TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 22. PROCEDURAL RULES

SUBCHAPTER J. SUMMARY PROCEEDINGS

The Public Utility Commission of Texas (commission) adopts the repeal of §22.181, relating to dismissal of a proceeding without changes to the proposed text as published in the September 23, 2016 issue of the Texas Register (41 TexReg 7371). New §22.181, relating to dismissal of a proceeding, and amendment to §22.182, relating to summary decision are adopted with changes to the proposed text as published in the September 23, 2016 issue of the Texas Register (41 TexReg 7372). The repealed, new, and amended sections will clarify the procedures that apply to motions to dismiss and motions for summary decision. The repealed, new, and amended sections are adopted under project number 46199.

The commission received comments on the proposed repeal, new section, and amendments from Southwestern Bell Telephone Company d/b/a AT&T Texas and Luminant Energy Company LLC.

Section 22.181(d) and (e)

Luminant proposed the addition of cross-references and other non-substantive changes to §22.181. Luminant also proposed revising §22.181(e)(3) to clarify that parties other than the applicant have the opportunity to respond to motions to dismiss in a proceeding.

Commission response

The commission agrees with some of Luminant's non-substantive recommendations and its recommendation regarding §22.181(e). The commission adds cross-references to §22.181(d) as suggested by Luminant and adds language to §22.181(e) to clarify that parties other than the applicant have an opportunity to respond to motions to dismiss.

Section 22.181(f)

Luminant argued that subsection §22.181(f)(4) could be misinterpreted to apply to all presiding officer actions under §22.181(f)(2). Luminant suggested that the commission clarify subsection (f)(4) to state that an order issued under paragraph (2) is final only if the order addresses withdrawal under subsection (g)(1) or (2).

Commission response

The commission renumbers subsections (f)(3) and (4) as (f)(4) and (6) respectively. The commission understands Luminant's concern and adds Luminant's suggested revision to subsection (f)(6) to clarify that an order of an administrative law judge is final if the dismissal is based solely upon withdrawal of an application under subsections (g)(1) or (2). The commission also adds new (f)(3) and (5) and revises (f)(2), (4), and (6) to clarify whether it is the commission or an administrative law judge acting under the paragraph. These modifications are intended to clarify the scope of the commission's delegation of authority.

AT&T proposed deleting the language in §22.181(f)(3) giving the presiding officer discretion to issue either an interim order or proposal for decision in cases of partial dismissal. AT&T argued that the proposed language could lead to confusion on the part of the commission and parties since a proposal for decision suggests that a final order may be adopted by the commission. AT&T therefore proposed that this paragraph only allow for issuance of an interim order. AT&T also proposed technical edits to this subsection in accordance with its recommendations.

Commission response

The commission makes changes to this paragraph to reduce the risk of confusion but disagrees with AT&T that this paragraph should only allow for issuance of an interim order. The commission renumbers §22.181(f)(3) as (f)(4) and adds language to clarify that in the case of partial dismissal the presiding officer may either issue an interim order or proposal for interim decision. Such interim orders and proposals for interim decision will produce interim orders of the commission subject to motions for reconsideration. The commission's addition of clarifying language resolves AT&T's concern that the issuance of a proposal for decision for a partial dismissal could cause confusion.

Section 22.181(g)

AT&T proposed that §22.181(g)(1) be revised to allow a party to withdraw its application with prejudice. AT&T also recommended that this subsection be revised to change the timeframe in which a party can withdraw its application without prejudice. AT&T proposed changing the proposed language that allows a party to withdraw its application without prejudice before it has presented its direct case to language that allows a party to withdraw its application without prejudice only before it has begun the presentation of its direct case. AT&T argued that there could be disputes as to when a party has presented its direct case and that its proposed language avoids such potential disputes.

Commission response

The commission agrees with AT&T's recommendation to add language that allows a party to agree to withdraw its application with prejudice. However, the commission finds AT&T's recommendation regarding when a party can withdraw its application without prejudice to be outside the scope of this rulemaking. AT&T's proposed revision would substantively change the rule rather than clarify current procedure, and the commission therefore declines to adopt this revision.

AT&T recommended deleting the phrase after the matter has otherwise been set on the open meeting agenda from §22.181(g)(2) and (3). AT&T argued that the proposed language creates conflicting timetables that would lead to confusion. Luminant suggested that language be added to clarify that §22.181(g)(2) and (3) would apply only after a matter has been set on the open meeting agenda for final disposition.

Commission response

The commission strikes the phrase after the matter has otherwise been set on an open meeting agenda from §22.181(g)(2) and (3), rejects Luminant's recommended language, and adds new (g)(4) to clarify its intended meaning. The new (g)(4) specifies the standard that will apply to evaluation of a request to withdraw an application after the matter has been set on an open meeting agenda for consideration of an appeal of an interim order, a request for certified issues, or a preliminary order with threshold legal or policy issues.

Luminant argued the amendments to §22.181(g)(4) would permit the presiding officer to condition withdrawal at any time after the presentation of the applicant's direct case upon a finding that withdrawal is with prejudice. Luminant stated that it was unclear what justification exists for ordering a dismissal with prejudice over the objection of the applicant. Therefore, Luminant suggested the addition of language specifying that withdrawal with prejudice can only be granted under this paragraph when the applicant has requested that result.

Commission response

The commission renumbers §22.181(g)(4) as (g)(5) and adds language to subsection (g)(5) to specify that if the presiding officer finds good cause for withdrawal, an order of dismissal under (g)(5) shall not be with prejudice unless requested by the applicant.

Section 22.182(f)

Luminant proposed the addition of language to §22.182(f) to clarify that a partial summary decision will result in either an interim order or interim proposal for decision that is subject to motions for reconsideration.

Commission response

The commission adds language to §22.182(f) in accordance with Luminant's suggestion to ensure the commission's intent is clear. Similar to the revisions in §22.181, the commission revises its language in §22.182(f) and adds subsection (g) to clarify the procedure for when the commission is acting as opposed to an administrative law judge.

In accordance with its recommendation regarding §22.181(f)(3), AT&T proposed deleting language in §22.182(f) giving the presiding officer discretion to issue either an interim order or proposal for decision in cases of partial summary decision. Again, AT&T argued that this subsection should only provide for the issuance of an interim order and that the proposed language could lead to confusion.

Commission response

The commission makes changes to this subsection to reduce the risk of confusion but disagrees with AT&T that this subsection should only allow for issuance of an interim order. The commission adds language to §22.182(f) to clarify that in the case of partial summary decision the presiding officer may either issue an interim order or proposal for interim decision. Such interim orders and proposals for interim decision will produce interim orders of the commission subject to motions for reconsideration. The commission's addition of clarifying language resolves AT&T's concern that the issuance of a proposal for decision for a partial summary decision could cause confusion.

All comments, including any not specifically referenced herein, were fully considered by the commission. In adopting these sections, the commission makes other minor modifications for the purpose of clarifying its intent.

16 TAC §22.181

The repeal is adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 and §14.052 (West 2016) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure.

Cross Reference to Statutes: PURA §14.002 and §14.052.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 16, 2016.

TRD-201606655

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 5, 2017

Proposal publication date: September 23, 2016

For further information, please call: (512) 936-7223


16 TAC §22.181, §22.182

The new and amended sections are adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 and §14.052 (West 2016) (PURA) which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, including rules of practice and procedure.

Cross Reference to Statutes: PURA §14.002 and §14.052.

§22.181.Dismissal of a Proceeding. (a) Dismissal of a proceeding. Upon the motion of the presiding officer or the motion of any party, the presiding officer may recommend that the commission dismiss, with or without prejudice, any proceeding for any reason specified in this section.

(b) Dismissal of issues within a proceeding. Upon the motion of the presiding officer or the motion of any party, the presiding officer may dismiss or may recommend that the commission dismiss, with or without prejudice, one or more issues within a proceeding for any reason specified in this section.

(c) Dismissal without hearing. A dismissal under this section requires a hearing unless the facts necessary to support the dismissal are uncontested or are established as a matter of law.

(d) Reasons for dismissal. Dismissal of a proceeding or one or more issues within a proceeding may be based on one or more of the following reasons:

(1) lack of jurisdiction;

(2) moot questions or obsolete petitions;

(3) res judicata;

(4) collateral estoppel;

(5) unnecessary duplication of proceedings;

(6) failure to prosecute;

(7) failure to amend an application such that it is sufficient after repeated determinations that the application is insufficient;

(8) failure to state a claim for which relief can be granted;

(9) gross abuse of discovery consistent with §22.161(b)(2) of this title (relating to Sanctions);

(10) withdrawal of an application consistent with subsection (g) of this section; or

(11) other good cause shown.

(e) Motion for dismissal, responses, and replies. Dismissal of a proceeding or one or more issues within a proceeding may be made upon the motion of the presiding officer or the motion of any party.

(1) A party's motion for dismissal must specify at least one of the grounds for dismissal identified in subsection (d) of this section. The motion must include a statement that explains the basis for the dismissal and if necessary:

(A) A statement that sets forth the material facts that support the motion; and

(B) An affidavit that supports the motion and that includes evidence that is not found in the then-existing record.

(2) A presiding officer's motion shall be provided by written order or stated in the record and must specify one or more grounds for dismissal identified in subsection (d) of this section and a clear and concise statement of the material facts supporting the dismissal.

(3) The party that initiated the proceeding or any other affected party shall have 20 days from the date of receipt to respond to a motion to dismiss. The response must contain a statement of reasons the party contends the motion to dismiss should not be granted, and if necessary:

(A) A statement that refers to each material fact identified in the motion to dismiss as uncontested that the responding party contends is contested; and

(B) An affidavit that supports the response to the motion to dismiss and that includes evidence the party relies upon to establish contested issues of fact. The affidavit may include evidence that is not found in the then existing record.

(4) Replies to a response to a motion to dismiss may be made only by leave of and as directed by the presiding officer.

(f) Action on a motion to dismiss. Action on a motion to dismiss shall conform to this subsection.

(1) If a hearing on the motion to dismiss is held, that hearing shall be confined to the issues raised by the motion to dismiss.

(2) If the administrative law judge determines that all issues within a proceeding should be dismissed, the administrative law judge must prepare a proposal for decision in accordance with §22.261 of this title (relating to Proposals for Decision) to that effect, unless the reason for dismissal is solely the withdrawal of an application under subsection (g)(1) or (2) of this section, in which case the administrative law judge may issue an order dismissing the proceeding. The commission shall consider the proposal for decision or motion for rehearing on an order of dismissal as soon as is practicable.

(3) If the commission determines that all issues within a proceeding should be dismissed, the commission will issue an order subject to motions for rehearing under §22.264 of this title (relating to Rehearing).

(4) If the administrative law judge determines that one or more, but not all, issues within a proceeding should be dismissed, the administrative law judge may issue a proposal for interim decision or an interim order dismissing such issues. An interim order issued by the administrative law judge resulting in partial dismissal is subject to appeal or reconsideration under §22.123 of this title (relating to Appeal of an Interim Order and Motions for Reconsideration of Interim Order Issued by the Commission).

(5) If the commission determines that one or more, but not all, issues within a proceeding should be dismissed, the commission may issue an interim order dismissing such issues. An interim order issued by the commission resulting in partial dismissal is subject to appeal or reconsideration under §22.123 of this title.

(6) An order of the administrative law judge dismissing a proceeding under paragraph (2) of this subsection based solely upon the withdrawal of an application under subsection (g)(1) or (2) of this section is the final order of the commission and is subject to motions for rehearing under §22.264 of this title.

(g) Withdrawal of application. An application may be withdrawn only in accordance with this subsection.

(1) A party that initiated a proceeding may withdraw its application without prejudice to refiling of same, at any time before that party has presented its direct case. A party may agree to withdraw its application with prejudice.

(2) After the presentation of its direct case, but prior to the issuance of a proposed order or proposal for decision, a party may request to withdraw its application with or without prejudice, and withdrawal may be granted only upon a finding of good cause by the presiding officer.

(3) A request to withdraw an application with or without prejudice after a proposed order or proposal for decision has been issued, may be granted only upon a finding of good cause by the commission. In ruling on the request, the commission will weigh the importance of the matter being addressed to the jurisprudence of the commission and the public interest.

(4) A request to withdraw an application with or without prejudice after the application has been placed on an open meeting agenda for consideration of an appeal of an interim order, a request for certified issues, or a preliminary order with threshold legal or policy issues may be granted only upon a finding of good cause by the commission. In ruling on the request, the commission will weigh the importance of the matter being addressed to the jurisprudence of the commission and the public interest.

(5) If a request to withdraw an application is granted, the presiding officer shall issue an order of dismissal stating whether the dismissal is with or without prejudice. If the presiding officer finds good cause, the order of dismissal under this paragraph shall not be with prejudice, unless the applicant requests dismissal with prejudice. Such order must, if applicable, specify the facts on which good cause is based and the basis of the dismissal and is the final order of the commission subject to motions for rehearing under §22.264 of this title.

§22.182.Summary Decision.

(a) Motion for summary decision. The presiding officer, on motion by any party, may grant a motion for summary decision on any or all issues to the extent that the pleadings, affidavits, materials obtained by discovery or otherwise, admissions, matters officially noticed in accordance with §22.222 of this title (relating to Official Notice), or evidence of record show that there is no genuine issue as to any material fact and that the moving party is entitled to a decision in its favor, as a matter of law, on the issues expressly set forth in the motion.

(b) Filing and contents of motion. Any party to a proceeding may move for summary decision on any or all of the issues. The motion must be filed before the close of the hearing on the merits or before the issuance of a proposal for decision or proposed order if no hearing is held, unless the time to file is extended by order of the presiding officer. The party filing the motion shall demonstrate that the issue or issues may be resolved by summary decision in accordance with the standard set forth in subsection (a) of this section. Affidavits in support of the motion shall be based on personal knowledge and shall set forth such facts as would be admissible in evidence. A motion for summary decision shall specifically describe the facts upon which the request for summary decision is based, the information and materials which demonstrate those facts, and the laws or legal theories that entitle the movant to summary decision.

(c) Response to motion. Any response to a motion for summary decision shall be filed within the time set by the presiding officer. A party opposing the motion shall show, by affidavits, materials obtained by discovery or otherwise, admissions, matters officially noticed, or evidence of record, that there is a genuine issue of material fact for determination at the hearing, or that summary decision is inappropriate as a matter of law.

(d) Hearing on the motion. If appropriate, the presiding office shall set the motion for hearing.

(e) No further hearing. No further evidentiary hearing shall be held on issues for which summary decision has been granted.

(f) Action on the motion by administrative law judge. The administrative law judge must issue a proposal for decision if all issues will be resolved by summary decision. The administrative law judge may issue an interim order or a proposal for interim decision if some, but not all, issues will be resolved by summary decision. Such a partial summary decision may result if the motion for summary decision does not include all issues or, if the motion does include all issues, the administrative law judge grants summary decision on some issues and denies summary decision on other issues. Parties may file exceptions and replies to exceptions to a proposal for interim decision recommending resolution of issues by summary decision. An interim order issued by the administrative law judge granting partial summary decision is subject to appeal or reconsideration under §22.123 of this title (relating to Appeal of an Interim Order and Motions for Reconsideration of Interim Order Issued by the Commission).

(g) Action on the motion by the commission. If all issues will be resolved by summary decision, the commission will issue an order that is subject to motions for rehearing under §22.264 of this title (relating to Motions for Rehearing). An interim order issued by the commission granting partial summary decision is subject to reconsideration under §22.123 of this title.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 16, 2016.

TRD-201606656

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 5, 2017

Proposal publication date: September 23, 2016

For further information, please call: (512) 936-7223


CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER I. TRANSMISSION AND DISTRIBUTION

DIVISION 2. TRANSMISSION AND DISTRIBUTION APPLICABLE TO ALL ELECTRIC UTILITIES

16 TAC §25.211

The Public Utility Commission of Texas (commission) adopts an amendment to §25.211, relating to interconnection of on-site distributed generation (DG rule), with changes to the proposed text as published in the June 24, 2016 issue of the Texas Register (41 TexReg 4577). Amendments are made solely to the Agreement for Interconnection and Parallel Operation of Distributed Generation (Interconnection Agreement or IA). The adopted amendments allow the end-use customer either to be the non-utility party to the IA (identified as Option 1) or otherwise to elect one of the following entities to be the non-utility party to the IA on their behalf: the entity who owns the distributed generation (DG) facility but is not the end-use customer (DG owner or an Option 2 entity), the owner of the premises at which the DG facility is located (premises owner or an Option 3 entity), or the person who by contract is assigned ownership rights to energy produced by the DG facility (an Option 4 entity). This amendment is adopted under Project Number 45078.

The commission received comments on the proposed amendments from AEP Texas Central Company, AEP Texas North Company, CenterPoint Energy Houston Electric, LLC, El Paso Electric Company, Entergy Texas, Inc., Oncor Electric Delivery Company LLC, Sharyland Utilities, L.P., Southwestern Electric Power Company, Southwestern Public Service Company, and Texas-New Mexico Power Company (collectively, Joint Utilities); NRG Energy, Inc., (NRG); the Office of Public Utility Counsel (OPUC); SolarCity, the Solar Energy Industries Association (SEIA); and the Texas Industrial Energy Consumers (TIEC).

Reply comments were received from SolarCity, OPUC, the Alliance for Retail Markets (with members Direct Energy, LP, and Noble Americas Energy Solutions LLC, participating), the Texas Energy Association for Marketers, SEIA, and Sunstreet Energy Group (collectively, Joint Market Participants); Joint Utilities; and TXU Energy Retail Company LLC (TXU Energy).

On November 10, 2016, the commission requested comments on questions relating to the commission's jurisdiction. Comments were received from NRG, OPUC, Joint Market Participants, Joint Utilities, and TXU Energy.

Section 25.211(p) - Agreement for Interconnection and Parallel Operation of Distributed Generation

General Comments

OPUC and SEIA stated that the proposed amendments appropriately recognized the realities of the current DG market in which the end-use customer may not be the best party to be the non-utility signatory to the Interconnection Agreement. OPUC stated that it was often not appropriate for the end-use customer to be responsible for the obligations and risks imposed by the IA, and that the proposed amendments better protect the rights of end-use customers who choose to use DG, as well as remove a potential barrier to adoption of such technologies. SEIA stated that allowing a distributed generation owner (DGO) to be a party to the IA will provide the DGO additional business certainty to further invest in the solar distributed generation market in the state. SolarCity stated that it strongly supported the proposed amendments to allow non-utility entities other than the end-use customer to sign the IA. Joint Market Participants likewise generally supported the proposed amendments and stated that restricting the non-utility signatory to the end-use customer would stifle growth and result in a barrier to entry for the average end-use customer who might be overwhelmed by the process and unwilling or unable to accept liability under an IA.

NRG stated that it supported the proposed revisions requiring the end-use customer to clearly acknowledge and approve the execution of the IA if it is executed by a third-party, which it argued should mitigate concerns that the customer may not be aware of the IA.

SolarCity and SEIA both stated that the proposed amendments to permit an Option 2-4 entity (a DG owner, premises owner, or the person who by contract is assigned ownership rights to energy produced by the DG facility) to execute the IA on behalf of the customer are consistent with the Public Utilities Regulatory Act (PURA) and commission rules. Specifically, SolarCity and SEIA asserted that a Distributed Renewable Generation Owner (DRGO), as defined in PURA §39.916(a)(2), possesses interconnection rights pursuant to PURA §39.916(a)(3) and §25.217(c)(4). In reply comments, the Joint Market Participants agreed that the end-use customer is not the only party with a direct physical connection to the utility, citing to PURA §39.916(a)(3) which defines "interconnection" as the "right of a DRGO to physically connect DRG [distributed renewable generation] to an electricity distribution system."

Conversely, Joint Utilities stated that they strongly prefer that the non-utility party to the IA be limited to the end-use customer. Joint Utilities argued that under PURA, the end-use customer is the only entity that can legally request a DG facility be interconnected to the utility. According to the Joint Utilities, PURA §39.101 grants rights to the customer, not the DG owner, and that, while PURA §39.916 gives DG owners the right to interconnect with the utility, subsection (c) provides that a customer may request DG interconnection. Joint Utilities argued that the Legislature could have authorized not just the customer, but any DRGO to apply for interconnection, but chose to restrict the filing of the interconnection request to the end-use customer. In reply comments, Joint Utilities asserted that only the end-use customer has the legal right to request DG interconnection. Joint Utilities also asserted that the definition of "customer" in §25.211(c)(3) as "an entity interconnected to the company's utility system" refers to the end-use customer, because there is no direct interconnection between the DG facility itself and the utility's system. Joint Utilities asserted that the end-use customer's electrical system hosts the DG facility, making the end-use customer the only necessary and appropriate non-utility signatory to the IA. Joint Utilities averred that, to the extent that §25.217(c)(4) may give DRGOs a right to request interconnection, then it is an invalid exercise of the commission's authority, as the commission cannot give DRGOs rights that the Legislature did not grant in PURA.

Joint Utilities also argued that the end-use customer is the only appropriate non-utility signatory because they are ultimately responsible for all the electrical equipment behind the meter, even if they choose to delegate such responsibilities. Joint Utilities also noted that §25.217, which governs an entity's authority to act on behalf of a customer, requires a contractual relationship to do so by letter of agency or otherwise. Joint Utilities argued that the DG owner can represent the customer and act on the customer's behalf as an agent, but cannot supplant the customer and act on its own behalf, as the end-use customer shoulders all of the legal rights and obligations.

Joint Utilities argued that the end-use customer should be the only non-utility signatory so that the end-use customer is fully aware of the possible negative impacts of hosting a DG facility on their retail electric service. Joint Market Participants argued that OPUC's proposed language requiring the Option 2-4 Customer to notify the end-use customer of disconnection, as well as requiring the Company's (utility's) best efforts to provide the end-use customer and the Customer with reasonable prior notice of disconnection, should make the end-use customer sufficiently aware of such negative impacts.

Commission response

The commission declines to limit the non-utility signatory to the end-use customer, as proposed by Joint Utilities, because doing so could unnecessarily restrict the end-use customer's preferences with respect to DG arrangements.

Joint Utilities argued that the IA should be signed solely by the utility and the end-use customer, because they are the only entities that are physically connected to each other. However, this argument is incorrect in some circumstances. The end-use customer may be a tenant and in that case the owner of the premises to which utility service is provided is not the end-use customer but may own the facilities that physically connect to the utility's facilities. Furthermore, the premises owner may own the DG; the end-use customer may own the DG; or an entity other than the premises owner or end-use customer may own the DG. A premises owner may decide to enter into a lease of the premises with an end-use customer and allow the interconnection of DG on the premises only if the end-use customer agrees in the premises lease that the premises owner will be the non-utility signatory to the IA. Thus, the premises owner could contractually prohibit interconnection of DG unless the premises owner is a signatory to the IA. Therefore, limiting the non-utility signatory to the end-use customer could result in the end-use customer not having access to on-site DG. This result would be inconsistent with the intent of PURA §39.101(b)(3), which states that a customer is entitled to access to on-site DG.

Furthermore, a utility entering into an agreement with a premises owner to interconnect DG is similar to the longstanding and necessary practice of a utility entering into a facilities easement agreement with a landowner who is not the end-use customer served by the facilities. Requiring the utility to allow the premises owner to sign the IA when all applicable commission rule requirements are met results in utility service, instrumentalities, and facilities that are safe, adequate, efficient, and reasonable, consistent with PURA §38.001; results in rates, operations, and services that are just and reasonable to the end-use customer and the utility, consistent with PURA §11.002(a); and is a reasonable exercise of the commission's general power to regulate and supervise the business of each utility, consistent with PURA §14.001.

As with the premises owner, public policy supports allowing the non-utility party to the IA to be the DG owner or the person (such as a retail electric provider) who by contract is assigned ownership rights to energy produced by the DG facility. The number of DG facilities not owned by end-use customers and the number of offerings by retail electric providers (REPs) involving DG are increasing. Joint Market Participants consist of OPUC, two REP associations, two solar energy companies, and a solar energy industry association. The commission shares Joint Market Participants' concern that restricting the non-utility signatory to the end-use customer would prevent the end-use customer from being able to engage in a relationship with the Option 2-4 Customer according to their preferences, which may include a preference to have the Option 2-4 Customer take care of the interconnection process and accept liability under an IA.

Utilities in Texas and other states have experience signing IAs with entities that are not the end-use customers. Affiliates of Entergy Texas, Inc. in Louisiana have signed interconnection agreements with premises owners rather than the tenants who are the end-use customers. This arrangement avoids the need for a new interconnection agreement when the tenant changes. In New Mexico, Southwestern Public Service Company in some cases has signed interconnection agreements with the DG owners rather than the end-use customers. See, Rulemaking Proceeding Related to Distributed Generation, Project No. 42532, Joint Utilities' Initial Comments on Staff's Questions (October 13, 2014) at pages 4-5. In Texas, Oncor Electric Delivery Company LLC has interconnected over 550 DG facilities where the owner of the DG facility is not the "utility customer/owner of the property" upon which the DG facility was installed, and has developed an approach to address such circumstances in the IA that has been acceptable to all parties involved. See, Rulemaking to Amend Substantive Rule 25.211, Interconnection of On-Site Distributed Generation (DG), and the Pro-Forma Interconnection Agreement and Tariff, Project Number 41325, Order Adopting Amendments to §25.211 as Approved at the February 21, 2015 Open Meeting at page 4.

The DG rule addresses the interconnection of a generation facility of ten megawatts (MW) or less at distribution voltage by an entity that is eligible for interconnection under the DG rule and other commission rules. See, §25.211(c)(10) (defining "on-site distributed generation (or distributed generation)"); §25.5(31) (defining "distribution line"); and §25.211(c)(3) (defining "customer" as "Any entity interconnected to the company's utility system for the purpose of receiving or exporting electric power from or to the company's utility system."). Although the comments filed in this rulemaking focused on DRG, the DG rule applies to a broad variety of DG facilities and entities. For example, DG facilities that may be interconnected under the DG rule include a 10 MW diesel or natural-gas-fired generation facility owned by a power generation company (PGC) that both provides on-site backup electricity to a manufacturing facility through a REP and sells electricity in the wholesale market; a 5 MW wind generation facility owned by an entity that is both a PGC and a qualifying facility (QF) that sells electricity through a REP to an on-site business and sells electricity in the wholesale market using the transmission grid; and solar panels on a house owned by a DRGO that sells electricity to the homeowner and the homeowner's REP.

PURA contains various provisions that authorize the commission to require a utility to enter into an IA with an owner or operator of DG facilities who need not be the end-use customer behind the utility's point of delivery. PURA §35.004(b) states: "The commission shall ensure that an electric utility or transmission and distribution utility provides nondiscriminatory access to wholesale transmission service for qualifying facilities, exempt wholesale generators, power marketers, power generation companies, retail electric providers, and other electric utilities or transmission and distribution utilities." PURA §31.002(20) defines transmission service to include transmission over distribution facilities. Renewable and non-renewable DG entities may own or operate generation facilities as PGCs and QFs, and therefore PURA §35.004 applies to them, including interconnection rights. See also, PURA §§31.002(4-a) and (10) and 35.036(c) (addressing an interconnection request by an owner or operator of a distributed natural gas facility). These PURA provisions do not entitle PGCs, QFs, REPs, and the other listed entities to sign distributed generation interconnection agreements. However, by requiring the commission to ensure nondiscriminatory access to "wholesale transmission service" at distribution voltage, the provisions give the commission the discretion to require a utility to sign the IA with a PGC, QF, or REP, provided all other applicable PURA and commission rule requirements are met.

The commission has rules that implement PURA §35.004(b). "The obligation to provide comparable transmission service applies to a TSP [transmission service provider] even if the TSP's interconnection with the transmission service customer is through distribution, rather than transmission facilities." See, §25.191(d)(2). "Transmission service customer" is defined by §25.5(142) as: "A transmission service provider, distribution service provider, river authority, municipally-owned utility, electric cooperative, power generation company, retail electric provider, federal power marketing agency, exempt wholesale generator, qualifying facility, power marketer, or other person whom the commission has determined to be eligible to be a transmission service customer. A retail customer, as defined in this section, may not be a transmission service customer."

The commission has a QF rule, §25.242, which states: "Interconnection by a qualifying facility is addressed by Subchapter I, Division 1, of this chapter (relating to transmission and distribution) if the interconnection is to a transmission system and by §25.211 of this title (relating to interconnection of on-site distributed generation) [the DG rule] if the interconnection is to a distribution system, except if the interconnection is regulated by the Federal Energy Regulatory Commission." See, §25.242(f)(3). Like some DRG, some QFs are not owned by the end-use customer and the QF owner may make retail sales to the end-use customer. See, §25.5(96) and (97) ("A qualifying cogenerator that provides electricity to the purchaser of the cogenerator's thermal output is not for that reason considered to be a retail electric provider or a power generation company.")

The commission has a rule that applies specifically to DRG, §25.217 (DRG rule), pursuant to PURA §39.916 and other PURA provisions. See also, §25.213 (Metering for Distributed Renewable Generation and Certain Qualifying Facilities). Like the QF rule, the DRG rule makes clear that the DG rule applies to DRG: "An existing or prospective DRGO [distributed renewable generation owner] or ISD-SG Owner [independent school district solar generation owner] may request interconnection by submitting an application for interconnection with the electric utility. The application shall be on a form approved by the commission and processed by the electric utility in accordance with §25.211 [the DG rule] and §25.212 of this title." See, §25.217(c)(4).

The number of DG facilities not owned by end-use customers and the number of offerings by REPs involving DG are increasing. This rulemaking was initiated to address IAs for these and other DG arrangements in a clear and consistent manner. The IA amendments adopted by the commission in this rulemaking give an end-use customer the choice of becoming a party to the IA or instead permitting an Option 2-4 entity to do so.

Scope of IA

Joint Utilities and TXU Energy generally objected to broadening the scope of the IA to include permutations of possible DG ownership, financing, installation, and operational right structures, stating that incorporating such complexity into a single IA is difficult and complex. In reply comments, Joint Market Participants asserted that the IA is clearly limited to the four alternatives to the end-use customer as the non-utility signatories, and asserted that generators are already successfully entering into IAs with utilities. SolarCity noted that it recently executed an IA with a large utility with itself as the Customer, and asserted that no material issues have arisen from this arrangement. In reply comments, Joint Utilities stated that this execution was only done several years ago, with SolarCity and only one other residential solar company. Joint Utilities asserted that issues may arise with such arrangements as the number of DG installations increases together with the number and types of potential non-utility signatories.

Commission response

The commission agrees with the comments of Joint Market Participants that, under the proposed amendments, the non-end-use customer entities that can enter into the IA on behalf of the end-use customer is limited to the Option 2-4 entities, and therefore the IA is not inappropriately broad.

Apportionment of Risks and Responsibilities

Joint Utilities stated that it is not the commission's role to determine the appropriate apportionment of risks and responsibilities between the end-use customer, the DG owner, the landlord, the financing company, and the owner of the output. Joint Utilities argued that the scope of the IA should be narrowly limited to the physical electrical interconnection of the DG system to the customer's system, and all other rights and responsibilities between the third-party and the end-use customer are more properly included in their private contracts.

Commission response

The commission agrees with the comments of Joint Utilities. The proposed amendments in the IA do not govern the relationship between the end-use customer and any Option 2-4 entity associated with the DG facility.

Complaints

Joint Utilities asserted that, should the end-use customer be disconnected for one of a variety of reasons, this would result in the DG facilities at the premises also being disconnected. Joint Utilities argued that allowing other entities to sign the IA may result in those parties bringing complaint cases against the end-use customer for failing to keep the DG facilities interconnected to the utility.

With respect to complaints, the Joint Market Participants replied that SolarCity had proposed language in its initial comments that would release the end-use customer from all liabilities under the IA if the end-use customer selected an Option 2-4 entity to execute the IA on their behalf. Joint Market Participants asserted that SolarCity's proposed language would prevent the non-utility signatory from bringing a complaint against the end-use customer as the end-use customer is released from all liabilities under the IA, and would prohibit the third-party signatory from bringing a complaint against the utility for the end-use customer's failure to keep the DG facilities interconnected. Joint Market Participants stated that it was amenable to additional language expressly waiving a third-party signatory's rights to file any complaint with the commission against the end-use customer.

Commission response

The purpose of the IA is to govern the relationship between the Customer - the end-use customer or one of three types of non-end-use customer entities - and the Company (utility). The IA does not govern the relationship between the end-use customer and an Option 2-4 entity that signs the IA. No commenter identified any statutory provision that would give the commission jurisdiction over a complaint by an Option 2-4 entity against an end-use customer. Conversely, allowing the IA to be executed between the utility and an entity other than an end-use customer does not preclude a private bilateral agreement that would be enforceable in the court system from governing the relationship between the signatory and an end-use customer and providing remedies.

Jurisdictional Issues

Joint Utilities asserted that allowing non-end-use customers to sign the IA raises jurisdictional and enforcement issues, stating that PURA is less than clear as to the commission's jurisdiction over DG owners who are not the end-use customer. Joint Utilities suggested that the third-party signatory to the IA may not be subject to the commission's jurisdiction, removing the ability of the commission to enforce contractual provisions in the IA against such an entity without having to file a suit. Joint Utilities noted that, conversely, the commission's authority to process disputes between a utility and an end-use customer is well-established.

In reply comments, the Joint Market Participants asserted that the commission has jurisdiction and authority over any IA executed pursuant to §25.211(p) because the IA is part of the electric utility's commission-approved tariff, and argued that, in the IA, private entity signatories agree to comply with all "applicable rules, regulations, orders of, and tariffs approved by" the regulatory authorities who have jurisdiction. Joint Market Participants argued that any party executing the IA would be directly subjecting themselves to the jurisdictional authority of the commission and it would not be necessary for the commission to establish direct control over the third-party signatory "entity." Joint Market Participants further asserted that it was amenable to additional language stating that any third-party signatory that is not an end-use customer is expressly submitting itself to regulation of the commission for the limited purpose of the IA, and noted that SolarCity had proposed language to this effect.

Joint Utilities, in its replies, stated that an IA signed solely by the utility and the end-use customer has clear lines of authority, with the commission only overseeing the utility and its interconnection with the end-use customer, rather than being involved in the relationships between the end-use customer and the third-party.

In comments in response to questions from the commission, OPUC, Joint Utilities, Joint Market Participants, and TXU argued that the commission's jurisdiction cannot be expanded by agreement or provisions in the IA, as administrative agencies have only the powers expressly conferred to them by the statute, along with those necessarily implied from the authority conferred or the duties imposed, stating that an agency cannot enlarge its own jurisdiction, as has been emphasized by the Texas Supreme Court and the Third Court of Appeals. Joint Utilities argued that newly asserted jurisdiction over non-end-use customer signatories other than the utility to the IA cannot be deemed necessary for the commission to fulfill its express functions or duties with respect to DG, but instead must be viewed as a new power that would be expedient for administrative purposes, and thus would be an impermissible extension of the commission's jurisdiction. Joint Market Participants argued that the potential expansion of commission jurisdiction to become an agency with general customer protection for competitive goods and services behind the meter could be difficult to contain, and noted that such jurisdiction had not been asserted for energy-efficiency service providers.

OPUC and TXU Energy stated that an agency can only exercise those specific powers that the law confers in clear and express language, or powers that are necessarily implied from the statutory authority granted or the duties expressly given or imposed, and cannot exercise what is effectively a new power or a power contradictory to statute based merely on a claim that the power is expedient for administrative purposes. Similarly, TXU Energy stated that an agency cannot contravene specific statutory language; run counter to the general objectives of the statute; or impose any additional burdens, conditions, or restrictions inconsistent with the relevant statutory provisions.

Joint Utilities argued that the basis for the commission to influence the actions of the retail electric customer or the DRGO is by exercising its clear jurisdiction over electric utilities. Joint Utilities stated that the commission does not have the jurisdiction to force the customer or the DRGO to meet any particular requirement; however, it can set out requirements for what the utility will or will not do if the other entity fails to meet certain requirements. Joint Market Participants asserted that the commission does hold authority to ensure customer protection to the extent that the IA creates a direct relationship between the utility and the DRGO. Joint Market Participants stated that signatories to the IA agree to be obligated to comply with all the rules, regulations, orders of, and tariffs approved by, the duly constituted regulatory authorities having jurisdiction. Joint Market Participants noted that the signatory is subjecting itself not only to the relevant authority of the commission, but also to the authority vested to the Office of the Attorney General (OAG).

OPUC stated that the commission draws authority to regulate end-use customers and DG from PURA §§14.002, 35.061, 38.002, 39.101(b)(3), and 39.916, noting that PURA provides the commission with broad authority with respect to DG. Joint Utilities stated that DG is referenced generally in PURA §39.101(b)(3), and specific subsets are addressed elsewhere, such as distributed natural gas generation in PURA §35.036, DRGOs in PURA §39.554 for non-ERCOT utilities, and PURA §39.916. Joint Market Participants argued that PURA §39.916(c) grants the commission authority to adopt rules relating to "procedures of a transmission and distribution utility or electric utility for the submission and processing of a customer's application for interconnection;" PURA §39.916(d) gives the commission jurisdiction to establish rules regarding the safety, technical, and performance standards for DRG; and PURA §39.916(k) limits the commission's jurisdiction over the DRGO for DRG covered by that subsection. OPUC asserted that the full extent of the commission's jurisdiction over DG is difficult to analyze, because it includes the full exercise of all powers necessarily implied from the statutory authority granted or the duties expressly given or imposed. OPUC noted that the IA was initially adopted under the broad PURA §39.101(b)(3) mandate that customers be entitled to access to on-site DG.

OPUC asserted that the commission referred to the Legislature the issue of whether DRGOs were required to register as PGCs because requiring registration of small DRGOs would place a burden on these entities that would outweigh the public benefit of such registration, as well as the issue of whether a person other than the end-use customer may own DRG, in its 2009 and 2011 Scope of Competition in Electric Markets in Texas reports. OPUC stated that, in response to the commission's recommendations, the Legislature adopted PURA §39.916(k) in 2011. OPUC stated that this implies a legislative intent that PURA §39.916(k) was intended to foster the adoption of DG when it was added in 2011. OPUC noted that, while PURA §39.916(k) provides some limitations on the commission's authority, it must be viewed in the light of the legislative intent to remove obstacles from the adoption of DRG.

TXU Energy argued that neither PURA §39.916(k) nor any other section of the statute directly confers jurisdiction to the commission over the retail electric customer or DRGOs merely as a result of their status as a user or DRGO. Similarly, Joint Utilities argued that the commission has limited, if any, jurisdiction over a retail electric customer and a DRGO. TXU Energy stated that PURA §39.916(k) expressly excludes end-use customers and DRGOs for DRG covered by that subsection, from the commission's jurisdiction by making clear that mere ownership or use of DRG covered by that subsection does not subject the user or owner to the commission's regulatory authority under PURA. TXU Energy argued that the limited exception to the express exclusion is in PURA §39.916(d), which provides the commission with the jurisdiction to "establish safety, technical, and performance standards for [DRG] that may be interconnected," but noted that this does not confer jurisdiction to the commission to involve itself in disputes between a DRGO and an end-use customer, and does not override the broad exclusion of end-use customers and DRGOs from the commission's jurisdiction over market participants.

Joint Market Participants stated that the commission has clear jurisdiction over the IA in §25.211, as the IA is part of the electric utility's tariff. Joint Market Participants argued that the Legislature has not provided specific authority that would allow the commission to regulate a DRGO outside the specific IA. However, Joint Market Participants stated that, as a result of executing the IA, the commission will have jurisdiction over the DRGO in those areas by virtue of the DRGO's executing the IA, which is part of the electric utility's tariff and thus subject to the commission's jurisdiction.

OPUC asserted that, to the extent that the commission does not have jurisdiction over all the controversies that could arise from the IA or the use of DG in general, other remedies may be available. TXU Energy stated that PURA §39.916 and Chapter 17 of PURA provided express powers to the commission for the protection of end-use customers, but that this authority is primarily over the conduct of REPs and electric utilities with respect to the end-use customer, and that remedies are generally limited to ordering refunds to end-use customers for overcharges by a REP or a utility, and do not include generally mediating contract disputes between an end-use customer or any other entity. Joint Market Participants asserted that the commission does not have direct authority to resolve disputes relating to a relationship between the end-use customer and the DRGO. OPUC stated that there is no indication that, in adopting provisions related to DG in PURA, the Legislature intended to divest Texas courts of jurisdiction over the various types of claims that an end-use customer may bring against any of the other non-utility parties that may execute the IA, which could include claims of enforcement, claims under the Deceptive Trade Practices Act, or common law claims, such as fraud. Similarly, Joint Market Participants argued that in signing the IA, the DRGO agrees to abide by the Deceptive Trade Practices Act in subjecting itself to all relevant authorities. OPUC asserted that it is not uncommon for agency jurisdiction to fail to extend to all aspects of the subject matter it regulates. Similarly, Joint Market Participants argued that while the Texas Real Estate Commission has the authority to license and regulate certain real estate professionals, it does not have the authority to regulate all facets of consumers' real estate transactions, some of which would be under the purview of the OAG. Joint Market Participants also stated that, while the commission has the authority to license and regulate certain specified telecommunications entities, it does not have jurisdiction over consumer issues like telephone solicitation, noting that the OAG instead has authority over issues like telemarketer fraud, deceptive trade practices, or violations of the Texas no-call list. OPUC and Joint Market Participants stated that, depending on the complaint, the customer may have to pursue a remedy from the commission, a different agency such as the OAG, or in district court. Joint Market Participants asserted that the OAG is in a better position to investigate complaints or conduct an enforcement action for contract disputes, and that the OAG is responsible for educating customers on the Deceptive Trade Practices Act. OPUC noted that the commission's website currently includes a list of entities which the commission does not regulate, referring affected customers to other resources to direct any particular complaints. Joint Market Participants argued that, to the extent that the consumer has a complaint about its contract with the DRGO, it may correctly assume that the appropriate regulatory body for consumer contract disputes is the OAG.

OPUC stated that the proposed amendments would further the objective of customer protection, as the end-use customer is not always the appropriate party to be responsible for many of the obligations imposed by the IA. Similarly, Joint Market Participants argued that allowing the end-use customer to have the option to have the DG provider sign the IA adds a level of accountability and scrutiny on such providers, because the utility and the commission will have the transparency of the DG provider, as well as the ability to enforce the safety of and technical compliance of the DG facility directly against the DG provider.

OPUC stated that, if the commission maintains the status quo, the only option will be for the end-use customer to accept all responsibility for operation and maintenance of DG, as well as the obligation to indemnify the utility company. Similarly, Joint Market Participants asserted that foregoing the increase in accountability and transparency because of separate concerns regarding customer protections could be a disservice to customers. OPUC argued that such a result would be contrary to the legislative intent in adopting PURA §39.101(b)(3), entitling customers to access to on-site DG, as well as PURA §39.916(k), which was established to remove obstacles to adoption of small-scale DRG.

Commission response

Under PURA, the commission generally regulates the conduct of the utility, not the conduct of various other types of entities with which a utility interacts in the course of fulfilling its obligations to provide electric utility service. Because the commission regulates the utility's conduct, an entity affected by that regulated conduct may file a complaint with the commission about that conduct. Conversely, a utility cannot file a complaint with the commission related to its provision of electric utility service, including a complaint against the Customer in the IA, although it may be able to request a commission order declaring its rights or making findings with respect to its conduct in its provision of electric utility service. In addition, jurisdiction cannot be conferred by agreement, through terms in the IA or otherwise. As a result, including a provision in the IA stating that a Customer is expressly submitting itself to regulation by the commission for the limited purpose of the IA would have no legal effect.

The commission's jurisdiction over a complaint filed by the Customer against the Company for a violation of the IA is not affected by what type of entity the Customer is. The Customer has standing to bring a complaint that the Company has not complied with the IA, regardless of whether the Customer is the end-use customer or an Option 2-4 entity. Similarly, an affected landowner has standing to bring a complaint to the commission that a utility did not comply with the commission's final order approving an amendment to a utility's certificate of convenience and necessity for the construction of a transmission line, regardless of whether the affected landowner receives electric utility service from the utility.

As described previously, a broad variety of DG arrangements could involve entities that must be certified or registered with the commission - REPs, PGCs, and QFs. Without addressing a particular issue in this rulemaking, the commission notes that it may have jurisdiction to resolve some disputes brought by an end-use customer related to DG where certified and registered entities are involved. For example, in a situation where the DG facility is owned by a PGC that sells the DG output to a REP that in turn sells the DG output to the end-use customer, the commission's customer protection rules would apply to the REP's sale of the output to the end-use customer. The commission's customer protection rules would not apply in arrangements exempted from commission regulation by PURA and in cases where a large end-use customer opts-out of the commission's customer protection rules. See, §25.471(a)(3) ("a customer other than a residential or small commercial class customer, or a non-residential customer whose load is part of an aggregation in excess of 50 kilowatts, may agree to terms of service that reflect either a higher or lower level of customer protections than would otherwise apply under these rules.")

PURA generally exempts arrangements involving small DRG facilities from the commission's jurisdiction, including the commission's customer protection rules. In particular, PURA §39.916(k) states: "Neither a retail electric customer that uses distributed renewable generation nor the owner of the distributed renewable generation that the retail electric customer uses is an electric utility, power generation company, or retail electric provider for the purposes of this title and neither is required to register with or be certified by the commission if at the time distributed renewable generation is installed, the estimated annual amount of electricity to be produced by the distributed renewable generation is less than or equal to the retail electric customer's estimated annual electricity consumption." This provision implies a legislative intent that the commission generally not regulate the relationship between the end-use customer and the DRG owner.

End-use customers who obtain power from DG covered by PURA §39.916(k) may incorrectly expect that the commission has jurisdiction to resolve disputes between the end-use customer and the DGO. If, for example, a homeowner is dissatisfied with a DRGO's conduct with respect to solar panels that the DRGO installed for the homeowner, the homeowner may incorrectly expect to be able to file a complaint with the commission. In order to help avoid such expectations, the commission has added language in the IA stating that the Customer and end-use customer acknowledge that agreements other than the IA that do not involve the Company may not be subject to the jurisdiction of the commission.

Merchant Generators, Distributed Generation Owners, and Distributed Renewable Generation Owners

TIEC commented that it supports amending the rule to clarify that merchant generators do not qualify as "end-use customers," as there has been an interpretation of the rules that has allowed merchants to access interconnection treatment intended for facilities serving a true end-use customer. TIEC stated that this interpretation raises concerns about reliability impacts, as the IA is not intended to accommodate large-scale merchant generators. TIEC argued that the correct interpretation of the DG rule is that it is limited to end-use retail customers that buy power for purposes unrelated to owning or operating a generating facility, and that §25.211 is intended to facilitate DG installation on the retail customer's home, business, or property. TIEC noted that the Order in Project Number 21220, which established §25.211 and §25.212, stated that smaller DG applications will be "used to serve residential and small commercial customers" and would provide "incentives for DG development for residential and small commercial customers." However, TIEC noted that this was a long-standing issue and that it understood the purpose of the instant proceeding to clarify the process for entities other than the end-use customer to sign the IA as the customer's agent. TIEC stated that the proposed amendments draw a distinction between the end-use customer and the Generator, defining those terms separately, and also adds language at the end of Section 7 to indicate that the end-use customer is a retail customer independent of DG facilities. TIEC stated that such language is an improvement and does not conflict with what it asserts is the appropriate interpretation of the DG rule.

In reply comments, TXU Energy stated that the published rule proposal essentially extends the statutory treatment of DRGOs to DGOs, without addressing a difference between a DGO and a DRGO. TXU Energy also noted that this potential extension of DRGO rights to DGOs is the driving source of TIEC's concerns in its comments regarding merchant generators. TXU Energy stated that, unless the commission explicitly decides to broadly extend to DGOs the benefits the statute reserves for the narrower DRGO subset, TXU Energy believes that separate IA forms would provide for a much clearer implementation process.

Commission response

With respect to TXU Energy's comments, the proposed amendments do not extend the statutory treatment of DRGOs to DGOs who are not also DRGOs. As the commission previously explains, PURA contains various provisions that authorize the commission to require a utility to enter into an IA with an owner or operator of DG facilities who need not be an end-use customer or a DRGO. With respect to TIEC's comments, the amendments in this rulemaking do not address whether merchant generators qualify as end-use customers.

Registration Requirements

NRG argued that the commission should ensure customer protection and operational reliability by requiring any non-end-use customer non-utility signatories to be registered REPs or another certified entity under the purview of the commission, such as PGCs, and proposed language to this effect. NRG stated that additional changes may be required to accomplish this recommendation, as REPs cannot own generation, but that the commission could require registration and certification of the third-party for the privilege of signing an IA on behalf of the customer. NRG argued that the end-use customer could still execute the IA, should the DG provider not wish to register as a REP or engage a REP in the DG service. In reply comments, Joint Utilities stated that it agreed with the concerns expressed by NRG, but that it believed the simplest resolution is to allow only the end-use customer to be the non-utility signatory to the IA. Joint Utilities asserted that NRG's proposal to require non-end-use customer entities to be certified as REPs had not been fully vetted, and that Joint Utilities were currently unable to support this proposal. In reply comments, Joint Market Participants argued that the commission already has inherent jurisdiction and authority over an IA executed using the form agreement in §25.211(p), given that the form agreement is part of the electric utility's tariff, in which parties submit to the commission's jurisdiction and authority. Joint Market Participants argued that PURA §39.916(k) expressly states that neither a retail electric customer that uses DRG or a DRGO is an electric utility, PGC, or REP and is not required to register or be certified by the commission if the estimated annual amount of electricity to be produced by the DRG is less than or equal to the retail electric customer's estimated annual electricity consumption. Joint Market Participants asserted that NRG's suggestion would expand the definition of a PGC to include a DRGO and effectively contradict the plain language of PURA, and also noted that REPs cannot own generation in Texas.

In comments in response to questions from the commission, NRG proposed that the execution of the IA be limited to either the end-use customer or the end-use customer's REP of record, which would ensure that the commission had the authority to ensure customer protection with respect to the non-end-use customer executing the IA with the utility. NRG noted that a REP must maintain managerial, financial, and technical requirements and capabilities, and must comply with customer protection rules. NRG also stated that the REP is responsible for the interface between the end-use customer and the utility, as well as ERCOT.

NRG stated that PURA §39.916(k) would prohibit the commission from requiring an end-use customer or a DRGO within the threshold to be certified or registered with the commission. NRG stated that limiting the non-utility signatory other than the end-use customer to a REP would not require an entity that qualified for the exemption in PURA §39.916(k) to register as a REP, and therefore would not violate PURA §39.916. NRG stated that this approach would still permit the DG owner to freely engage with the customer. NRG further stated that limiting the non-utility signatory other than an end-use customer to the REP would allow the end-use customer the option to give their REP the rights, responsibilities, and liabilities contained in the IA, while preserving commission oversight to ensure customer protection. NRG noted that, while REPs cannot own generation, contractual relationships can allow flexibility to engage in arrangements with distributed generation resources.

NRG asserted that the commission would not be prohibited from requiring a DG owner to be registered as a PGC, if they did not meet the exemption provision for certain DRG in PURA §39.916. Joint Utilities and Joint Market Participants stated that, if the exemption does not apply, either the REP or the DRGO might qualify as an electric utility, PGC, or a REP, and thus be subject to the commission's jurisdiction, certification, and registration requirements. In additional comments, OPUC noted that, to the extent that PURA §39.916(k) is limited to DRG, it does not limit the commission's broad jurisdiction related to DG. Joint Market Participants stated that the commission's jurisdiction would not extend to matters of contract dispute between a PGC and every party with whom it contracts. Joint Market Participants asserted that the commission would not be regulating the entity because it is a DRGO that entered into IA, but because the DRGO has taken affirmative steps to request from the commission designation as a REP, PGC, or electric utility.

Joint Market Participants asserted in reply comments that customer protection and operational reliability are ensured elsewhere in the IA, in requirements that the Customer operate the facilities in accordance with §25.211 and §25.212, which details the technical requirements for interconnection and establishes protection obligations for customers. Joint Market Participants argued that, in executing the IA, the DRGO subjects itself to those requirements. Joint Market Participants also argued that the DRGO is already required to ensure the safe and reliable operation of the DG, as Section 3 requires the Customer to ensure that the facilities meet the National Electric Safety Code, and to operate the DG facility to minimize any disturbance to the utility. Joint Market Participants averred that NRG's approach would restrict options for end-use customers, create a barrier to entry, and restrict business models for small-scale DG in Texas, as well as preclude a REP's affiliate from executing an IA.

Commission response

The commission declines to adopt NRG's proposal to require these Option 2-4 entities to be a REP or a PGC, or some other entity regulated by the commission, in order to be a party to the IA. First, REPs do not operate in the service areas of vertically integrated utilities, to which this rule applies in addition to TDUs. Second, the purpose of the IA is to ensure the reliable interconnection of DG to a utility's system, not to regulate the relationship between the end-use customer and other entities associated with the DG facility. In addition, PURA §39.916(k) states: "Neither a retail electric customer that uses distributed renewable generation nor the owner of the distributed renewable generation that the retail electric customer uses is an electric utility, power generation company, or retail electric provider for the purposes of this title and neither is required to register with or be certified by the commission if at the time distributed renewable generation is installed, the estimated annual amount of electricity to be produced by the distributed renewable generation is less than or equal to the retail electric customer's estimated annual electricity consumption." This provision implies that the legislature intended for the commission generally not to regulate the relationship between the end-use customer and the DRG owner in the circumstances described by the provision.

Comments Regarding Interconnection Agreement Language

NRG stated that, in the event that the commission determines not to permit a non-end-use customer to execute the IA, or determines to apply any limitations, that such new requirements be applied on a prospective basis only, so as not to affect existing IAs, and proposed language to this effect. In reply comments, Joint Utilities stated that it agreed with NRG's proposal, as attempting to modify existing or creating new IAs would be time-consuming and expensive, and proposed that such language be contained in §25.211(p), before or after the reference to the IA.

SolarCity also argued that the phrase "or Party" should be added after "Customer" in the preamble to the IA. In reply comments, Joint Utilities responded that, since the word "Party" also refers to the utility, such a change would be inappropriate, and the sentence could be read to mean that the term "Party" does not include the utility.

In addition, SolarCity proposed adding language stating that the Customer agrees to be bound by the IA and assumes the rights, obligations, and liabilities of the end-use customer under the IA, and proposed clarifying the role of the Option 2-4 signatory. SolarCity additionally proposed language releasing the end-use customer from all liabilities under the Agreement except those accrued prior to the execution of the IA. In replies, Joint Utilities opposed this language, asserting that, while the end-use customer should and will have very limited rights under an IA signed by a non-end-use customer, those rights that are provided to the end-use customer and not to the third-party must stay with the end-use customer. Joint Utilities also stated that no purpose is served by including language stating that the Customer will be bound by the IA, as proposed by SolarCity, as the Customer will naturally be bound to the IA as a signatory party. Conversely, Joint Utilities proposed adding language to the end of the affirmation indicating that the end-use customer agrees to be bound by the IA, including limitation of liability provisions. In replies, Joint Market Participants argued that Joint Utilities' proposal should be rejected, as it was contrary to the concept of exempting the end-use customer from liability by shifting the burden to the third-party signatory.

OPUC commented that the IA does not indicate which person or entity should fill in the "Customer" blank in the first paragraph, and proposed that language be added indicating that the customer blank be filled in with the name of the person or entity selected in Options 1-4.

OPUC also proposed defining the term "end-use customer," proposing to define it as the "retail customer who purchases electric services from the Company for the premises at which the Facilities will be located." In reply comments, Joint Utilities objected to the specificity of OPUC's proposed definition, arguing that, in competitive areas, the end-use customer purchases services from the REP, not the TDU. Joint Utilities proposed instead to adopt the definition of "Customer" from §25.211(c)(3), which states that a customer is an "any entity interconnected to the company's utility system for the purpose of receiving or exporting electric power from or to the Company's utility system," and adding a minor clarification that the entity be directly connected to the utility's system. In addition, Joint Utilities proposed adding a parenthetical to refer to the end-use customer as "the person or entity that pays for the provision of retail electric service."

In reply comments, the Joint Market Participants stated the term "customer" in PURA is undefined, and the Legislature may have intended its meaning to be broader than only the end-use customer. Joint Market Participants stated that the SGIA defines an "interconnection customer" as "any entity … that proposes to interconnect its Small Generating Facility with the Transmission Provider's Transmission System." Joint Market Participants argued that the broad reference to "any entity" is similar to the definition of "customer" in the commission's rule, and suggests that other markets are open to allowing third-parties to execute an IA. Joint Market Participants also asserted that "customer" is broadly defined in §25.211(c)(3) and appears to include a DRGO within its scope, as the definition under PURA §39.916(a)(2) meets the requirements of "any entity interconnected to the company's utility system".

Commission response

With respect to NRG's proposal that language be added to make the IA prospective, the commission declines to adopt this proposal. Both the existing IA and the IA as amended in this project address the applicability of commission-mandated changes to the IA by providing that the Company may terminate an existing IA in the event that there is a material change in an applicable rule or statute that necessitates termination of the IA. Therefore, each utility will need to evaluate its existing IAs and determine whether it should exercise this right. The commission also declines to adopt SolarCity's proposed modification to add the phrase "or Party" after "Customer", for the reasons asserted by Joint Utilities.

The commission declines to adopt the differing proposals of SolarCity and Joint Utilities addressing the respective rights and obligations of the non-utility entity signatory and the end-use customer. The IA as proposed contains various provisions concerning the relationships among the Company, Customer, and end-use customer, and the commission does not have sufficient information to conclude that the adoption of either proposal would be in the public interest. Some of the relevant IA provisions that the commission is adopting include Section 4(a), which indicates that the Company's provision of electric service to the end-use customer other than the interconnections service addressed by the IA is limited as set forth in Company's non-DG tariff provisions. In addition, the end-use customer must either sign the IA as the non-utility Party to the IA or sign the IA in order to authorize the Option 2-4 entity to be the non-utility Party to the IA.

The commission adopts OPUC's proposal to modify the first paragraph of the IA to clarify which entity should be listed as the Customer in the first paragraph of the IA. The proposed IA includes a provision after the listing of options that addresses this issue by stating that Customer refers to the non-utility selected to sign the IA. However, this provision appears after the first paragraph, where the name of the Customer must be inserted.

The commission declines to adopt OPUC's proposed definition of end-use customer, because the term itself is sufficiently clear for purposes of the IA and defining such the term would risk unintended consequences.

Section 3 - Responsibilities of Company and Customer

SolarCity commented that the IA should have additional assignability language, asserting that such language found general support from participants at an October 2015 workshop on this project. Similarly, SEIA proposed requiring a deadline by which the Company must accept a change of parties to the IA. SolarCity asserted that many state DG interconnection regulations are based on the Small Generation Interconnection Procedures and its standard form companion document, the Small Generator Interconnection Agreement (SGIA), which have been adopted by the Federal Energy Regulatory Commission (FERC), and includes assignability language similar to that proposed by SolarCity in its comments. SolarCity argued that allowing such assignability would aid financing, and that it proposed language to notify the Company after assignment has occurred in such cases, allowing the utility to appropriately track its Customer. SolarCity averred that there is no persuasive argument as to why the IA should not be assignable, as it is a fundamental cornerstone of the market-standard SGIA, as well as large-scale generation in Texas, and should not be withheld from small-scale generators.

In reply comments, Joint Utilities stated that they believed assignment issues were deliberately excluded by the commission in the published proposal, and that adopting such language at this time could raise notice issues. Joint Utilities argued that the SGIA language is for interconnection at transmission, not distribution-level. Joint Utilities also argued that the SGIA requires the Customer and any assignees to meet certain financial and insurance requirements that do not apply to DG customers signing an IA in Texas. In addition, Joint Utilities asserted that the assignment language proposed by SolarCity is not identical to that found in the SGIA, and contains some modifications to the SGIA language. Joint Utilities also expressed concern that the assignee may be a type of entity that does not fall within the options presented in the IA, and that SolarCity's assignment language could possibly introduce a non-domestic financing entity to the IA as an assignee, where commission jurisdiction may not be clear. Joint Utilities argued that the commission should not require utilities to enter into contracts with foreign entities.

Joint Utilities expressed concern about the proposed amendments which require the Customer to notify the Company of any circumstances necessitating a change of Parties to the IA. Joint Utilities argued that it is unclear what circumstances would necessitate a change of Parties, and that it is unclear whether such a change would require amendment to the IA, and whether the end-use customer would need to consent to that amendment or enter into a new IA.

In addition, SolarCity proposed adding language that if 14 days' written notice of a change in parties is not feasible, the Customer shall provide the notice to the Company as soon as practicable prior to such change in ownership, cessation of operations, or change of parties to the IA, asserting that the proposed amendments would not account for an emergency where the Customer would be unable to alert the company in such a timeframe. Joint Utilities responded that it agreed with SolarCity that a cessation in operations by the Customer could occur in an emergency without 14 days' prior notice being feasible. Joint Utilities argued, however, that a 14-day prior notice of a change in Parties should be feasible for the Customer. Joint Utilities proposed revised language to provide that, in the event of an emergency cessation of operations, the Customer shall provide notice as soon as possible.

Joint Utilities asserted that modifications should be made to recognize that Option 3 and Option 4 signatories do not own any of the DG facilities, and thus the phrase "its facilities" is inappropriate, and proposed revised language.

Commission response

The IA should be written in a manner that provides for a reasonably expeditious process to accommodate changes in circumstances, including a change in the Customer to the IA. The existing IA requires the Customer to provide the Company at least 14 days' written notice of a change of ownership or cessation of operation of one or more Facilities. The commission's proposed amendments to the IA included adding a requirement that the Customer provide the Company at least 14 days' written notice of any circumstances necessitating a change of Parties to the IA. In addition, the existing IA provides that the Customer may terminate the IA at any time by giving Company sixty days' written notice. The commission adopts a provision that, upon notice by Customer of circumstances necessitating a change in the person who is the Customer to this Agreement, Company shall undertake in a reasonably expeditious manner entry of a new IA with the change in person who is the Customer.

The commission adopts Joint Utilities' proposal to clarify the language concerning "its facilities."

The commission declines to adopt SolarCity's and Joint Utilities' proposal that, in the event of an emergency cessation of operations in which 14 days' written notice is not feasible, the Customer shall provide notice to the Company as soon as possible of such cessation of operations. This rulemaking was initiated to address issues related to which types of entities should be allowed to be the non-utility signatory to the IA. This proposal is unnecessary and goes beyond the purpose of this rulemaking.

Section 4 - Limitation of Liability and Indemnification

Section 4(b)

SolarCity proposed that there be more clarity in these indemnification provisions of Section 4(b), arguing that parties should not be indemnified for acts attributable to their own negligence or misconduct. SolarCity argued that the intent of Section 4(b) appears to be aimed at force majeure events, and thus actions caused by negligence should be expressly excluded.

Joint Utilities replied that no modifications to this section were necessary, and that it is appropriate for the Customer to be liable should a breakdown in the Customer's DG facility cause damage to the utility's equipment. Joint Utilities opposed SolarCity's proposed change to add the phrase "in accordance with applicable law," arguing that the proposed change appears to make it the responsibility of the party to determine if an order or restriction imposed by a governing body is in fact "in accordance with applicable law." Joint Utilities argued that, if it receives an order from a governing body, it will likely always comply, and it should not be at risk for liability for damages.

SolarCity proposed to add language to state that repairs shall be made to minimize the disruption of the Customer's electric service. Joint Utilities asserted that such a provision was unacceptable; in an emergency, it stated utilities will respond and make repairs based on the needs of the system as a whole. Joint Utilities stated that, given thousands of DG customers, such a provision would result in the utility prioritizing repairs to feeders or equipment serving DG first over the integrity the system as a whole. Joint Utilities also argued that it would be difficult to prioritize among the DG facilities themselves to "minimize disruption of electric service," as proposed by SolarCity.

SolarCity also proposed removing "curtailment" from the indemnification provisions, stating that it does not seem to fit with items of force majeure. In reply comments, Joint Utilities asserted that any curtailment ordered by a regulatory authority should not expose that party to be liable to the other party, arguing that if a utility is ordered to curtail the DG facility, it must do so, and should not be liable to the Customer for doing so.

Commission response

The commission is persuaded by the arguments of Joint Utilities and declines to adopt SolarCity's proposed changes.

Sections 4(c) and 4(d)

In initial comments, the Joint Utilities suggested that the initial lines of Section 4(d) be modified to clarify that all non-federal agency customers, including state agencies and other political subdivisions, fall within the definition of what is currently labeled as a "private entity," and proposed adding a sentence to this effect.

SolarCity proposed that Sections 4(c) and 4(d), which address private entities and federal agencies respectively, be combined to make the treatment of private entities and federal agencies reciprocal. SolarCity stated that the current indemnification language in the proposed amendments appears to be reciprocal, and that Sections 4(c) and 4(d) should be combined, and the provisions in Section 4(d) that distinguish between private entities and federal agencies should be deleted.

In reply comments, Joint Utilities disagreed with SolarCity's proposed modifications. Joint Utilities asserted that the portion of Section 4(d) applicable to federal entities, which SolarCity proposed to delete, was originally added because the federal Department of Veterans' Affairs refused to sign an IA with Oncor if any language applicable to private entities was included, even if such language was expressly made subject to explicitly listed superseding federal provisions. Joint Utilities stated that the commission approved of the good-cause exception by Oncor and the Department of Veterans' Affairs with the agreed-upon language, and soon thereafter modified Section 4(d) in Project Number 41325 to provide for the current private entities and federal agencies provisions. Joint Utilities stated that there was no reason to revert back to language that was found unacceptable by a federal agency when the current provision has worked for all IAs signed by federal agencies since its inception.

Commission response

The commission is persuaded by the comments of Joint Utilities that the existing, separate provision for federal agencies should be retained. The commission also agrees with Joint Utilities that the "private entity" provision needs to be clarified to apply to persons other than federal agencies, and has clarified the provision to that effect to specifically apply to a state or local entity to the extent permitted by the constitution and laws of the State of Texas.

Section 4(f)

SolarCity proposed language requiring the Company not to unreasonably withhold prior authorization of energizing the connections between the Company and the Customer. In replies, Joint Utilities stated that it did not oppose SolarCity's proposed change to this provision.

Commission response

The commission declines to make the changes proposed by SolarCity, because the Company is required to act reasonably with respect to energizing the connections, without express language to that effect.

Section 5 - Rights of Access, Equipment Installation, Removal & Inspection

SolarCity asserted that the current language permits broad access for the utility to inspect the interconnection and observe the facility upon initial startup, with reasonable notice of a to-be-determined time frame. SolarCity proposed modifications requiring a 72-hour prior written notice for the utility to witness the startup of the DG facilities, during normal business hours. Similarly, OPUC also recommended more fully defining the phrase "upon reasonable notice," suggesting that notice be provided at least 48 hours in advance unless there is an emergency related to the Facilities. In reply comments, Joint Utilities asserted that it objected to any explicit minimum notice period, particularly one the Customer cannot waive, and that no reason existed to require such notice. Joint Utilities also asserted that §25.212(h) provides that the "utility may witness the testing of any equipment and protective systems associated with the interconnection," with no prior written notice requirement. Joint Utilities asserted that 72-hour prior written notice was unnecessarily restrictive, and that the end-use customer might agree to the Company accessing the premises sooner, including after business hours when they can be present for Company access, which would be prohibited by the proposed language. Joint Utilities stated that allowing access after "reasonable notice" and at "reasonable hours" was sufficient and reasonable.

SolarCity also proposed to only allow the utility unnoticed access in the event of an immediate threat to person or property, or a hazardous condition. Similarly, OPUC stated that the IA is an agreement related to the DG facilities, and thus the Company's access should be limited to circumstances related to the Facilities, and also proposed clarifications to what constitutes an emergency or hazardous condition. SolarCity also proposed in its initial comments only permitting the Company access solely for the purpose of performing its obligations under the IA or meeting legal obligations to serve its customers. In reply comments, Joint Utilities asserted that such qualifiers as proposed by SolarCity and OPUC were unreasonable, questioning which events would constitute an "immediate threat." Joint Utilities stated that, in the case of a system emergency or when the premises are on fire, it may be necessary to disconnect the DG facility from the grid so that work can be safely done, but this would likely not meet the standard of an "immediate threat" or be related specifically to the "facilities." Joint Utilities also argued that limiting access only to when the Company is performing its "obligations" is too restrictive. Joint Utilities stated that it is the Customer that has the obligation to meet all of the requirements, and the Company's efforts to ensure that the Customer is meeting the requirements might not meet the standard of an "obligation." Joint Utilities also stated that an end-use customer that installs a DG facility that is interconnected to the utility's grid must anticipate that the utility may need to disconnect the DG facility on rare occasions, and that such access would not impair the end-use customer's expected privacy rights. Joint Utilities stated that it was unaware of any complaints or problems with regards to unreasonable access which would necessitate such language.

OPUC also proposed that language be added to require the utility to use its best efforts to coordinate with the Customer and the end-use customer to schedule reasonable access to the Facilities. In reply comments, Joint Utilities stated that coordinating with two entities is difficult, and recommended rejecting OPUC's proposal to require that the utility coordinate with more than one entity.

OPUC proposed language to address obtaining the necessary approvals for access when the Customer is not the end-use customer. Joint Utilities stated in reply comments that it believed OPUC's proposed language would act contrary to OPUC's intention, and would be operative only if the Customer is the entity who owns the output of the DG facility. Joint Utilities proposed modified language that would permit access irrespective of the type of entity the Customer may be.

OPUC and Joint Utilities proposed changes to reflect that the DG facilities may not be located at the Customer's premises.

Commission response

This rulemaking was initiated to address issues related to which types of entities should be allowed to be the non-utility signatory to the IA. Some of the proposed changes do not address such issues and the commission is not persuaded that the changes should be made.

With respect to OPUC's proposal that the Company be required to coordinate with the end-use customer as well as the Customer, the commission agrees with the comments of Joint Utilities that such a requirement is too burdensome. In addition, the end-use customer and the Option 2-4 entity may agree to coordination procedures between themselves.

In response to OPUC's and Joint Utilities' comments, the commission adopts amendments to the IA to reflect that the DG facilities may not be at the Customer's premises, and that the Customer warrants that it has obtained the necessary rights to provide the Company with access to the premises and Facilities for purposes of exercising its rights under the IA.

Section 6 - Disconnection of Facilities

SolarCity suggested language to waive the Customer's requirement to provide 30 days' notice to the Company of disconnection in the event of an emergency situation. Joint Utilities stated it did not object to this proposed language.

SolarCity also proposed to change the conditions under which the Company may disconnect service by including language allowing the Company to suspend service only in situations of imminent danger to the Customer. In reply comments, Joint Utilities argued that the original language mirrors §25.211(e)(3), and SolarCity's proposed language would make the IA inconsistent with the rule language, and therefore should not be adopted.

SolarCity proposed requiring the Company to take all steps necessary to mitigate the impact of the suspension of service on the Customer. Joint Utilities replied that such language is not found in §25.211(e)(3) and would result in an IA inconsistent with the rule. Joint Utilities argued that utilities should be able to respond to system emergencies without a requirement that they prioritize reconnecting premises with a DG facility over other premises without a DG facility, which could result in impermissible discrimination under PURA §38.021.

SolarCity also proposed language that would prohibit the Company from suspending service to the DG facility for economic reasons. In replies, Joint Utilities asserted that such a prohibition is premature at this time, as ERCOT is currently examining Distributed Energy Resources (DER) in its stakeholder process. Joint Utilities argued that if DG is ultimately allowed to participate in generation markets, it should be made subject to dispatch by ERCOT or the utility, in which case "disconnection" of the DG facility may not only be permissible, but also sometimes mandatory. Joint Utilities recommended that the commission not address this matter at this time; should the commission include SolarCity's proposed change, Joint Utilities argued that the commission should clarify that it does not apply to instances when the utility disconnects the end-use customer due to non-payment.

OPUC stated that the IA should require the Option 2-4 Customer to provide prior notice of disconnection to the end-use customer at the same time that it notifies the utility, so that the end-use customer is aware of possible disconnection in advance. In addition, OPUC proposed language requiring that the Company exercise its best efforts to provide the Customer with a reasonable prior notice before suspending service due to a forced outage. Joint Utilities stated in reply comments that it disagreed with this proposal, arguing that, if the end-use customer has chosen not to be a party to the IA, then the task of providing reasonable notice should fall to the Customer and not the Company. OPUC also proposed that, in situations where the Customer is not the end-use customer, the Customer should also be required to use best its efforts to provide notice to the end-use customer as well of possible disconnection. Joint Utilities stated in replies that it does not disagree with OPUC's suggestion, and noted that it expands the IA to encompass rights and obligations between the end-use customer and the Option 2-4 Customer, rather than having those relationships be contained in contracts between those two entities. Joint Utilities also questioned how the commission would enforce such obligations between the Customer and end-use customer.

TXU Energy argued that the enforcement of the IA should not trump the REP's right to disconnect the end-use customer for non-payment, and proposed adding language stating that the Company shall have the right to suspend service at the request of the end-use customer's REP. TXU Energy also urged the commission to make clear in its preamble that the DGO may not file a complaint against the REP for pursuing its right to request disconnection for non-payment pursuant to §25.483, arguing that it would upset the REP-customer relationship to allow a DGO to interfere with the REP service agreement.

Commission response

This rulemaking was initiated to address issues related to which types of entities are an appropriate non-utility signatory to the IA. Some of the proposed changes do not address such issues and the commission is not persuaded that the changes should be made.

With respect to OPUC's proposal that the IA require that an Option 2-4 Customer notify the end-use customer of possible disconnection, the commission notes that the IA is an agreement between the Customer and the Company and does not address the unregulated interactions between the end-use customer and the Option 2-4 Customer, who may agree to notification procedures between themselves. With respect to OPUC's language to require that the Company make its best efforts to contact not only the Customer but also the end-use customer if the Customer is not the end-use customer, the commission declines to make such a change, again because private contractual arrangements between the end-use customer and the Option 2-4 Customer can address such issues.

Section 7 - Effective Term and Termination Rights

Joint Utilities and TXU Energy expressed concern with the proposed amendments allowing the IA to remain in effect even if the end-use customer terminates the relationship with the utility. TXU Energy argued that such language incorrectly associates retail electric service with the utility. Joint Utilities and TXU Energy argued that the ramifications of the proposal were unclear, suggesting that there may not be a new end-use customer if the premises are unoccupied, and the IA would continue to remain in effect. TXU Energy noted that all customers in the competitive areas of ERCOT must have a REP in order to receive electric service, and recommended adding language that the Customer understands and agrees that the interconnection of the Facilities is conditioned upon the provision of retail electric service at the premises containing the point of common coupling, and that the DG facility will not be interconnected with the utility's facilities if no electric service is being provided at the premises.

Joint Utilities stated that it was unclear as to whether the new end-use customer would need to sign the same affirmation in the Agreement that the original end-use customer signed, or enter into a new IA. Joint Utilities suggested that the affirmation by the end-use customer be moved into the Facilities Schedule at the end of the IA, which would allow the affirmation to be updated with the new end-use customer more easily, allow a non-end-use customer to sign a single IA, and permit the IA to cover multiple premises. Joint Utilities stated that, in the event that the commission declined to move the affirmation to the Facilities Schedule, the language should make clear that the IA is terminated when the end-use customer moves out, and a new IA must be executed when the new end-use customer moves in. Joint Utilities asserted that the right to interconnect resides with the end-use customer, which should always maintain the right to determine whether it will allow the DG facility to be interconnected to its facilities.

Joint Market Participants stated that it agreed with the proposed amendments stating that the IA shall continue even if the end-use customer who is not the Customer terminates its electric service. Joint Market Participants argued that this approach reduces the administrative burden in transferring the IA to a new end-use customer. Joint Market Participants asserted that it disagreed with Joint Utilities' proposal that a new IA be executed, but agreed that an affirmation by the new end-use customer must be executed. Joint Market Participants suggested that the affirmation portion of the IA simply be relocated as an attachment, allowing any subsequent affirmation to replace the former end-use customer's affirmation or be appended as a superseding affirmation. Joint Market Participants agreed with Joint Utilities that, if the new end-use customer refuses to sign the affirmation, then the IA will terminate, because without the end-use customer's agreement, the contractual arrangement cannot continue.

In initial comments, SolarCity proposed that, in a situation where the Customer has not begun producing electricity within 12 months after the completion of the interconnection with the utility, the utility must give the customer at least 30 days' notice that it intends to terminate the IA or the utility will permanently waive the ability to terminate the IA for non-production. In reply comments, Joint Utilities argued that this proposal should be rejected, stating that changes in the utility's system often occur irrespective of the production status of the DG facility, which might warrant another study to evaluate the interconnection of the DG facility. Joint Utilities stated that it was reasonable to allow the utility, at its discretion, to terminate the IA and require that the Customer apply again for interconnection. Joint Utilities asserted that the mandatory provision to either "terminate or waive" as proposed by SolarCity would incent the utility to terminate the IA rather than work with the customer.

Commission response

The commission agrees with Joint Utilities and Joint Market Participants to move the provision for the end-use customer's affirmation to a new schedule so that it can be appended to the IA, while retaining the selection of the Customer at the beginning of the IA. This change may greatly facilitate the process of updating an IA when the end-use customer associated with a DG facility changes. As stated by Joint Utilities, a DG owner with numerous DG facilities associated with numerous end-use customers will be able to sign one IA for each utility and an end-use customer affirmation schedule can be replaced when the end-use customer associated with a particular DG facility changes, recognizing that the new end-use customer must consent to the Option 2-4 Customer continuing to be the non-utility Party to the IA in order for the IA to continue to remain in effect for that particular DG facility. The end-use customer affirmation schedule adopted by the commission also avoids the need for new end-use customer affirmation schedules to be signed in the event the DG facilities to which the IA applies are sold to another entity pursuant to the contracts between the original DG owner and the end-use customers and the acquiring entity signs a new IA. As a result, the commission removes the proposed amendment that suggests the IA continues after termination of retail electric service to the premises at which the DG facility is located.

The commission is persuaded by the comments of Joint Utilities and declines to adopt a mandatory "terminate or waive" provision in the IA as proposed by SolarCity.

Section 8 - Governing Law and Regulatory Authority

SolarCity proposed combining the language addressing liability for the Company as a federal agency or private entity. SolarCity asserted it was unnecessary to have separate liability sections for private entities and federal agencies. Joint Utilities stated that it opposed these changes for the reasons it stated in response to SolarCity's comments on Section 4(d), that the current approach is in place in response to negotiations with a federal agency, and there is no reason to make this change.

Commission response

Based on the arguments and concerns raised by Joint Utilities in response to SolarCity's parallel proposed modifications to Section 4(d) with respect to combining language for private entities and federal agencies, the commission declines to adopt SolarCity's proposed modifications to this section, and also changes "Private Entity" to "Person Other Than a Federal Agency."

Section 9 - Amendment

OPUC proposed requiring the Company to ensure that the end-use customer is aware of any amendments to the IA. In reply comments, Joint Utilities disagreed with this suggestion, stating that obligations and rights belong to the entity that the end-use customer has chosen as a party to the IA, and if the end-use customer desires to obtain copies of any amendments to the IA, that responsibility should fall with the Customer and not the Company.

Commission response

The commission agrees with the comments of Joint Utilities. As discussed previously, the commission does not intend to use this IA to govern the contractual and private relationship between an Option 2-4 Customer and the end-use customer. The commission declines to adopt OPUC's proposed changes for the reasons asserted by Joint Utilities.

Section 11 - Written Notices

SolarCity proposed changes to further address the delivery of notice. In reply comments, Joint Utilities stated that they did not oppose the changes.

Commission response

The commission declines to adopt the changes to Section 11 proposed by SolarCity because they are unclear.

Facility Schedule

OPUC noted that the Facility Schedule currently includes sections for providing the Customer name and the Premises Owner name, and recommended that the Facility Schedule be revised to include the end-use customer name as well, given the proposed changes to distinguish between the Customer and the end-use customer. In reply comments, Joint Utilities asserted that its proposal to include the end-use customer's agreement to designate an Option 2-4 entity as a Customer on its behalf in the Facilities Schedule would accomplish OPUC's goal.

Commission response

The commission agrees with the comments of Joint Utilities and therefore makes no further changes to the IA.

The amendment is adopted under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002 (West 2007 and Supp. 2016) (PURA), which provides the Public Utility Commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; and specifically, §14.001, which provides the commission with the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §31.002 (20), which defines transmission service to include transmission over distribution facilities; §32.101, which requires an electric utility to file its tariff with each regulatory authority; §35.004(b), which requires the commission to ensure that an electric utility or transmission and distribution utility provides nondiscriminatory access to wholesale transmission service for qualifying facilities, exempt wholesale generators, power marketers, power generation companies, retail electric providers, and other electric utilities and transmission and distribution utilities; §36.003, which requires that each rate be just and reasonable and not unreasonably preferential, prejudicial, or discriminatory; §38.001, which requires an electric utility to furnish service, instrumentalities, and facilities that are safe, adequate, efficient, and reasonable; §39.101(b)(3), which requires the commission to ensure that customers have access to on-site distributed generation and to providers of energy generation by renewable energy resources; §39.554, which addresses the interconnection of distributed renewable generation with an electric utility subject to PURA Chapter 39, Subchapter L; and §39.916, which addresses the interconnection of distributed renewable generation.

Cross reference to statute: Public Utility Regulatory Act §§14.001, 14.002, 31.002, 32.101, 35.004, 36.003, 38.001, 39.101, 39.554, and 39.916.

§25.211.Interconnection of On-Site Distributed Generation (DG).

(a) Application. Unless the context indicates otherwise, this section and §25.212 of this title (relating to Technical Requirements for Interconnection and Parallel Operation of On-Site Distributed Generation) apply to an electric utility for all purposes except to the extent preempted by federal law. The only part of this section that applies to electric cooperatives is subsection (o) of this section.

(b) Purpose. The purpose of this section includes stating the terms and conditions that govern the interconnection and parallel operation of both on-site distributed generation in order to implement Public Utility Regulatory Act (PURA) §39.101(b)(3) and a natural gas distributed generation facility in order to implement PURA §35.036. Sales of power by on-site distributed generation and natural gas distributed generation in the intrastate wholesale market are subject to §§25.191-25.203 of this title (relating to Open-Access Comparable Transmission Service for Electrical Utilities in the Electric Reliability Council of Texas).

(c) Definitions. The following words and terms when used in this section and §25.212 of this title shall have the following meanings, unless the context indicates otherwise:

(1) Application for interconnection and parallel operation or application--The form of application prescribed in subsection (q) of this section.

(2) Company--An electric utility operating a distribution system.

(3) Customer--Any entity interconnected to the company's utility system for the purpose of receiving or exporting electric power from or to the company's utility system.

(4) Distributed natural gas generation facility--A facility installed on the customer's side of the meter that uses natural gas to generate not more than 2,000 kilowatts of electricity.

(5) Facility--An electrical generating installation consisting of one or more on-site distributed generation units, including a distributed natural gas generation facility. The total capacity of the installation's on-site distributed generation units may exceed ten megawatts (MW); however, no more than ten MW of the installation's capacity will be interconnected at any point in time at the point of common coupling under this section.

(6) Interconnection--The physical connection of distributed generation to the utility system in accordance with the requirements of this section so that parallel operation can occur.

(7) Interconnection agreement--The form of agreement prescribed in subsection (p) of this section. The interconnection agreement sets forth the contractual conditions under which a company and a customer agree that one or more facilities may be interconnected with the company's utility system.

(8) Inverter-based protective function--A function of an inverter system, carried out using hardware and software, that is designed to prevent unsafe operating conditions from occurring before, during, and after the interconnection of an inverter-based static power converter unit with a utility system. For purposes of this definition, unsafe operating conditions are conditions that, if left uncorrected, would result in harm to personnel, damage to equipment, unacceptable system instability or operation outside legally established parameters affecting the quality of service to other customers connected to the utility system.

(9) Network service--Network service consists of two or more utility primary distribution feeder sources electrically tied together on the secondary (or low voltage) side to form one power source for one or more customers. The service is designed to maintain service to the customers even after the loss of one of these primary distribution feeder sources.

(10) On-site distributed generation (or distributed generation)--An electrical generating facility located at a customer's point of delivery (point of common coupling) of ten megawatts (MW) or less and connected at a voltage less than 60 kilovolts (kV) which may be connected in parallel operation to the utility system.

(11) Parallel operation--The operation of on-site distributed generation while the customer is connected to the company's utility system.

(12) Point of common coupling--The point where the electrical conductors of the company utility system are connected to the customer's conductors and where any transfer of electric power between the customer and the utility system takes place, such as switchgear near the meter.

(13) Pre-certified equipment--A specific generating and protective equipment system or systems that have been certified as meeting the applicable parts of this section relating to safety and reliability by an entity approved by the commission.

(14) Pre-interconnection study--A study or studies that may be undertaken by a company in response to its receipt of a completed application for interconnection and parallel operation with the utility system. Pre-interconnection studies may include, but are not limited to, service studies, coordination studies and utility system impact studies.

(15) Stabilized--A company utility system is considered stabilized when, following a disturbance, the system returns to the normal range of voltage and frequency for a duration of two minutes or a shorter time as mutually agreed to by the company and customer.

(16) Tariff for interconnection and parallel operation of distributed generation--The tariff for interconnection and parallel operation of distributed generation prescribed in subsection (q) of this section.

(17) Unit--A power generator.

(18) Utility system--A company's distribution system below 60 kV to which the generation equipment is interconnected.

(d) Terms of Service.

(1) Distribution line charge. No distribution line charge shall be assessed to a customer for exporting energy to the utility system.

(2) Interconnection operations and maintenance costs. No charge for operation and maintenance of a utility system's facilities shall be assessed against a customer for exporting energy to the utility system.

(3) Transmission charges. No transmission charges shall be assessed to a customer for exporting energy. For purposes of this paragraph, the term transmission charges means transmission access and line charges, transformation charges, and transmission line loss charges.

(4) New or amended interconnection agreements. A new or amended interconnection agreement entered into 30 or more days after the commission's approval of an electric utility's compliance tariff filed pursuant to paragraph (5) of this subsection shall meet the requirements of this section.

(5) Tariffs. Not later than 30 days after the effective date of this amended section, an electric utility shall file with the commission for approval tariff amendments to comply with this amended section, including subsections (p) and (q) of this section. An electric utility shall include in its tariff the fees for interconnection studies. An electric utility that sells electricity shall also include back-up, supplemental, and maintenance power services for distributed generation in its tariff.

(e) Disconnection and reconnection. A utility may disconnect a distributed generation unit from the utility system under the following conditions:

(1) Expiration or termination of interconnection agreement. The interconnection agreement specifies the effective term and termination rights of company and customer. Upon expiration or termination of the interconnection agreement with a customer, in accordance with the terms of the agreement, the utility may disconnect customer's facilities.

(2) Non-compliance with the technical requirements specified in §25.212 of this title. A utility may disconnect a distributed generation facility if the facility is not in compliance with the technical requirements specified in §25.212 of this title. Within two business days from the time the customer notifies the utility that the facility has been restored to compliance with the technical requirements of §25.212 of this title, the utility shall have an inspector verify such compliance. Upon such verification, the customer in coordination with the utility may reconnect the facility.

(3) System emergency. A utility may temporarily disconnect a customer's facility without prior written notice in cases where continued interconnection will endanger persons or property. During the forced outage of a utility system, the utility shall have the right to temporarily disconnect a customer's facility to make immediate repairs on the utility's system. When possible, the utility shall provide the customer with reasonable notice and reconnect the customer as quickly as reasonably practical.

(4) Routine maintenance, repairs, and modifications. A utility may disconnect a customer or a customer's facility with seven business days prior written notice of a service interruption for routine maintenance, repairs, and utility system modifications. The utility shall reconnect the customer as quickly as reasonably possible following any such service interruption.

(5) Lack of approved application and interconnection agreement. In order to interconnect distributed generation to a utility system, a customer must first submit to the utility an application for interconnection and parallel operation with the utility system and execute an interconnection agreement on the forms prescribed by the commission. The utility may refuse to connect or may disconnect the customer's facility if such application has not been received and approved.

(f) Incremental demand charges. During the term of an interconnection agreement a utility may require that a customer disconnect its distributed generation unit and/or take it off-line as a result of utility system conditions described in subsection (e)(3) and (4) of this section. Incremental demand charges arising from disconnecting the distributed generator as directed by company during such periods shall not be assessed by company to the customer.

(g) Pre-interconnection studies for non-network interconnection of distributed generation. A utility may conduct a service study, coordination study or utility system impact study prior to interconnection of a distributed generation facility. In instances where such studies are deemed necessary, the scope of such studies shall be based on the characteristics of the particular distributed generation facility to be interconnected and the utility's system at the specific proposed location. By agreement between the utility and its customer, studies related to interconnection of on-site distributed generation on the customer's premises may be conducted by a qualified third party.

(1) Distributed generation facilities for which no pre-interconnection study fees may be charged. A utility may not charge a customer a fee to conduct a pre-interconnection study for pre-certified distributed generation units up to 500 kW that export not more than 15% of the total load on a single radial feeder and contribute not more than 25% of the maximum potential short circuit current on a single radial feeder.

(2) Distributed generation facilities for which pre-interconnection study fees may be charged. Prior to the interconnection of a distributed generation facility not described in paragraph (1) of this subsection, a utility may charge a customer a fee to offset its costs incurred in the conduct of a pre-interconnection study. In those instances where a utility conducts an interconnection study the following shall apply:

(A) The conduct of such pre-interconnection study shall take no more than four weeks;

(B) A utility shall prepare written reports of the study findings and make them available to the customer;

(C) The study shall consider both the costs incurred and the benefits realized as a result of the interconnection of distributed generation to the company's utility system; and

(D) The customer shall receive an estimate of the study cost before the utility initiates the study.

(h) Network interconnection of distributed generation. Certain aspects of secondary network systems create technical difficulties that may make interconnection more costly to implement. In instances where customers request interconnection to a secondary network system, the utility and the customer shall use best reasonable efforts to complete the interconnection and the utility shall utilize the following guidelines:

(1) A utility shall approve applications for distributed generation facilities that use inverter-based protective functions unless total distributed generation (including the new facility) on affected feeders represents more than 25% of the total load of the secondary network under consideration.

(2) A utility shall approve applications for other on-site generation facilities whose total generation is less than the local customer's load unless total distributed generation (including the new facility) on affected feeders represents more than 25% of the total load of the secondary network under consideration.

(3) A utility may postpone processing an application for an individual distributed generation facility under this section if the total existing distributed generation on the targeted feeder represents more than 25% of the total load of the secondary network under consideration. If that is the case, the utility should conduct interconnection and network studies to determine whether, and in what amount, additional distributed generation facilities can be safely added to the feeder or accommodated in some other fashion. These studies should be completed within six weeks, and application processing should then resume.

(4) A utility may reject applications for a distributed generation facility under this section if the utility can demonstrate specific reliability or safety reasons why the distributed generation should not be interconnected at the requested site. However, in such cases the utility shall work with the customer to attempt to resolve such problems to their mutual satisfaction.

(5) A utility shall make all reasonable efforts to seek methods to safely and reliably interconnect distributed generation facilities that will export power. This may include switching service to a radial feed if practical and if acceptable to the customer.

(i) Pre-Interconnection studies for network interconnection of distributed generation. Prior to charging a pre-interconnection study fee for a network interconnection of distributed generation, a utility shall first advise the customer of the potential problems associated with interconnection of distributed generation with its network system. For potential interconnections to network systems there shall be no pre-interconnection study fee assessed for a facility with inverter systems under 20 kW. For all other facilities the utility may charge the customer a fee to offset its costs incurred in the conduct of the pre-interconnection study. In those instances where a utility conducts an interconnection study, the following shall apply:

(1) The conduct of such pre-interconnection studies shall take no more than four weeks;

(2) A utility shall prepare written reports of the study findings and make them available to the customer;

(3) The studies shall consider both the costs incurred and the benefits realized as a result of the interconnection of distributed generation to the utility's system; and

(4) The customer shall receive an estimate of the study cost before the utility initiates the study.

(j) Communications concerning proposed distributed generation projects. In the course of processing applications for interconnection and parallel operation and in the conduct of pre-interconnection studies, customers shall provide the utility detailed information concerning proposed distributed generation facilities. Such communications concerning the nature of proposed distributed generation facilities shall be made subject to the terms of §25.84 of this title (relating to Annual Reporting of Affiliate Transactions for Electric Utilities), §25.272 of this title (relating to Code of Conduct for Electric Utilities and their Affiliates), and §25.273 of this title (relating to Contracts between Electric Utilities and their Competitive Affiliates). A utility and its affiliates shall not use such knowledge of proposed distributed generation projects submitted to it for interconnection or study to prepare competing proposals to the customer that offer either discounted rates in return for not installing the distributed generation, or offer competing distributed generation projects.

(k) Equipment pre-certification.

(1) Entities performing pre-certification. The commission may approve one or more entities that shall pre-certify equipment as defined pursuant to this section.

(2) Standards for entities performing pre-certification. Testing organizations and/or facilities capable of analyzing the function, control, and protective systems of distributed generation units may request to be certified as testing organizations.

(3) Effect of pre-certification. Distributed generation units which are certified to be in compliance by an approved testing facility or organization as described in this subsection shall be installed on a company utility system in accordance with an approved interconnection control and protection scheme without further review of their design by the utility.

(l) Designation of utility contact persons for matters relating to distributed generation interconnection.

(1) Each electric utility shall designate a person or persons who will serve as the utility's contact for all matters related to distributed generation interconnection.

(2) Each electric utility shall identify to the commission its distributed generation contact person.

(3) Each electric utility shall provide convenient access through its internet web site to the names, telephone numbers, mailing addresses and electronic mail addresses for its distributed generation contact person.

(m) Time periods for processing applications for interconnection and parallel operation. In order to apply for interconnection the customer shall provide the utility a completed application for interconnection and parallel operation. The interconnection of distributed generation shall take place within the following schedule:

(1) For a facility with pre-certified equipment, interconnection shall take place within four weeks of the utility's receipt of a completed application.

(2) For other facilities, interconnection shall take place within six weeks of the utility's receipt of a completed application.

(3) If interconnection of a particular facility will require substantial capital upgrades to the utility system, the company shall provide the customer an estimate of the schedule and customer's cost for the upgrade. If the customer desires to proceed with the upgrade, the customer and the company will enter into a contract for the completion of the upgrade. The interconnection shall take place no later than two weeks following the completion of such upgrades, except in situations in which a customer is not able to connect within two weeks following the completion of such upgrades, this time may be extended by agreement of the electric utility and the customer. The utility shall employ best reasonable efforts to complete such system upgrades in the shortest time reasonably practical.

(4) A utility shall use best reasonable efforts to interconnect facilities within the time frames described in this subsection. If in a particular instance, a utility determines that it cannot interconnect a facility within the time frames stated in this subsection, it will notify the applicant in writing of that fact. The notification will identify the reason or reasons interconnection could not be performed in accordance with the schedule and provide an estimated date for interconnection.

(5) All applications for interconnection and parallel operation shall be processed by the utility in a non-discriminatory manner. Applications shall be processed in the order that they are received. It is recognized that certain applications may require minor modifications while they are being reviewed by the utility. Such minor modifications to a pending application shall not require that it be considered incomplete and treated as a new or separate application.

(n) Reporting requirements. Each electric utility shall maintain records concerning applications received for interconnection and parallel operation of distributed generation. Such records will include the name of the applicant, the business address of the applicant, and the location of the proposed facility by county, the capacity rating of the facility in kilowatts, whether the facility is a renewable energy resource as defined in §25.173 of this title (relating to Goal for Renewable Energy), the date each application is received, documents generated in the course of processing each application, correspondence regarding each application, and the final disposition of each application. The owner of a distributed generation facility that is interconnected under this section shall report to the utility any change in ownership of the facility and the cessation of operations of a facility within 14 days of such change. By March 30 of each year, every electric utility shall file with the commission a distributed generation interconnection report for the preceding calendar year that identifies each distributed generation facility interconnected with the utility's distribution system. The report shall list the new distributed generation facilities interconnected with the system since the previous year' report, any change in ownership or the cessation of operations of any distributed generation that has been reported to the electric utility and not included in the previous report, the capacity of each facility and whether it is a renewable energy resource, and the feeder or other point on the company's utility system where the facility is connected. The annual report shall also identify all applications for interconnection received during the previous one-year period, and the disposition of such applications.

(o) Distributed natural gas generation facility. This subsection, as well as the other subsections of this section, apply to a distributed natural gas generation facility. This subsection does not require an electric cooperative to transmit electricity to a retail point of delivery in the certificated area of the electric cooperative if the electric cooperative has not adopted customer choice. If there is a conflict between this subsection and another subsection of this section, this subsection controls.

(1) Transmission.

(A) Electric utilities. At the request of the owner or operator of a distributed natural gas generation facility, an electric utility shall allow the owner or operator of the facility to interconnect with and use transmission and distribution facilities to transmit electricity to another entity that is acceptable to the owner or operator in accordance with this section and the commission's rules for open-access comparable transmission service for electric utilities in ERCOT, §§25.191 - 25.203 of this title, or a tariff approved by the Federal Energy Regulatory Commission (FERC).

(B) Electric cooperatives. At the request of the owner or operator of a distributed natural gas generation facility, an electric cooperative shall allow the owner or operator of the facility to use transmission and distribution facilities to transmit the electric power to another entity that is acceptable to the owner or operator in accordance with the commission's rules for open-access comparable transmission service for electric utilities in ERCOT, §§25.191 - 25.203 of this title, or a tariff approved by FERC.

(2) Interconnection Disputes. If an electric utility or electric cooperative seeks to recover from the owner or operator of a distributed natural gas generation facility an amount that exceeds the amount in the estimate provided under PURA §35.036(e) by more than 5%, the commission shall resolve the dispute at the request of the owner or operator of the facility.

(p) Agreement for Interconnection and Parallel Operation of Distributed Generation.

Figure: 16 TAC §25.211(p) (.pdf)

(q) Tariff for Interconnection and Parallel Operation of Distributed Generation.

Figure: 16 TAC §25.211(q) (No change.)

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 16, 2016.

TRD-201606657

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 5, 2017

Proposal publication date: June 24, 2016

For further information, please call: (512) 936-7223