A BILL TO BE ENTITLED
AN ACT to modify the statutes governing cost recovery for fuel‑related charges, to promote the development of on‑site generation capacity by large electricity customers, and to appropriate funds to the workforce housing loan program.
The General Assembly of North Carolina enacts:

part i. fuel cost sharing
SECTION 1.  G.S. 62‑133.2 reads as rewritten:  
"§ 62‑133.2.  Fuel and fuel‑related charge adjustments for electric utilities.
(a)	An electric public utility that generates electric power by fossil fuel or nuclear fuel shall request Commission approval to charge an increment or decrement as a rider to its rates for changes in the cost of fuel and fuel‑related costs used in providing its North Carolina customers with electricity from the cost of fuel and fuel‑related costs established in the electric public utility's previous general rate case on the basis of cost per kilowatt hour, provided that the Commission establishes a fuel cost and purchased power cost sharing mechanism as provided in subsection (d3) of this section. 
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(c)	At least 30 days prior to the annual hearing, each electric public utility shall submit to the Commission verified annualized information and data in such form and detail as the Commission may require, for an historic 12‑month test period, relating to:
(1)	Cost of fuel and fuel‑related costs used in each generating facility owned in whole or in part by the utility.
(2)	Fuel procurement practices and fuel inventories for each facility, including unredacted fuel supply agreements. 
(3)	Burned cost of fuel used in each generating facility.
(4)	Plant capacity factor for each generating facility.
(5)	Plant availability factor for each generating plant.
(6)	Generation mix by types of fuel used.
(7)	Sources and fuel cost component of purchased power used.
(8)	Recipients of and revenues received for power sales and times of power sales.
(9)	Test period kilowatt‑hour sales for the utility's total system and on the total system separated for North Carolina jurisdictional sales.
(10)	Procurement practices and inventories for: fuel burned and for ammonia, lime, limestone, urea, dibasic acid, sorbents, and catalysts consumed in reducing or treating emissions.
(11)	The cost incurred at each generating facility of fuel burned and of ammonia, lime, limestone, urea, dibasic acid, sorbents, and catalysts consumed in reducing or treating emissions.
(12)	Any net gains or losses resulting from any sales by the electric public utility of fuel or other fuel‑related costs components.
(13)	Any net gains or losses resulting from any sales by the electric public utility of by‑products produced in the generation process to the extent the costs of the inputs leading to that by‑product are costs of fuel or fuel‑related costs.
(d)	The Commission shall provide for notice of a public hearing with reasonable and adequate time for investigation and for all intervenors to prepare for hearing. At the hearing the Commission shall receive evidence from the utility, the Public Staff, and any intervenor desiring to submit evidence, and from the public generally. In reaching its decision, the Commission shall consider all evidence required under subsection (c) of this section as well as any and all other competent evidence that may assist the Commission in reaching its decision including changes in the cost of fuel consumed and fuel‑related costs that occur within a reasonable time, as determined by the Commission, after the test period is closed. Subject to the cost sharing mechanism provided in subsection (d3) of this section, the Commission shall incorporate in its cost of fuel and fuel‑related costs determination under this subsection the experienced over‑recovery or under‑recovery of reasonable costs of fuel and fuel‑related costs prudently incurred by the electric public utility, based upon the prudent standards set pursuant to subsection (d1) of this section, in fixing an increment or decrement rider. Upon request of the electric public utility, the Commission shall also incorporate in this determination the experienced over‑recovery or under‑recovery of costs of fuel and fuel‑related costs through the date that is 30 calendar days prior to the date of the hearing, provided that the reasonableness and prudence of these costs shall be subject to review in the utility's next annual hearing pursuant to this section. The Commission shall use deferral accounting, and consecutive historical 12‑month periods, in complying with this subsection, and the over‑recovery or under‑recovery portion of the increment or decrement shall be reflected in rates for 12 months, notwithstanding any changes in the base fuel cost in a general rate case. Any experienced over‑recovery or under‑recovery of reasonable fuel and fuel‑related costs prudently incurred shall accrue interest at the commercial paper rate as identified by the Federal Reserve for A2/P2 nonfinancial issuers, or reasonable successor thereto, on a weighted average basis over the applicable time period. The burden of proof as to the correctness and reasonableness of the charge and as to whether the cost of fuel and fuel‑related costs were reasonably and prudently incurred shall be on the utility. The Commission shall allow only that portion, if any, of a requested cost of fuel and fuel‑related costs adjustment that is based on adjusted and reasonable cost of fuel and fuel‑related costs prudently incurred under efficient management and economic operations. In evaluating whether cost of fuel and fuel‑related costs were reasonable and prudently incurred, the Commission shall apply the rule adopted pursuant to subsection (d1) of this section. To the extent that the Commission determines that an increment or decrement to the rates of the utility due to changes in the cost of fuel and fuel‑related costs over or under base fuel costs established in the preceding general rate case is just and reasonable, the Commission shall order that the increment or decrement become effective for all sales of electricity and remain in effect until changed in a subsequent general rate case or annual proceeding under this section. 
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(d3)	The Commission shall establish, by order or rule, a fuel cost and purchased power cost sharing mechanism applicable to each electric public utility subject to this section. The mechanism shall operate as follows:
(1)	Baseline. – The fuel cost and purchased power cost baseline for each annual hearing shall be the total fuel and purchased power costs, on a per‑kilowatt hour basis, established in the electric public utility's most recent Commission‑approved fuel forecast and fuel factors. 
(2)	Variance Calculation. – At each annual hearing under subsection (b) of this section, the Commission shall compare the electric public utility's actual fuel and purchased power costs for the historic 12‑month test period to the baseline. The difference between actual costs and the baseline, whether an over‑expenditure or a savings, shall constitute the variance.
(3)	Sharing Allocation. – Of the variance determined pursuant to subdivision (2) of this subsection, eighty percent (80%) shall be recovered from or credited to customers through the increment or decrement rider, and twenty percent (20%) of the variance shall be recovered from or credited to the electric public utility's shareholders. Where actual costs exceed the baseline, the utility's shareholders shall absorb twenty percent (20%) of the variance and may not recover that portion from customers. Where actual costs are below the baseline, the utility's shareholders shall retain twenty percent (20%) of the variance as a shareholder benefit, and eighty percent (80%) shall be credited to customers through a reduction in the rider.
(4)	Prudence Review. – The sharing allocation in subdivision (3) of this subsection applies only to the portion of any variance that the Commission finds was reasonably and prudently incurred. Any costs found to be unreasonably or imprudently incurred shall be disallowed in full and may not be recovered from customers. The twenty percent (20%) shareholder share under subdivision (3) of this subsection is not a cap on disallowance. The Commission retains full authority to disallow imprudently incurred costs beyond that share. 
(5)	Annual True‑Up. – The twenty percent (20%) shareholder share of any over‑expenditure variance shall be reflected as a reduction to the increment or decrement rider in the annual hearing in which it is determined. The Commission shall establish procedures for the accounting and reporting of shareholder shares and customer credits under this subsection. The fuel cost and purchased power cost sharing mechanism shall not be calculated on actual over‑ and under‑recovered amounts reported to the Commission pursuant to subsection (d2) of this section.
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part ii. industrial energy independence
SECTION 2.  The General Assembly finds that:
(1)	North Carolina's electric public utilities project demand growth driven by large commercial and industrial load additions at a rate that requires new tools to manage grid costs, maintain reliability, and protect existing ratepayers. 
(2)	Large industrial and commercial customers who develop on‑site electric generation capacity reduce the volume of grid infrastructure that must be built and paid for by all ratepayers.
SECTION 3.(a)  Article 7 of Chapter 62 of the General Statutes is amended by adding a new section to read:
"§ 62‑159.5.  Bring Your Own Generation (BYOG) Program.
(a)	Definitions. – For purposes of this section, the following definitions apply:
(1)	Bring Your Own Generation or BYOG. – An arrangement under which an eligible large customer develops, owns, or contracts for on‑site generation capacity and connects that capacity to the electric grid for the purpose of serving some or all of the customer's own load, and providing available capacity as a grid service resource. 
(2)	BYOG interconnection agreement. – A standardized agreement governing the technical and commercial terms under which an eligible large customer's on‑site generation capacity connects to the electric public utility's distribution or transmission system. 
(3)	Eligible large customer. – An electric utility customer with a peak demand of one megawatt (MW) or greater, or at some other level of peak demand as defined by rule or order of the Commission. 
(4)	Grid service resource. – Any on‑site generation capacity or controllable load made available by an eligible large customer under a grid services agreement to the electric public utility for dispatch, curtailment, or grid‑balancing purposes. 
(5)	Grid services agreement. – An agreement between an eligible large customer and an electric public utility establishing the terms under which the customer's grid service resources may be dispatched by the utility. 
(6)	On‑site generation capacity. – An electric generating facility, including solar photovoltaic systems, batter energy storage systems, fuel cells, combined heat and power systems, or any combination thereof, located on or adjacent to an eligible large customer's premises and used for the primary purpose of serving that customer's electricity needs. 
(b)	Application. – Each electric public utility shall file with the Commission an application requesting approval of a Bring Your Own Generation Program applicable to eligible large customers. Each electric public utility's application shall provide standardized terms and conditions for (i) an interconnection agreement with participating eligible large customers connecting on‑site generation capacity and (ii) a grid services agreement for participating eligible large customers to offer grid service resources to the utility. The BYOG Program application shall also include rates and interconnection fees applicable to eligible large customers, in addition to a description of the cost allocation method used to establish rates under the program. Eligible large customers who elect to participate in the voluntary BYOG Program may also elect to make the customer's on‑site generation capacity or controllable load available to the electric public utility as a grid service resource under the terms of a grid services agreement.
(c)	Rate Treatment for Participating Customers. – Each electric public utility shall file for Commission approval rates for electric services applicable to eligible large customers participating in the  BYOG Program. The rates approved by the Commission shall:
(1)	Reflect the reasonable costs attributable to serving eligible large load customers, including the costs of interconnecting on‑site generation capacity and the costs of administering the Program.
(2)	Reflect the benefits that on‑site generation capacity and grid service resources provide to the electric power system, including avoided transmission and distribution infrastructure costs, avoided capacity costs, and the value of dispatchable load flexibility during grid stress events. 
(3)	Not result in a net cost increase for residential and small commercial customers. 
(d)	Interconnection Processing. – An electric public utility shall process applications from eligible large customers to voluntary participate in the BYOG Program in accordance with the following schedule: 
(1)	No later than 10 days following receipt of a BYOG application, the electric public utility shall review the application for completeness and notify the applicant of receipt and whether any additional information is necessary for the application to be considered complete. 
(2)	No later than 60 days following receipt of a complete BYOG application, the electric public utility shall conduct a technical feasiibliity review and provide the customer with a written feasibility determination.
(3)	No later than 90 days following receipt of a complete BYOG application, the electric public utility shall enter into a BYOG interconnection agreement with the eligible large customer, except for good cause as demonstrated to the Commission. 
(4)	No later than 180 days after entering a BYOG interconnection agreement, the electric public utility shall complete the physical interconnection of the eligible large customer's approved‑on‑site generation capacity, except for good cause as demonstrated to the Commission. 
(e)	State Agency Coordination. – The Department of Commerce, in consultation with the State Energy Office and the Department of Environmental Quality, shall develop the following:
(1)	A single point‑of‑contact process through which eligible large customers seeking to develop on‑site generation capacity may coordinate with relevant State agencies regarding applicable permits and approvals. 
(2)	A model permit checklist identifying all State‑level permits, registrations, and approvals that may be required for on‑site generation capacity of different technologies at different scales. 
(f)	Local Permitting. – Notwithstanding any other provision of law, any local government development regulation that imposes a permit requirement applicable to the construction of new on‑site generation capacity shall be subject to the following: 
(1)	The permit application shall be available in an electronic format.
(2)	As applicable to on‑site generation capacity with a nameplate capacity equal or less than five megawatts (MW), the local government shall issue a final decision approving or denying the development permit within 30 business days of receiving a complete application.
(3)	As applicable to on‑site generation capacity with a nameplate capacity greater than five megawatts (MW), the local government shall issue a final decision approving or denying the development permit within 60 business days of receiving a complete application.
(4)	The local government shall only apply such land use requirements for on‑site generation capacity that is reasonably related to public safety, building code compliance, or compatibility with local land use plans. 
(g)	Electric Public Utility Report. – An electric public utility shall file with the Commission no later than January 1 each year a report on the BYOG Program during the prior year. The report shall include each of the following:
(1)	The number of BYOG Program applications received, approved, denied, and pending.
(2)	The total nameplate capacity of all on‑site generation capacity interconnected under the BYOG Program, disaggregated by technology type.
(3)	The number of grid services agreements entered between the electric public utility and eligible large customers, the amount of aggregate capacity included within those agreements, and the amount of energy dispatched under these agreements. 
(4)	The total compensation paid to eligible large customers for grid service resources provided to the electric public utility.
(5)	An assessment of the impact of the BYOG Program on system peak demand, avoided infrastructure costs, and ratepayer costs. 
(h)	Commission Report; Program Review. – By no later than March 1 each year the Commission shall submit to the General Assembly a summary of the reports filed by electric public utilities as provided in subsection (g) of this section, along with any recommendations for modifying the BYOG Program." 
SECTION 3.(b)  No later than 180 days after the effective date of this section, an electric public utility shall submit the application as required by G.S. 62‑159.5(b), as enacted by subsection (a) of this section. 
SECTION 3.(c)  No later than 180 days after the effective date of this section, the Department of Commerce shall develop the single point‑of‑contact process and the model permit checklist required under G.S. 62‑159.5(e), as enacted by subsection (a) of this section.
SECTION 3.(d)  This section is effective when it becomes law.  

part iii. appropriation and effective date
SECTION 4.(a)  There is appropriated from the General Fund to the North Carolina Housing Finance Agency the sum of thirty five million dollars ($35,000,000) in nonrecurring funds for the 2026‑2027 fiscal year to be allocated to the Workforce Housing Loan Program.  
SECTION 4.(b)  This section becomes effective July 1, 2026.   
SECTION 5.  Except as otherwise provided, this act is effective when it becomes law.