H 1192

GENERAL ASSEMBLY OF NORTH CAROLINA
  SESSION 2025
 H  1
  HOUSE BILL 1192
 Short Title:   Energy and Housing Affordability Act.  (Public)
 Sponsors:      Representatives Schietzelt, Moss, and Paré (Primary Sponsors).
  For a complete list of sponsors, refer to the North Carolina General Assembly web site.
 Referred to:   Rules, Calendar, and Operations of the House
  May 5, 2026
1A BILL TO BE ENTITLED
2 AN ACT TO MODIFY THE STATUTES GOVERNING COST RECOVERY FOR
3    FUEL-RELATED CHARGES, TO PROMOTE THE DEVELOPMENT OF ON-SITE
4    GENERATION CAPACITY BY LARGE ELECTRICITY CUSTOMERS, AND TO
5    APPROPRIATE FUNDS TO THE WORKFORCE HOUSING LOAN PROGRAM.
6 The General Assembly of North Carolina enacts:
7
8 PART I. FUEL COST SHARING
9SECTION 1. G.S. 62-133.2 reads as rewritten:
10 "§ 62-133.2. Fuel and fuel-related charge adjustments for electric utilities.
11     (a)     The Commission shall permit anAn electric public utility that generates electric power
12 by fossil fuel or nuclear fuel shall request Commission approval to charge an increment or
13 decrement as a rider to its rates for changes in the cost of fuel and fuel-related costs used in
14 providing its North Carolina customers with electricity from the cost of fuel and fuel-related costs
15 established in the electric public utility's previous general rate case on the basis of cost per
16 kilowatt hour.hour, provided that the Commission establishes a fuel cost and purchased power
17 cost sharing mechanism as provided in subsection (d3) of this section.
18     …
19     (c)     For purposes ofAt least 30 days prior to the annual hearing, each electric public utility
20 shall submit to the Commission verified annualized information and data in such form and detail
21 as the Commission may require, for an historic 12-month test period, relating to:
22(1)     Cost of fuel and fuel-related costs used in each generating facility owned in
23whole or in part by the utility.
24(2)     Fuel procurement practices and fuel inventories for each facility.facility,
25including unredacted fuel supply agreements.
26(3)     Burned cost of fuel used in each generating facility.
27(4)     Plant capacity factor for each generating facility.
28(5)     Plant availability factor for each generating plant.
29(6)     Generation mix by types of fuel used.
30(7)     Sources and fuel cost component of purchased power used.
31(8)     Recipients of and revenues received for power sales and times of power sales.
32(9)     Test period kilowatt-hour sales for the utility's total system and on the total
33system separated for North Carolina jurisdictional sales.
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 General Assembly Of North Carolina  Session 2025
1(10)      Procurement practices and inventories for: fuel burned and for ammonia, lime,
2limestone, urea, dibasic acid, sorbents, and catalysts consumed in reducing or
3treating emissions.
4(11) The cost incurred at each generating facility of fuel burned and of ammonia,
5lime, limestone, urea, dibasic acid, sorbents, and catalysts consumed in
6reducing or treating emissions.
7(12) Any net gains or losses resulting from any sales by the electric public utility
8of fuel or other fuel-related costs components.
9(13) Any net gains or losses resulting from any sales by the electric public utility
10of by-products produced in the generation process to the extent the costs of
11the inputs leading to that by-product are costs of fuel or fuel-related costs.
12      (d)     The Commission shall provide for notice of a public hearing with reasonable and
13 adequate time for investigation and for all intervenors to prepare for hearing. At the hearing the
14 Commission shall receive evidence from the utility, the Public Staff, and any intervenor desiring
15 to submit evidence, and from the public generally. In reaching its decision, the Commission shall
16 consider all evidence required under subsection (c) of this section as well as any and all other
17 competent evidence that may assist the Commission in reaching its decision including changes
18 in the cost of fuel consumed and fuel-related costs that occur within a reasonable time, as
19 determined by the Commission, after the test period is closed. The Subject to the cost sharing
20 mechanism provided in subsection (d3) of this section, the Commission shall incorporate in its
21 cost of fuel and fuel-related costs determination under this subsection the experienced
22 over-recovery or under-recovery of reasonable costs of fuel and fuel-related costs prudently
23 incurred by the electric public utility, based upon the prudent standards set pursuant to subsection
24 (d1) of this section, in fixing an increment or decrement rider. Upon request of the electric public
25 utility, the Commission shall also incorporate in this determination the experienced
26 over-recovery or under-recovery of costs of fuel and fuel-related costs through the date that is 30
27 calendar days prior to the date of the hearing, provided that the reasonableness and prudence of
28 these costs shall be subject to review in the utility's next annual hearing pursuant to this section.
29 The Commission shall use deferral accounting, and consecutive test historical 12-month periods,
30 in complying with this subsection, and the over-recovery or under-recovery portion of the
31 increment or decrement shall be reflected in rates for 12 months, notwithstanding any changes in
32 the base fuel cost in a general rate case. Any experienced over-recovery or under-recovery of
33 reasonable fuel and fuel-related costs prudently incurred shall accrue interest at the commercial
34 paper rate as identified by the Federal Reserve for A2/P2 nonfinancial issuers, or reasonable
35 successor thereto, on a weighted average basis over the applicable time period. The burden of
36 proof as to the correctness and reasonableness of the charge and as to whether the cost of fuel
37 and fuel-related costs were reasonably and prudently incurred shall be on the utility. The
38 Commission shall allow only that portion, if any, of a requested cost of fuel and fuel-related costs
39 adjustment that is based on adjusted and reasonable cost of fuel and fuel-related costs prudently
40 incurred under efficient management and economic operations. In evaluating whether cost of fuel
41 and fuel-related costs were reasonable and prudently incurred, the Commission shall apply the
42 rule adopted pursuant to subsection (d1) of this section. To the extent that the Commission
43 determines that an increment or decrement to the rates of the utility due to changes in the cost of
44 fuel and fuel-related costs over or under base fuel costs established in the preceding general rate
45 case is just and reasonable, the Commission shall order that the increment or decrement become
46 effective for all sales of electricity and remain in effect until changed in a subsequent general rate
47 case or annual proceeding under this section.
48      …
49      (d3) The Commission shall establish, by order or rule, a fuel cost and purchased power
50 cost sharing mechanism applicable to each electric public utility subject to this section. The
51 mechanism shall operate as follows:
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1(1)     Baseline. – The fuel cost and purchased power cost baseline for each annual
2hearing shall be the total fuel and purchased power costs, on a per-kilowatt
3hour basis, established in the electric public utility's most recent
4Commission-approved fuel forecast and fuel factors.
5(2)     Variance Calculation. – At each annual hearing under subsection (b) of this
6section, the Commission shall compare the electric public utility's actual fuel
7and purchased power costs for the historic 12-month test period to the
8baseline. The difference between actual costs and the baseline, whether an
9over-expenditure or a savings, shall constitute the variance.
10(3)     Sharing Allocation. – Of the variance determined pursuant to subdivision (2)
11of this subsection, eighty percent (80%) shall be recovered from or credited to
12customers through the increment or decrement rider, and twenty percent
13(20%) of the variance shall be recovered from or credited to the electric public
14utility's shareholders. Where actual costs exceed the baseline, the utility's
15shareholders shall absorb twenty percent (20%) of the variance and may not
16recover that portion from customers. Where actual costs are below the
17baseline, the utility's shareholders shall retain twenty percent (20%) of the
18variance as a shareholder benefit, and eighty percent (80%) shall be credited
19to customers through a reduction in the rider.
20(4)     Prudence Review. – The sharing allocation in subdivision (3) of this
21subsection applies only to the portion of any variance that the Commission
22finds was reasonably and prudently incurred. Any costs found to be
23unreasonably or imprudently incurred shall be disallowed in full and may not
24be recovered from customers. The twenty percent (20%) shareholder share
25under subdivision (3) of this subsection is not a cap on disallowance. The
26Commission retains full authority to disallow imprudently incurred costs
27beyond that share.
28(5)     Annual True-Up. – The twenty percent (20%) shareholder share of any
29over-expenditure variance shall be reflected as a reduction to the increment or
30decrement rider in the annual hearing in which it is determined. The
31Commission shall establish procedures for the accounting and reporting of
32shareholder shares and customer credits under this subsection. The fuel cost
33and purchased power cost sharing mechanism shall not be calculated on actual
34over- and under-recovered amounts reported to the Commission pursuant to
35subsection (d2) of this section.
36    …."
37
38 PART II. INDUSTRIAL ENERGY INDEPENDENCE
39SECTION 2. The General Assembly finds that:
40(1)     North Carolina's electric public utilities project demand growth driven by
41large commercial and industrial load additions at a rate that requires new tools
42to manage grid costs, maintain reliability, and protect existing ratepayers.
43(2)     Large industrial and commercial customers who develop on-site electric
44generation capacity reduce the volume of grid infrastructure that must be built
45and paid for by all ratepayers.
46SECTION 3.(a) Article 7 of Chapter 62 of the General Statutes is amended by adding
47 a new section to read:
48 "§ 62-159.5. Bring Your Own Generation (BYOG) Program.
49     (a)    Definitions. – For purposes of this section, the following definitions apply:
50(1)     Bring Your Own Generation or BYOG. – An arrangement under which an
51eligible large customer develops, owns, or contracts for on-site generation
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1capacity and connects that capacity to the electric grid for the purpose of
2serving some or all of the customer's own load, and providing available
3capacity as a grid service resource.
4(2)     BYOG interconnection agreement. – A standardized agreement governing the
5technical and commercial terms under which an eligible large customer's
6on-site generation capacity connects to the electric public utility's distribution
7or transmission system.
8(3)     Eligible large customer. – An electric utility customer with a peak demand of
9one megawatt (MW) or greater, or at some other level of peak demand as
10defined by rule or order of the Commission.
11(4)     Grid service resource. – Any on-site generation capacity or controllable load
12made available by an eligible large customer under a grid services agreement
13to the electric public utility for dispatch, curtailment, or grid-balancing
14purposes.
15(5)     Grid services agreement. – An agreement between an eligible large customer
16and an electric public utility establishing the terms under which the customer's
17grid service resources may be dispatched by the utility.
18(6)     On-site generation capacity. – An electric generating facility, including solar
19photovoltaic systems, batter energy storage systems, fuel cells, combined heat
20and power systems, or any combination thereof, located on or adjacent to an
21eligible large customer's premises and used for the primary purpose of serving
22that customer's electricity needs.
23      (b)     Application. – Each electric public utility shall file with the Commission an
24 application requesting approval of a Bring Your Own Generation Program applicable to eligible
25 large customers. Each electric public utility's application shall provide standardized terms and
26 conditions for (i) an interconnection agreement with participating eligible large customers
27 connecting on-site generation capacity and (ii) a grid services agreement for participating eligible
28 large customers to offer grid service resources to the utility. The BYOG Program application
29 shall also include rates and interconnection fees applicable to eligible large customers, in addition
30 to a description of the cost allocation method used to establish rates under the program. Eligible
31 large customers who elect to participate in the voluntary BYOG Program may also elect to make
32 the customer's on-site generation capacity or controllable load available to the electric public
33 utility as a grid service resource under the terms of a grid services agreement.
34      (c)     Rate Treatment for Participating Customers. – Each electric public utility shall file
35 for Commission approval rates for electric services applicable to eligible large customers
36 participating in the BYOG Program. The rates approved by the Commission shall:
37(1)     Reflect the reasonable costs attributable to serving eligible large load
38customers, including the costs of interconnecting on-site generation capacity
39and the costs of administering the Program.
40(2)     Reflect the benefits that on-site generation capacity and grid service resources
41provide to the electric power system, including avoided transmission and
42distribution infrastructure costs, avoided capacity costs, and the value of
43dispatchable load flexibility during grid stress events.
44(3)     Not result in a net cost increase for residential and small commercial
45customers.
46      (d)     Interconnection Processing. – An electric public utility shall process applications
47 from eligible large customers to voluntary participate in the BYOG Program in accordance with
48 the following schedule:
49(1)     No later than 10 days following receipt of a BYOG application, the electric
50public utility shall review the application for completeness and notify the
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1applicant of receipt and whether any additional information is necessary for
2the application to be considered complete.
3(2)     No later than 60 days following receipt of a complete BYOG application, the
4electric public utility shall conduct a technical feasiibliity review and provide
5the customer with a written feasibility determination.
6(3)     No later than 90 days following receipt of a complete BYOG application, the
7electric public utility shall enter into a BYOG interconnection agreement with
8the eligible large customer, except for good cause as demonstrated to the
9Commission.
10(4)     No later than 180 days after entering a BYOG interconnection agreement, the
11electric public utility shall complete the physical interconnection of the
12eligible large customer's approved-on-site generation capacity, except for
13good cause as demonstrated to the Commission.
14     (e)    State Agency Coordination. – The Department of Commerce, in consultation with the
15 State Energy Office and the Department of Environmental Quality, shall develop the following:
16(1)     A single point-of-contact process through which eligible large customers
17seeking to develop on-site generation capacity may coordinate with relevant
18State agencies regarding applicable permits and approvals.
19(2)     A model permit checklist identifying all State-level permits, registrations, and
20approvals that may be required for on-site generation capacity of different
21technologies at different scales.
22     (f)    Local Permitting. – Notwithstanding any other provision of law, any local
23 government development regulation that imposes a permit requirement applicable to the
24 construction of new on-site generation capacity shall be subject to the following:
25(1)     The permit application shall be available in an electronic format.
26(2)     As applicable to on-site generation capacity with a nameplate capacity equal
27or less than five megawatts (MW), the local government shall issue a final
28decision approving or denying the development permit within 30 business
29days of receiving a complete application.
30(3)     As applicable to on-site generation capacity with a nameplate capacity greater
31than five megawatts (MW), the local government shall issue a final decision
32approving or denying the development permit within 60 business days of
33receiving a complete application.
34(4)     The local government shall only apply such land use requirements for on-site
35generation capacity that is reasonably related to public safety, building code
36compliance, or compatibility with local land use plans.
37     (g)    Electric Public Utility Report. – An electric public utility shall file with the
38 Commission no later than January 1 each year a report on the BYOG Program during the prior
39 year. The report shall include each of the following:
40(1)     The number of BYOG Program applications received, approved, denied, and
41pending.
42(2)     The total nameplate capacity of all on-site generation capacity interconnected
43under the BYOG Program, disaggregated by technology type.
44(3)     The number of grid services agreements entered between the electric public
45utility and eligible large customers, the amount of aggregate capacity included
46within those agreements, and the amount of energy dispatched under these
47agreements.
48(4)     The total compensation paid to eligible large customers for grid service
49resources provided to the electric public utility.
50(5)     An assessment of the impact of the BYOG Program on system peak demand,
51avoided infrastructure costs, and ratepayer costs.
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1     (h)      Commission Report; Program Review. – By no later than March 1 each year the
2 Commission shall submit to the General Assembly a summary of the reports filed by electric
3 public utilities as provided in subsection (g) of this section, along with any recommendations for
4 modifying the BYOG Program."
5SECTION 3.(b) No later than 180 days after the effective date of this section, an
6 electric public utility shall submit the application as required by G.S. 62-159.5(b), as enacted by
7 subsection (a) of this section.
8SECTION 3.(c) No later than 180 days after the effective date of this section, the
9 Department of Commerce shall develop the single point-of-contact process and the model permit
10 checklist required under G.S. 62-159.5(e), as enacted by subsection (a) of this section.
11SECTION 3.(d) This section is effective when it becomes law.
12
13 PART III. APPROPRIATION AND EFFECTIVE DATE
14SECTION 4.(a) There is appropriated from the General Fund to the North Carolina
15 Housing Finance Agency the sum of thirty five million dollars ($35,000,000) in nonrecurring
16 funds for the 2026-2027 fiscal year to be allocated to the Workforce Housing Loan Program.
17SECTION 4.(b) This section becomes effective July 1, 2026.
18SECTION 5. Except as otherwise provided, this act is effective when it becomes
19 law.
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