or electric distribution company knew or should have known as a result of standards, policies or procedures previously articulated by the Commission or through generally accepted industry standards or practices that its action(s) or inaction(s) would have been reasonably likely to cause the material failure.

(f) In making the determination under subsection (e) of this section to modify, suspend or revoke any prior certificate, permit or authorization, the Commission shall consider:

(1) The factors listed in subsection (b) of this section;

(2) The ability of penalties and other sanctions to ensure compliance without the need to suspend or revoke; and

(3) The impact on the public interest by such modification, suspension or revocation.

(g) The penalty and other sanctions authorized by this section shall be in addition to any other penalties or sanctions authorized by law. The Commission may exercise the power granted in subsection (e) of this section in addition to the imposition of any penalty or other sanction imposed under this section or any other provision of the law. A final order with respect to any findings made or penalties or other sanctions imposed under this section shall be subject to the appeal procedures of § 510 of this title.

(h) The Commission may recover the costs of any proceeding instituted under this section in accordance with the provisions of §§ 114 and 1012(c)(2) of this title.

(i) This section shall apply to electric distribution companies, electric suppliers, DP&L and DEC, and any successors or assigns, except that this section shall not apply to electric distribution companies that are exempt from the jurisdiction of the Commission pursuant to § 202 of this title.

74 Del. Laws, c. 73, §  6; 

(a) Integrated resource plans (IRPs) filed with the Commission pursuant to § 1007 of this title shall include a detailed description of the energy efficiency activities of the utility. Electricity demand response programs shall be directly implemented by the utility. Demand-side management and other energy efficiency activities shall be implemented by the SEU (as defined in § 8059 of Title 29), in collaboration with the utility. The contributions of utility-implemented and SEU-implemented programs shall be considered in meeting the Energy Efficiency Resource Standards required under Chapter 15 of this title.

(b) In preparing the IRP, the utility shall first consider electricity demand response and demand-side management strategies for meeting base load and load growth needs and shall preferentially obtain electricity demand response resources through utility operated programs or demand-side management resources from the SEU or Weatherization Assistance Program, and cost-effective renewable energy resources before considering traditional fossil fuel-based electric supply services to meet their retail electricity supplier (as defined in § 352 of this title) obligations.

77 Del. Laws, c. 188, §  4;