BEFORE THE DEPARTMENT OF PUBLIC SERVICE REGULATION
OF THE STATE OF MONTANA
In the matter of the adoption of NEW RULE I pertaining to the creation of a legally enforceable obligation involving qualifying facilities, NEW RULE II pertaining to access to avoided cost modeling data for a qualifying facility, and the amendment of ARM 38.5.1901 pertaining to definitions
NOTICE OF ADOPTION AND AMENDMENT
TO: All Concerned Persons
1. On March 16, 2018, the Department of Public Service Regulation published MAR Notice No. 38-5-240 pertaining to the public hearing on the proposed adoption and amendment of the above-stated rules at page 550 of the 2018 Montana Administrative Register, Issue Number 5.
2. The department has amended ARM 38.5.1901 as proposed.
3. The department has adopted NEW RULES I and II as proposed, but with the following changes from the original proposal, new matter underlined, deleted matter interlined:
NEW RULE I (38.5.1909) CREATION OF A LEGALLY ENFORCEABLE OBLIGATION (1) A legally enforceable obligation
, as that term is used in 18 C.F.R. § 292.304, is created when a qualifying facility has:
(a) a qualifying facility has unilaterally signed and tendered a
n executed power purchase agreement to the purchasing utility with a price term consistent with the purchasing utility's avoided costs, calculated within 14 days of the date the power purchase agreement is tendered, with specified beginning and ending dates; equal to either:
(i) the existing standard offer rate in accordance with the applicable standard tariff provisions as approved by the commission for qualifying facilities eligible for standard offer rates; or
(ii) a price term consistent with the purchasing utility's avoided costs, calculated within 14 days of the date the power purchase agreement is tendered, with specified beginning and ending dates for delivery of energy, capacity, or both to be purchased by the utility and provisions committing the qualifying facility to reimburse the purchasing utility for interconnection costs, pursuant to ARM 38.5.1901(2)(d) and 38.5.1904(2) and (3) for qualifying facilities not eligible for standard offer rates;
undertaken at least the following work toward interconnection: a qualifying facility has obtained and provided to the purchasing utility written documents confirming control of the site for the length of the asserted legally enforceable obligation and permission to construct the qualifying facility that establish, at a minimum:
submitted an interconnection request to the interconnecting utility which has been signed by the qualifying facility in accordance with the generator interconnection procedures of the interconnecting utility's Open Access Transmission Tariff (OATT); proof of control of the site for the duration of the term of the power purchase agreement such as a lease or ownership interest in the real property;
paid any required deposit fee; proof of all required land use approvals and environmental permits necessary to construct and operate the facility; and
provided information sufficient to demonstrate that the qualifying facility has complied with the deadlines for an Interconnection Customer specified in the OATT; and permission to construct the qualifying facility as defined in ARM 38.5.1901(2)(f);
(iv) provided information sufficient to demonstrate that the qualifying facility has not waived deadlines applicable to the interconnecting utility, except that if such deadline or deadlines have been waived by the Interconnection Customer, or an alternative timeline has been agreed to by the Interconnection Customer, that a legally enforceable obligation will be created, for the purposes of this subsection, at the date or dates by which the Interconnection Customer agreed to in lieu of the deadlines specified in the OATT; and
control of the site and permission to construct the qualifying facility, including at a minimum: a qualifying facility has submitted a completed generator interconnection request that either requested study for network resource interconnection service (NRIS) for facilities larger than 20 megawatts or requested an optional study equivalent to NRIS for facilities 20 megawatts and smaller; and
(i) a legally recognized interest in the real property on which the qualifying facility will be sited, such as a lease or ownership interest in the real property;
(ii) all required government land use approvals; and
(iii) all necessary environmental permits to build the facility.
(d) a qualifying facility has undertaken one of the following additional steps towards interconnection:
(i) the qualifying facility has executed and returned a signed System Impact Study Agreement, with any required deposit, to the interconnecting utility and all technical data necessary to complete the System Impact Study Agreement;
(ii) for qualifying facilities requesting to interconnect under the Small Generator Interconnection Procedures (SGIP), 53 days have elapsed since the qualifying facility submitted the interconnection request and all of the following conditions exist: the interconnecting utility did not provide the qualifying facility a System Impact Study Agreement within 38 days of the qualifying facility's interconnection request; the qualifying facility has not waived the tariffed SGIP timeline; and the qualifying facility has satisfied applicable interconnection customer deadlines in the tariffed SGIP;
(iii) for qualifying facilities requesting to interconnect under the Large Generator Interconnection Procedures (LGIP), 90 days have elapsed since the qualifying facility submitted a completed interconnection request with the interconnecting utility, and all of the following conditions exist: the qualifying facility has not been provided a System Impact Study Agreement within 60 days of the initial interconnection request; the qualifying facility has not waived the timeline associated with the work of the interconnecting utility associated with the LGIP process; and the qualifying facility has timely met its deadlines established in the LGIP; or
(iv) for qualifying facilities that have waived the deadlines pertaining to the work of the interconnecting utility associated either with the SGIP or LGIP process, the mutually agreed upon time period after which the qualifying facility was scheduled to execute and return a signed System Impact Study Agreement, with any required deposit, to the interconnecting utility and all technical data necessary to complete the System Impact Study, has elapsed.
NEW RULE II (38.5.1910) QUALIFYING FACILITY ACCESS TO AVOIDED COST MODELING DATA (1) remains as proposed.
(2) The utility must provide an initial avoided cost calculation within
14 21 days of receipt of a qualifying facility's resource information, including generating technology, size, location, and production profile, at no cost to the qualifying facility. In providing an initial avoided cost calculation to the qualifying facility, the utility must use the methodologies most recently approved by the commission for that utility and must provide the qualifying facility with all assumptions and inputs used to make the avoided cost calculation.
(3) If a utility uses a proprietary modeling software to calculate its avoided cost, the utility must allow a qualifying facility, upon request, to conduct one avoided cost calculation using the utility modeling software with the qualifying facility's own assumptions and inputs at no cost to the qualifying facility. The utility must make dashboard access to its modeling software accessible to the qualifying facility within
14 21 days of the qualifying facility's request to conduct an alternative avoided cost calculation. The qualifying facility must have access to the modeling software for 14 21 days after the utility makes it available to the qualifying facility to conduct an alternative avoided cost calculation. A utility must accommodate reasonable requests by a qualifying facility to conduct additional avoided cost calculations using the utility's modeling software and may charge the qualifying facility a reasonable price for use of the modeling software beyond the single avoided cost calculation identified in this subsection.
(4) Pursuant to 69-3-206 and 69-3-209, MCA, a qualifying facility
or utility may petition the commission for fines against a qualifying facility or utility for failure to adhere to this rule.
4. The department has thoroughly considered the comments and testimony received. A summary of the comments received and the department's responses are as follows:
COMMENT NO. 1: One commenter stated that the department's proposed New Rule I is inconsistent with Federal Energy Regulatory Commission (FERC) regulations. According to the commenter, New Rule I requires Qualifying Facilities (QFs) to make substantial investments prior to the establishment of a Legally Enforceable Obligation (LEO), even though the viability of a project is unknown until the avoided cost rate is determined. Another commenter stated that the rule allows a utility to impose unreasonable restrictions that will effectively prevent many QFs from being able to form LEOs. Another commenter called the proposed rules impractical because they impose significant or costly burdens prior to the formation of a LEO. The department's rules would prevent many developers from being able to obtain financing because they would be required to spend significantly before knowing the purchase prices of their energy product.
RESPONSE: The department does not agree as the proposed New Rule I is consistent with FERC regulations. States are granted the primary role in overseeing the relationship between QFs and the utilities under the regulations promulgated by FERC. Indep. Energy Producers Ass’n v. California PUC, 36 F.3d 848, 856 (9th Cir. 1994). FERC leaves it to state commissions to determine the appropriate LEO test. FERC has consistently stated that "[it] is up to the States … to determine the specific parameters of individual QF power purchase agreements, including the date at which a legally enforceable obligation in incurred under State law." West Penn Power Co., 71 FERC ¶ 61,153, at 61,495 (1995). A LEO is a legally enforceable obligation and an unequivocal commitment by a QF to provide power to a utility. Therefore it requires a commitment from a QF to show the project is viable and can deliver power in the near future. New Rule I imposes reasonable restrictions on the creation of a LEO.
COMMENT NO. 2: One commenter stated that the problem QF developers face is that they cannot get the utility to negotiate with them and that a LEO cannot be established until after a full commission proceeding. They state that a LEO should correspond with the date from which the avoided cost will be calculated, not the date at which an avoided cost is already agreed to. One commenter supports the commission's acknowledgement that a QF should be able to establish a LEO without completing Power Purchase Agreement (PPA) negotiations, but it recommends that the commission also address situations where PPA negotiations have been completed and signed by the QF. One commenter testified that generally NorthWestern is unwilling to negotiate a price other than the avoided cost that NorthWestern generates. The commenter states that the language "with a price term consistent with the purchasing utility's avoided cost," should be removed from New Rule I. The commenter recommends that a QF should be found to have established a LEO on the date negotiations end with the utility or when the utility refuses to negotiate its initial offer. The commenter stated that New Rule I should include incentives for utilities to negotiate with QF developers and avoid commission contested hearings. The commenter said that there should be a sanction on the utility for failure to negotiate in good faith. Examples of behaviors that would incur sanctions are refusal to change an original offer, refusal to allow access to proprietary software models used to develop avoided costs, or purposefully offering numbers below avoided cost. Another commenter expressed concerns about unforeseen hurdles throughout the negotiation process and that QFs should be able to trigger a LEO at any time during negotiations with a utility.
RESPONSE: Under the LEO rule adopted by the department, the utility is required to negotiate in good faith with the QF and the department can and will entertain complaints from the QF if that does not occur. These objectives must be balanced against requiring the QF to do more than just initiate negotiations with a utility to trigger a LEO to avoid paper projects merely engaged in speculation. In support of a more lenient LEO standard, commenters quote to JD Wind 1, LLC, which states that "a QF, by committing itself to sell to an electric utility, also commits the electric utility to buy from the QF; these commitments result either in contracts or in non-contractual, but binding, legally enforceable obligations." 129 F.E.R.C. ¶ 61,148, at 61633 (Nov. 19, 2009). FERC's declaratory order (or declaratory letter) in JD Wind 1, LLC was later appealed to Fifth Circuit Court of Appeals. Exelon Wind 1, L.L.C. v. Nelson, 766 F.3d 380, n.5 (5th Cir. 2014) (“Exelon Wind”). In Exelon Wind, the Fifth Circuit found FER's conclusions in JD Wind 1, LLC were incorrect and upheld the Texas Public Utility Commission's 90-day LEO standard. Id., 395–97. If a QF were simply able to incur a LEO by simply committing itself to sell an electric utility, then Texas' 90-day rule would be invalid because it imposes more strenuous obligations than the QF merely executing a power purchase agreement to the utility. Id., 385–86 (observing that under the 90-day rule only QFs that are capable of generating "firm power" are eligible and for the remaining QFs that the ability to sell their power as available is sufficient). The court noted that the Texas Public Utility Commission "left open the possibility that other wind farms might be able to provide firm power, and thus form Legally Enforceable Obligations." Id., 396. Accordingly, this language in JD Wind 1, LLC cannot be viewed as requiring the department to allow any QF that has made a de minimis commitment to sell its energy—whether it's through simply tendering an executed power purchase agreement to the utility or otherwise—to incur a LEO.
Since the Fifth Circuit's decision in Exelon Wind on September 8, 2014, FERC has applied this language from JD Wind 1, LLC in a more limited fashion. In FLS Energy, Inc., FERC cited to this language to assert that "a legally enforceable obligation turns on the QF's commitment, and not the utility's action." 157 F.E.R.C. ¶ 61,211, at 61731 (Dec. 15, 2016). In E. Ky. Power Coop., Inc., FERC examined this JD Wind 1, LLC language but noted that formation of a LEO might be restricted under state law. 162 F.E.R.C. ¶ 61,267, at 62444, n.11 (Mar. 26, 2018); see also N. States Power Co., 151 F.E.R.C. P61,110, 61689 (May 14, 2015) (declining to examine the LEO issue because the case could be decided on other grounds). These FERC declaratory orders are consistent with Exelon Wind, which requires states to implement a LEO standard achievable through the QF’s own actions. Additionally, this rule allows QFs to incur a LEO through their own actions.
COMMENT NO. 3: Several commenters suggested that the rule should further clarify that, at the very latest, a QF should be found to have created a LEO on the date it files a petition or complaint with the commission. A petition with the commission requires a substantial investment of time and legal expenses, and occurs only after negotiations between the QF and utility have stalled. By that point, a QF is clearly committed to developing the project if it is willing to file a petition with the commission.
RESPONSE: The department appreciates the comments and acknowledges that filing a petition or complaint can require a substantial investment of time and expenses. However there are more relevant requirements to trigger the creation of a LEO. Relevant requirements that the department has proposed in its rule include a unilaterally executed PPA, executing a signed System Impact Study Agreement or demonstrating a commitment to obtain a System Impact Study Agreement, and having site control for the length of the asserted LEO.
COMMENT NO. 4: Several commenters state that a LEO should be established by tendering an executed power purchase agreement that includes the QF's reasonable calculation of avoided cost.
RESPONSE: The department's New Rule I satisfies the intent of this comment because a QF's reasonable calculation of avoided cost should result in a rate in the signed power purchase agreement tendered to the utility by the QF that is consistent with the utility's avoided cost. New Rule II enhances a QF's ability to develop a reasonable calculation of avoided cost.
COMMENT NO. 5: One commenter stated that New Rule I does not distinguish between QFs that are eligible for standard rates and those that are not. The commenter stated that there are generally three sizes of QFs. Those eligible for standard rates, those larger than the standard rate threshold up to 20 MW, and those larger than 20 MW. The commenter suggests that the rule should be amended so standard-rate QFs do not require an avoided cost calculation.
RESPONSE: The department agrees and has updated New Rule I to distinguish between QFs that are eligible for standard rates and those that are not.
COMMENT NO. 6: One commenter stated that for larger QFs, New Rule I does not have the specificity needed to clarify the areas being litigated and the rule should be modified to include a limit of 12 months between execution of a PPA and commercial operation date. In addition, contracts should be limited to 15 years and QFs should be required to utilize market price projections consistent with the method most recently used by the commission. Finally the rule should recognize that a QF may displace both market purchases and economically dispatched owned generation.
RESPONSE: The department appreciates the comments, but finds that further specificity, as suggested by the commenter, should be the subject of future rulemaking proceedings.
COMMENT NO. 7: Several commenters provided comments in support of the commission's rulemaking and stated that a LEO is an unequivocal commitment to sell on behalf of the QF. It is more than just a speculative proposal. The commission's requirements are designed to ensure the feasibility of the QF projects.
RESPONSE: The department appreciates these comments and agrees that a LEO is an unequivocal commitment to sell on behalf of the QF. The department's requirements are designed to ensure the feasibility of the QF projects and that the project is more than just a speculative paper project.
COMMENT NO. 8: The commenter states that New Rule I(1)(b) violates FERC Order 888, which requires interconnection employees to remain unaware of who the project owner is when an interconnection request is made (for example, if it is a QF or utility-owned). In Montana, once a QF contested case petition is filed with the Commission, the utility's interconnection and transmission employees are involved in testimony about the QF's interconnection requests and studies.
RESPONSE: The department does not agree as FERC subsequently adopted regulations requiring open access same time information systems (OASIS) and codes of conduct for transmission providers, such as NorthWestern Energy, in 18 C.F.R. Part 358. These requirements constitute the "additional safeguards" FERC identified as necessary to protect against market power abuses in Order 888. In addition, FERC subsequently issued Orders 2003 and 2006 to standardize the interconnection procedures for generators. Since the interconnection of any electric generator, including a QF, to a utility transmission system must cohere to these procedures, and since interconnection is a prerequisite to a generator's ability to deliver energy and capacity, the interconnection requirements in this rule are reasonable and do not violate FERC regulations.
COMMENT NO. 9: Several commenters stated that the requirements for a QF to obtain all required government land-use approvals and all necessary environmental permits prior to incurring a LEO should not be included in New Rule I(1)(c). Those requirements are outside of the control of the developer and create a disincentive to LEO formation. The commenters object to what they characterize as development hurdles in the commission's proposed New Rule I(1)(c). The requirements that a developer must have a lease or ownership interest in the real property, obtain all government land-use approvals, and obtain all environmental permits is not necessary to demonstrate a QF's unequivocal commitment to sell its output to a utility. Such requirements are not necessary to execute a binding PPA, and so should not be conditions of establishment of a LEO. The commenters also object to the vagueness of New Rule I(1)(c), as it could lead to litigation over issues, for example, whether or not the option to lease or purchase would satisfy the rule's conditions for site control.
RESPONSE: The department appreciates the comments; however the requirements in the rule for a QF to have site control for the length of the asserted LEO are important and relevant requirements. Based on comments received, several projects have asserted LEOs in the past only to find out later that they cannot move forward because they do not have a legal interest in the land or they have not obtained the necessary governmental approvals to build their facility as proposed. Site control has been required by several other states as appropriate requirements for the creation of a LEO. Courts have upheld state commissions' findings that a QF had established a LEO because the QF project had demonstrated significant technical and operational development—not simply a unilateral tender of a PPA by the QF. For example, the Supreme Court of New Hampshire upheld the state commission's finding that a QF had formed a LEO where, in addition to unilaterally tendering an IA, the QF demonstrated that it had obtained siting and environmental permits, secured property rights, and sufficiently advanced its design and construction plans, among other things. Appeal of Public Service Co. of N.H., 539 A.2d 275, 281 (N.H. 1988). By contrast, a Pennsylvania court upheld the state commission's finding that a QF was not yet viable so as to establish a LEO where it had not yet acquired necessary permits, site development approval, or construction plans and financing. South River Power Partners, L.P. v. Pennsylvania PUC, 696 A.2d 926, 931 (Pa. 1997) (detailing actions not taken by QF). The department has amended the proposed rule to ensure it is as clear as possible to hopefully avoid any issues of clarity or litigation.
COMMENT NO. 10: Several commenters expressed support for the commission's proposal to ascertain a developer's legal interest in the real property for the project, all required government land use approvals, and all necessary environmental permits. One of those commenters suggested modifications to this section including requiring the developer to provide site control documents to the utility, verifying that site control is for the length of the asserted LEO, provide proof of lease or fee ownership in the property, and submission of land use and environmental permits necessary to construct the facility. The commenter made reference to various situations where developers had asserted LEOs but either a governmental body refused a zoning change, refused to issue a conditional permit, or a developer did not have an executed lease so the project could not move forward. Another commenter said it's reasonable to require a QF to provide some initial evidence of its ability to gain regulatory land approval but obtaining all approvals and environmental permits imposes an unrealistic burden on the QF.
RESPONSE: The department appreciates those comments and has made some modifications to the site control requirements. Site control has been required by several other states as appropriate requirements for the creation of a LEO as discussed above. Based on comments received, several projects have asserted LEOs in the past only to find out later that they cannot move forward because they do not have a legal interest in the land or they have not obtained the necessary governmental approvals to build their facility as proposed. After significant time has been expended by the QF developer, intervenors, and the department, that project cannot move forward because a local government does not approve the project. The department finds this is a reasonable requirement.
COMMENT NO. 11: One commenter supported the interconnection request requirement, but suggested that there should be flexibility in cases where the utility violates its own OATT timelines and causes delays. Another commenter states that the interconnection milestones in the proposed rule may contradict the FERC ruling that no rigid policy controllable by the utility may be allowed to prevent a QF from committing to sell its output.
RESPONSE: The department appreciates the comments and has amended the interconnection requirements to ensure that if a utility violates its own OATT timelines a LEO can still be created. The department has included timelines that a utility must meet; otherwise a LEO will be created by lack of utility action. For example in New Rule I, if a QF is requesting to interconnect under the SGIP and 53 days have elapsed since the qualifying facility submitted the interconnection request and all of the following conditions exist: the interconnecting utility did not provide the qualifying facility a System Impact Study Agreement within 38 days of the qualifying facility's interconnection request; the qualifying facility has not waived the tariffed Small Generator Interconnection Procedure (SGIP) timeline; and the qualifying facility has satisfied applicable interconnection customer deadlines in the tariffed SGIP, then a LEO will be created. Then for qualifying facilities requesting to interconnect under the Large Generator Interconnection Procedures (LGIP), 90 days have elapsed since the qualifying facility submitted a completed interconnection request with the interconnecting utility, and all of the following conditions have been met: the qualifying facility has not been provided a System Impact Study Agreement within 60 days of the initial interconnection request; the qualifying facility has not waived the timeline associated with the work of the interconnecting utility associated with the LGIP process; and the qualifying facility has timely met its deadlines established in the LGIP, then a LEO will be created.
COMMENT NO. 12: One commenter discussed that the timelines for large and small generator interconnection requests for varying sizes of QFs are relatively similar and the commenter attached interconnection request forms to its comments. The interconnection process begins with a developer submitting an Interconnection Request to the utility’s transmission group, which triggers timelines. The commenter observes that developers abandon many projects either after the scoping meeting or when the first study reveals adverse system impacts. The commenter states that in order for the utility to have the necessary planning information and to calculate a correct avoided cost, the interconnection application must be complete. In addition, to ensure the developers have considered the cost of interconnection, the rule should require a QF to have agreed to complete either a System Impact Study or Facilities Study before creating a LEO. The commenter stated that these amendments will add simplicity and clarity to the proposed rule by ensuring that the QF developer is committed to a real, rather than a paper project.
RESPONSE: The department appreciates these comments and the detail provided about the timelines for SGIP and LGIP. The department agrees that the QF should be required to agree to complete a System Impact Study before creating a LEO and the rule has been amended consistent with these comments. The department shares the concerns of the commenter that the QF developer needs to make sufficient commitments by proceeding part of the way through the interconnection process to confirm it has committed to a real project and not just a paper project. These recommendations, in part, are adopted in this rule.
COMMENT NO. 13: One commenter was concerned that the proposed New Rule II is too ambiguous in describing the access QFs will have to PowerSimm modeling. Developers should have full access to the model and be allowed to make any adjustments to input and output parameters, as well as access to the utility's input and assumptions in its avoided cost models. It should not be left to the utility or the commission to determine what constitutes a "reasonable request" any time an issue arises. NorthWestern and QF developers also have different definitions of what constitutes "reasonably transparent data." Another commenter supported the commission's attempt to improve QF access to utility avoided cost data and agree with the commission's definition of production profile. This commenter proposed various changes to the wording in New Rule II.
RESPONSE: The department appreciates the comments and has clarified New Rule II to more specifically describe the access QFs will have to a utility’s proprietary modeling software. The department does not agree that QFs must have full, unfettered access to a utility's modeling software in order to obtain an adequate understanding of the utility's avoided cost calculation. In addition to being able to conduct alternative avoided cost calculations with the utility’s model, QFs will have all the inputs and assumptions underlying a utility's calculations and can, if they choose, use their own modeling software to make alternative calculations.
COMMENT NO. 14: One commenter stated that the requirement in New Rule II(2) for a utility to provide an avoided cost within 14 days of a request from a QF is sometimes unachievable due to factors outside of the utility's control. The commenter proposes that the 14 day requirement be extended to 21 days after receipt of resource data or if not feasible an estimate of when the avoided cost will be provided. The commenter also stated the utility should be able to request resource data that underlies the QF's production profile. Finally upon receipt of the resource data, the utility should be allowed seven days to provide the market project inputs to the QF.
RESPONSE: The department generally agrees with the commenter and has extended the deadline to 21 days. The department also clarified the rule that the QF must provide the resource information, including generating technology, size, and location of the facility. In addition, the rule was clarified that the utility must provide the qualifying facility with all assumptions and inputs used to make the avoided cost calculation. Out of fairness, QFs will have an equal 21 days of access to the model.
COMMENT NO. 15: One commenter stated that New Rule II(3), established bad public policy and imposes unreasonable costs on either the utility or its customers. The commenter recommends that all costs incurred for QFs to access proprietary software for an alternative avoided cost calculation be recoverable in a tracking mechanism. Any additional costs after the first alternative calculation should be borne by the QF. Finally the software developer should separately invoice costs for calculations requested by QFs.
RESPONSE: FERC regulations state that when a QF chooses to deliver power to a utility pursuant to a LEO, rates must be based on avoided costs calculated on the date the obligation was incurred. In addition, a utility is obligated to make available information from which its avoided costs may be determined. Thus, it is neither bad public policy nor unreasonable to require a utility to provide a QF reasonable access to the inputs, assumptions, and modeling software used to determine avoided costs. Multiple methods are available to make avoided cost calculations, not all of which require a utility to use proprietary modeling software. Where a public utility chooses to use proprietary modeling software, compliance with FERC regulations and the public interest require mechanisms to ensure adequate transparency so that any rates based on the resulting avoided costs do not discriminate against QFs.
COMMENT NO. 16: One commenter reminded the commission that several issues addressed in this rulemaking are currently before the courts in various proceedings, and the commission may want to consider the timing of its rulemaking to include commentary and direction that may be issued by the courts.
RESPONSE: The department appreciates this comment. The department has tried to balance the timing of its rulemaking based on the various proceedings ongoing. On November 24, 2017, the department issued Order No. 7500d and invited any interested party to file a petition to initiate rulemaking pursuant to 2-4-315, MCA, to address the Whitehall Wind LEO test. No petition for rulemaking was filed by any interested person. Therefore in March of 2018, the department, on its own initiative, filed a rulemaking notice with the Secretary of State. The department is aware that Courts may have some guidance on whether the LEO rule should be amended or not, but the department is the appropriate entity to determine what the LEO test should look like. The department has decided it is appropriate to finalize the rulemaking based on the oral and written comments received.
COMMENT NO. 17: One commenter stated that the amendment of the definition of production profile in ARM 38.5.1901 is clear and correct as it allows for the self-produced energy production modeling based on widely available data that is the industry standard for renewables. The commenter stated that they appreciate the commission clarifying the definition.
RESPONSE: The department appreciates the comment and amends ARM 38.5.1901 as proposed.
/s/ JUSTIN KRASKE /s/ BRAD JOHNSON
Justin Kraske Brad Johnson
Rule Reviewer Chairman
Department of Public Service Regulation
Certified to the Secretary of State June 26, 2018.