April 1 through June 30, 2017

Rate & Regulatory Update A Summary of State Rate & Regulatory ActivityA Publication for AGA MembersThis document is intended to provide AGA members with a summary of information relative to state rate and regulatory proceedings and other related matters on a timely basis. Additional information and archived versions of the Rate & Regulatory Update can be found at the following web link:https://www.aga.org/rate-alerts

Rate Case Data for this PeriodOrders Issued 8Average ROE 9.69% (8 available results)Innovative Rate Mechanisms

VSP, COYL surcharges (Southwest Gas), LPP tracker (National Fuel), PRP rider (Delta Gas), FCCM- decoupling mechanism (Intermountain Gas), Gas Service Line Replacement Program (Louisville Gas & Electric)

Trends and Analysis

Return on EquityAs noted in the 2016 year-end update, average return on equity (ROE) saw a slight decline in 2016, finishing at an average of 9.58% for the year (based on information from publicly available cases). During the 2nd quarter, average ROE—based on the 8 available results—saw a slight increase from the 2016 data, averaging at around 9.69% for the time period analyzed. It’s important to note, however, that two of the results were ROEs that had been awarded several years ago, and were not up for re-evaluation in the cases resolved during this quarter. As a result, these two outlier results brought up the overall average.

Gas Distribution ROE 2012-20162012 9.93% (34 cases)2013 9.68% (21 cases)2014 9.78% (26 cases)2015 9.63% (17 cases)2016 9.58% (24 cases)

Based on publicly reported cases

Innovative Rate Mechanisms Regulatory support for “innovative” rate mechanisms continues across the country. In fact, support for these rate mechanisms has become prevalent in so many jurisdictions that they may no longer need to be deemed as innovative. The accelerated replacement of pipelines deemed no longer fit for service continues to be a focus for both companies and commissions.

The following mechanisms were considered during this quarter: Southwest Gas Vintage Steel Pipe Replacement Program (VSP), Customer Owned Yard

Line Program (COYL) National Fuel Leak Prone Pipe Tracker (LPP)

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April 1 through June 30, 2017

Rate & Regulatory Update Delta Gas Pipeline Replacement Program Rider (PRP) Intermountain Gas Fix Cost Collection Mechanism (FCCM) Louisville Gas & Electric Gas Service Line Replacement Program (GSLR)

Additional detail on each is contained within the case summaries provided below.

Leak Abatement ProgramNotably, during the 2nd quarter, the California Public Utilities Commission (CPUC) issued a final decision relative to the establishment of best practices and reporting requirements for the CPUC Natural Gas Leak Abatement Program, which was developed in consultation with the California Air Resources Board (CARB) pursuant to state legislation—SB 1371—which was enacted in 2014. Per the decision, in order to minimize natural gas emissions from California’s regulated transmission and distribution gas system, utilities are now required to eliminate their backlog of natural gas leaks within three years.

Further, the decision implements the following:

1) Annual reporting for tracking methane emissions2) Twenty-six best practices for minimizing methane emissions pertaining to policies and

procedures, recordkeeping, training, experienced trained personnel, leak detection, leak repair and leak prevention

3) Biennial compliance plan incorporated into the utilities’ annual Gas Safety Plans beginning March 2018

4) Cost recovery process to facilitate Commission review and approval of incremental expenditures to implement best practices and Pilot Programs and Research & Development

Additional information about this decision, including background and plans for the future, is included in PG&E’s rate case summary below.

Other Regulatory Developments

Commission Changes & Updates

FERC: On June 6, the Senate Committee on Energy & Natural Resources approved the nominations of Neil Chatterjee and Robert Powelson to fill vacancies on the Federal Energy Regulatory Commission. Both await confirmation by the full Senate.

On June 28, President Donald Trump announced his intent to nominate Robert Glick to the Commission. Glick served as minority counsel on the Senate Energy and Natural Resources Committee. If confirmed, he will serve the remainder of a 5 year term that expires in June 2022.

Commissioner Colette Honorable departed the Commission on June 30.

On July 13, President Trump announced his intent to nominate Kevin McIntyre to be FERC Chairman. McIntyre is presently the co-leader of the global Energy Practice at the law firm

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April 1 through June 30, 2017

Rate & Regulatory UpdateJones Day. If confirmed, McIntyre would serve the remainder of the term expiring June 30, 218 and an additional term ending June 30, 2023.

Florida: On June 25, Jimmy Patronis resigned from the Florida Public Service Commission. Governor Rick Scott has not yet named a replacement.

Hawaii: On April 29, the Hawaii State Senate rejected the appointment of Thomas Gorak to the Hawaii Public Utilities Commission. Governor David Ige subsequently announced his appointment of James Griffin to the Commission on May 19. This is appointment is again subject to senate confirmation.

Iowa: On April 10, the Iowa State Senate confirmed Richard Lozier to the Iowa Utilities Board. Lozier began serving a term that will extend to 2023 on May 1st.

Louisiana: On May 23, Commission Scott Angelle announced his resignation from the Louisiana Public Service Commission. Louisiana Governor John Bel Edwards is permitted to make an interim appointment until a special election can be held for the remainder of Angelle’s unexpired term—which extends to December 2018.

On June 1, Governor Edwards appointed Damon Baldone to the commission. Baldone is to serve on an interim basis until a special election can be held for the remainder of Angelle’s unexpired term of office.

Maine: On June 30, Carlisle McLean resigned from the Maine Public Utilities Commission. Governor Paul LePage has not yet named a replacement.

Massachusetts: On June 19, Cecile Fraser began serving on the Massachusetts Department of Public Utilities. Fraser’s term extends to April 2021.

Nevada: On May 15, Commissioner Paul Thomsen resigned from the Public Utilities Commission of Nevada. He was serving a term that extends to September 2019.

New York: On June 21, the New York Senate confirmed Governor Andrew Cuomo’s appointment of John Rhodes as chairman of the New York Public Service Commission. Rhodes will serve at term that expires in February 2021. The Senate also confirmed Philip Wilcox and James Alesi to terms as commissioners. I

North Carolina: On May 1, North Carolina Governor Roy Cooper appointed three commissioners to the North Carolina Utilities Commission—Commissioner ToNola Brown Bland was reappointed to another six year term; Charlotte Mitchell was appointed to replace Commissioner Bryan Beatty; Daniel Clodfelter was appointed to replace Commissioner Don Bailey.

Tennessee: On May 8, Governor Bill Haslam announced the appointment of Keith Jordan to the Tennessee Public Utility Commission. As well, Commissioner Herbert Hilliard was appointed to a second 6 year term. Both were approved by the General Assembly in late April.

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April 1 through June 30, 2017

Rate & Regulatory UpdateTexas: On April 13, Public Utility Commission of Texas Chairman Donna Nelson announced her departure from the Commission effective May 15th.

Vermont: On June 1, Governor Phil Scott announced his appointment of Anthony Roisman to serve as chairman of the Vermont Public Service Board. Roisman’s appointment is subject to Senate confirmation. If confirmed, he will serve a term extending to February 2023.

Other Noteworthy Regulatory Action On April 4, Wisconsin Gas LLC, a subsidiary of WEC Energy Corporation, filed a settlement agreement with the Public Service Commission of Wisconsin. If adopted, the company would be required to freeze base rates in 2018 and 2019.

On April 26, the Missouri Public Service Commission adopted a settlement which authorizes Missouri Gas Energy, a subsidiary of Spire Inc., a $3 million gas rate increase in the context of the company’s infrastructure system replacement surcharge rider (ISRS).

On May 1, Virginia Natural Gas, a subsidiary of Southern Company, filed for an adjustment to its SAVE rider. The company is seeking a $3 million rate increase that reflects a $15 million rider-specific rate base.

On June 15, the California Public Utilities Commission approved a request made by Southwest Gas Corporation authorizing the company to maintain its rate framework, including the Post Test Year Mechanism adjustments. Under the mechanism, Southwest Gas is able to implement annual rate increases of 2.75% for each of its three rate jurisdictions. The company must come in for its next rate case by September 1, 2019.

The following companies initiated rate proceedings during the 2nd quarter: CenterPoint Energy Resources (Arkansas), Columbia Gas of Maryland, Missouri Gas Energy, Laclede Gas (Missouri), Northern Utilities, Niagara Mohawk Power Co., Southern Connecticut Gas Company, Northern Utilities, Avista Corporation, Northern States Power Co., Public Service Company of Colorado (Xcel), Southern Connecticut Gas Company (Avangrid), Avista Corporation (Idaho), Northern Utilities (Unitil), South Carolina Electric & Gas Co. (SCANA), Piedmont Natural Gas Company (South Carolina).

Rate Case Decisions April 11, 2017

Company Southwest Gas HoldingsState ArizonaDocket Number D-G-01551A-16-0107Approved Increase

$16 million ($32 million requested)

Approved ROE 9.5% (10.25% requested)Intervenors Arizona Investment Council, Residential Utility Consumer Office,

Arizona Community Action Association, NatureSweet USA, LLC, Desert Valley Natural Gas, LLC, Pinal Energy, LLC, Property Owners and

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April 1 through June 30, 2017

Rate & Regulatory UpdateResidents Association of Sun City West

Case SummaryOn April 11, the Arizona Corporation Commission adopted a gas rate settlement for Southwest Gas Holdings. The settlement authorizes the company a $16 million base rate increase, premised upon a 9.5% return on equity (51.7% of capital) and an implied 7.4% overall return on an original cost rate base valued at $1.325 billion.

Provisions of the approved settlement agreement include the following: A $16 million base rate increase; No change to the approved return on equity of 9.5%; A three-year rate case stay out, in which the Company agrees not to file any new

general rate case until at least May 1, 2019; Retention of the company’s full revenue decoupling mechanism, with modifications to

simplify and improve the methodology; Increasing eligibility for the low income ratepayer assistance program to 200% of the

federal poverty guideline level; Implementation of a Vintage Steel Pipe (VSP) replacement program to improve safe

and reliable operation of the Company’s system.

Regarding the VSP program, the annual adjustment surcharge will be capped at $0.015 per therm per year, and shall apply to all recorded full margin therms sold. The effective period for replacements under the VSP program will be until the effective date of new permanent rates approved by the Commission in the Company’s next general rate case application, unless otherwise extended by the Commission.

Also as part of the settlement agreement, Southwest Gas will be allowed to expand its Customer Owned Yard Line (COYL) program. The Company will work with Staff to develop a plan for the COYL program, to include revised annual reports. The annual rate adjustment for the COYL program surcharge will continue to be capped at $01.01 per therm per year, and shall apply to recorded full margin therms sold.

Per the settlement, Southwest Gas shall be allowed to continue to utilize a full revenue decoupling mechanism, subject to the modification that the Energy Efficiency Enabling Provision (EEP) will no longer utilize a monthly weather adjustor. The Company shall modify its tariff to change the name of the mechanism from “Energy Efficiency Enabling Provision” to “Delivery Charge Adjustment Provision.”

April 20, 2017Company National Fuel Gas Distribution State New YorkDocket Number C-16-G-0257Approved Increase

$5.9 million ($41.7 million requested)

Approved ROE 8.7 % (10.2% requested)Intervenors Utility Intervention Unit of the Department of State, Multiple Intervenors

(large commercial and industrial users), Public Utility Law Project of

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April 1 through June 30, 2017

Rate & Regulatory UpdateNew York, EnergyMark LLC, People United for Sustainable Housing Buffalo

Case Summary On April 20, the New York Public Service Commission authorized National Fuel Gas Distribution a $5.9 million gas distribution rate increase premised on a 8.7% return on equity (42.9% of capital) and a 6.92% return on rate base valued at $704 million.

Additional issues raised in the case and subsequent decision are outlined below.

Leak Prone Pipe Surcharge Mechanism: In its initial filing, National Fuel proposed that it be provided a system upgrade and modernization tracking mechanism. The Company justified its inclusion as allowing for the efficient recovery of carrying costs associated with the replacement of Leak Prone Pipe (LPP) above the targeted amounts planned for replacement. The Company proposed a 200 basis point repeating, cumulative positive incentive to accelerate its LPP replacement.

Staff supported the company’s request for a surcharge, but maintained that it should cover only those costs specific to LPP replacement. In this manner, the surcharge would be consistent with surcharges provided to other LDCs in accord with Commission Policy. Staff also proposed that the surcharge would sunset after three years, be limited to the forecast unit cost per mile and include a positive incentive limited to 10 basis points per year for incremental LPP beyond 105 miles. The Company refuted some of the Staff’s modifications, claiming that some of the limitations were not consistent with the Commission’s policy of replacing LPP as quickly as practicable.

In its final order, the Commission adopted a LPP tracking mechanism limited to incremental LPP costs that reflect the approved pre-tax rate of return, depreciation rates, property tax rates and uncollectible rates. The surcharge will be available for recovery of the Company’s LPP costs for a period of three years or until modified by the Commission.

Methane Detector Deployment: Similar to a program that was recently adopted for other utilities in the State, Staff proposed an incentive program to encourage residential methane detector deployment. The Recommended Decision rejected this proposal, noting the concern that the technology sought to be deployed was not presently available.

However, Staff later expressed concern that the RD’s reasoning could be used subjectively against any technology-based program inasmuch as one could speculate that new or better technology might always be developed in the future. The Company explained that the issue is that any prediction about when such technology might be available. The Company claimed that another utility in the state—Consolidated Edison Company of New York—had already agreed to work with interested parties to develop a plan relative to methane detector deployment and that there is likely some benefit to be gained in experience and knowledge from that process. The Company asserted that there is no harm in requiring a similar collaborative process here. The Commission agreed and modified the RD accordingly.

Customer Conversion Incentives: Staff proposed a new positive revenue adjustment

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April 1 through June 30, 2017

Rate & Regulatory Updateincentive of one basis point for each 10 percent additional increase in customers, incremental to Staff’s customer growth targets of 2,500 firm customers in the rate year. The Commission did not adopt this recommendation, and declined to adopt any performance mechanism for the Company in its Order.

Franchise Expansion: Staff proposed an incentive to encourage the Company to pursue opportunities outside of its existing franchise. The Commission rejected this incentive, agreeing with the Company that extraterritorial expansion could dilute the Company’s resources and that it should focus on opportunities within its own territory.

Pilot Programs: National Fuel had previously gotten approval to implement two pilot programs—one relative to distributed generation and another for natural gas vehicles. In this case, Staff recommended that these be included in the Company’s tariff as permanent programs. The ALJ deemed the conversion of the pilots to permanent programs unnecessary, and the Commission adopted that recommendation.

Gas Distribution System Enhancement: Staff recommended that the Company pursue a General Gas Expansion Program and a Low Income Gas Expansion Pilot Program. The Company agreed to work with municipalities to try to identify new load and municipal financial assistance possibilities. The ALJ commented on the relationship between Staff and the Company as to guidance and managing the programs in his Recommended Decision (RD), which the Commission then adopted.

Low Income Gas Expansion Pilot: In its filing, National Fuel indicated that it has two new programs: the Gas Conversion Rebate Program and the Low Income Usage Reduction Conversion Program. These programs provide rebates to cover some or all of the non-Company related costs associated with appliance Conversion and internal houseline installation. In its RD, the ALJ recommended that the programs continue. The Commission later adopted that recommendation.

April 27, 2017Company Delta Natural GasState KentuckyDocket Number C-2017-00111 (PRP)Approved Increase

$1.8 million ($1.8 million requested)

Approved ROE 10.4% (2010)Intervenors n/a

Case SummaryOn April 27, the Kentucky Public Service Commission authorized Delta Natural Gas a $1.8 million gas distribution rate increase, premised upon a $9.8 million rate base, in the context of the company’s pipe replacement program (PRP rider). The increase reflects investments made during 2016, and the Company’s PRP related rate changes reflect a 10.4% return on equity—as established in a 2010 rate case.

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April 1 through June 30, 2017

Rate & Regulatory UpdateIn its February 2017 application, Delta proposed a current year PRP adjustment of $1,762,370. During 2016, the Company experienced an over-recovery of its PRP revenues of $1,645 which it proposed to include as a credit through its PRP Balancing Adjustment for 2017. The total PRP adjustment, including the Balancing Adjustment, is $1,760,725.

In the case, Delta was asked to provide information relative to the number of years it expected to use the PRP mechanism to recover the cost of replacing pipelines deemed no longer fit for service. In its previous case, the Company responded that it would take approximately 5 years to complete replacements of unprotected bare steel mains, but that that the PRP would be a “continuing program to improve public safety and reliability of service for its customers.” In this instant case, Delta stated that at the current pace it would take the Company 14-20 years to eradicate its mapped bare steel.

As noted in its previous order, the Commission, while recognizing the shared goal of safety and reliability of service provided via the PRP, does not intend for the program to be open-ended. As a result, and given the increase in time estimates between the two cases, the Commission will continue to require Delta to file information relative to the remaining items to be replaced and estimate of associated costs, etc. with future annual PRP applications.

April 28, 2017Company Intermountain GasState IdahoDocket Number C-INT-G-16-2Approved Increase

$4.1 million ($10.2 million requested)

Approved ROE 9.5%Intervenors Community Action Partnership Association of Idaho, Northwest

Industrial Gas Users, Idaho Conservation League, Northwest Energy Coalition, Amalgamated Sugar Company, Snake River Alliance, Federal Executive Agencies

Case SummaryOn April 28, the Idaho Public Utility Commission authorized MDU Resources Group subsidiary Intermountain Gas a $4.1 million gas rate increase premised on a 9.5% return on equity, and a 7.3% return on rate base valued at $235.5 million.

Intermountain Gas filed its last general rate case in 1985. In its initial filing in August 2016, Intermountain stated that it needs to raise base rates for the first time in over 30 years in order to recover increased costs and operating expenses associated with maintaining a safe and reliable distribution system for an expanding customer base, installation of a new Customer Service Center, and significant spending and depreciation expenses related to pipeline and infrastructure replacement.

In its application, the Company also asked to implement a DSM program that would help customers decrease their need for gas through conservation. The Company proposed to introduce a new Energy Efficiency Rebate Program under which the Company would provide rebates to customers who install high-efficiency natural gas equipment and have ENERGY

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April 1 through June 30, 2017

Rate & Regulatory UpdateStar certified homes. The company also proposed to implement a decoupling mechanism (Fixed Cost Collection Mechanism (FCCM)) to ensure that it does not lose money if its proposed DSM program causes customers to buy less gas. Intermountain proposed raising its monthly fixed customer charges for residential and commercial classes, and to recover these fixed costs through the FCCM—defined as total sales service margin less Purchased Gas Cost Adjustment (PGA) and less revenues recovered from the customer charge for the applicable rate schedules. Under its proposal, the Company would reconcile, and accrue through a balancing account, the difference between its actual FCCM and the approved FCCM, and thus ensure the Company’s revenues and earnings are separated from, and unaffected by, the amount of gas it sells to its customers.

In its Order, the Commission found that the DSM is an important part of any utility’s provision of service, both as a least-cost resource and an element of promoting energy efficiency. Accordingly, it authorized the implementation of Intermountain’s proposed DSM program.

The Commission did not, however, find the associated decoupling mechanism (FCCM) to be In the public interest at this time. The Commission stated its belief that the Company must offer a more defined DSM program before the FCCM could be authorized—noting that the proposed program is inadequate to justify a fixed-cost recovery for perceived lost therm sales. The Commission encouraged increased evidentiary quantification of the Company’s need for the decoupling mechanism, and noted that neither the DSM nor FCCM need to be tied to a general rate case and can be presented to the Commission at any time.

On May 18, 2017, Intermountain Gas petitioned the Commission to reconsider its original Order on the points relating to (1) the data input into Staff’s weather normalization model; (2) the Commission’s preference for Staff’s weather normalization model over the Company’s model; (3) the disallowance of certain affiliated O&M expenses; and (4) the disallowance of incentive compensation. Discussions relative to these four issues are ongoing and the Commission is expected to issue a Final Order on Reconsideration later this year.

May 11, 2017Company Pacific Gas and Electric Co.State CaliforniaDocket Number A-15-09-001 (Gas)Approved Increase

$3 million decrease ($62.6 million increase requested)

Approved ROE 10.4%Intervenors The Utility Reform Network (TURN), Alliance for Nuclear Responsibility,

Coalition of California Utility Employees (CUE), Collaborative Approaches to Utility Safety Enforcement (CAUSE), Consumer Federation of California (CFC), Environmental Defense Fund (EDF), Marin Clean Energy, Merced Irrigation District, Modesto Irrigation District, National Diversity Coalition, Small Business Utility Advocates, South San Joaquin Irrigation District

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April 1 through June 30, 2017

Rate & Regulatory UpdateCase Summary

On May 11, the California Public Utilities Commission (CPUC) approved a Settlement Agreement authorizing Pacific Gas & Electric Company, a PG&E Corporation subsidiary, a $91 million electric distribution and generation base rate increase, and required a $3 million gas distribution rate reduction. Rate of return was not an issue in these proceedings, as it is determined in a separate automatic adjustment mechanism. The cases incorporated a 10.4% return on equity and an 8.06% overall return.

The adopted gas distribution revenue requirement includes additional funding to enable PG&E to continue to upgrade its pipeline system and to improve emergency response capabilities. PG&E will receive additional funding to transition from a 5-year to a 4-year leak survey cycle, to expand the use of new surveyor technology and to repair below-ground leaks. Further, PG&E will receive additional funding for new and replacement cathodic-protection systems and remote monitoring systems. Finally, PG&E will receive additional funding for gas pipeline replacement and reliability, especially its Gas Pipeline Replacement Program, where the Company requested sufficient revenues to replace 46 miles of pipe per year, 95 miles of Aldyl-A plastic pipe per year, and 15 miles of gas mains per year and to install additional emergency valves.

Article 4 of the Settlement Agreement sets forth two contested issues over which the Settling Parties were unable to reach consensus. One of the contested issues centered on gas leak management. The parties were unable to reach consensus on whether PG&E should be authorized to establish a new balancing account to record costs to comply with gas leak management requirements that may emerge from Commission Rulemaking R.15-01-008 (more information below). In Section 4.2 of the Settlement Agreement, CUE, EDF and PG&E agree to support Commission approval of the following provisions:

PG&E agrees to support adoption of a minimum 3-year leak survey cycle in R.15-01-1008

CUE, EDF and PG&E agree that, to enable the Company to implement new regulatory requirements upon their adoption in Phase 1 of R.15-01-008 a New Environmental Regulatory Balancing Account (NERBA) should be adopted. PG&E shall be authorized to track and record to the NERBA incremental Gas Distribution Emission reduction costs associated with new regulatory requirements pertaining to gas distribution leak management activities, adopted in Phase 1 of R.15-01-008, until the Commission makes a decision regarding costs in Phase 2

PG&E will file a Tier 1 Advice Letter under the Commission’s issuance of a final decision in the 2017 GRC to establish the NERBA

PG&E is authorized to recover the costs recorded in the NERBA annually by including them in the Annual Gas True-up advice letter filing

TURN, CAUSE and CFC opposed those provisions.

The Commission opted not to decide on these particular proposals in this GRC decision because at the time they were actively pending in R.15-01-008. The proposal to adopt the new balancing account was denied without prejudice in this GRC decision.

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April 1 through June 30, 2017

Rate & Regulatory UpdateR. 15-01-008 BackgroundIn August 2014, the California legislature passed a pipeline safety bill. As amended, the bill required the California PUC to adopt rules and procedures governing the operation, maintenance, repair and replacement of those commission-regulated gas pipeline facilities that are intrastate transmission and distribution lines to minimize leaks to be mitigated pursuant to the Natural Gas Pipeline Safety Act of 2011 and to reduce emissions of natural gas from those facilities to the maximum extent feasible in order to advance the state’s goals in reducing emissions of GHG pursuant to the California Global Warming Solutions Act of 2006. Further, the legislation required the CPUC to commence a proceeding by 1/15/15 to adopt those rules and procedures that:

Provide maximum technologically feasible and cost-effective avoidance, reduction and repair of leaks and leaking components in facilities that are intrastate transmission and distribution lines within a reasonable time after discovery;

Provide for repair of leaks as soon as reasonably possible after discovery, consistent with established safety requirements and the goals of reducing air pollution and the climate change impacts of methane emissions;

Evaluate operations, maintenance and repair practices for those facilities to determine whether existing practices are effective at achieving the goals of the bill and to determine whether alternative practices may be more effective;

Establish and require the use of best practices for leak surveys, patrols, leak survey technology and leak reduction;

Establish protocols and procedures for the development and use of metrics to quantify the volume of emissions from leaking components not inconsistent with the protocols and procedures utilized in mandatory reporting to state and federal air quality agencies;

Require owners of commission-regulate facilities to calculate and report to the CPUC a baseline system wide leak rate and to periodically update that rate calculation and to annually report measures that will be taken in the following year to reduce the system wide leak rate to achieve goals of the bill.

Pursuant to this legislation, on January 15, 2015, the California Public Utilities Commission Opened a rulemaking to carry out the intent of SB 1371. In the proceeding (R. 15-01-008), the Commission intended to adopt rules and procedures to minimize natural gas leaks from commission-regulated intrastate transmission and distribution gas pipelines and facilities. The developed rules and procedures were to govern the operation, maintenance, repair, and replacement of these pipelines to achieve both of the following objectives:

(1) To minimize the leaks as a hazard to be mitigated pursuant to § 961(d); and (2) While giving due deference to the cost considerations of § 977, to reduce the emissions of natural gas from these pipelines to the maximum extent feasible in order to advance the state’s goals of reducing greenhouse gas emissions.

Companies affected by this rulemaking were required to file a report by May 15, 2015. These reports were required to include, at a minimum include the following information:

(1) A description and general location of each gas corporation’s gas pipeline facilities, including its intrastate transmission and distribution lines.

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April 1 through June 30, 2017

Rate & Regulatory Update(2) A summary of its current leak management practices.(3) A list of new methane leaks in 2013 by grade, and in 2014 by grade.(4) A list of open leaks that are being monitored or are scheduled to be repaired. If the open leak is only being monitored, provide the reason why the leak has not been scheduled to be repaired.(5) The total number of leaks detected and repaired in 2013 and 2014, and the time it took to repair those leaks once they were discovered.(6) A best estimate of gas loss due to leaks (list estimated gas loss by month for 2013 and 2014), and an explanation of how the estimates were derived.

In a decision published on June 15, 2017, the CPUC established best practices and reporting requirements for the CPUC Natural Gas Leak Abatement Program which was developed in consultation with the California Air Resource Board (CARB) pursuant to SB 1371. In order to minimize natural gas emissions from California’s regulated transmission and distribution gas system, utilities are required to eliminate their backlog of leaks within three years.

Further, the decision implements the following:

5) Annual reporting for tracking methane emissions6) Twenty-six best practices for minimizing methane emissions pertaining to policies and

procedures, recordkeeping, training, experienced trained personnel, leak detection, leak repair and leak prevention

7) Biennial compliance plan incorporated into the utilities’ annual Gas Safety Plans beginning March 2018

8) Cost recovery process to facilitate Commission review and approval of incremental expenditures to implement best practices and Pilot Programs and Research & Development

In its June 15 decision, the CPUC does authorize utilities to establish a two-way balancing account to recover their best practices implementation costs associated with the rulemaking. Within 30 days of the published decision, each utility shall submit a Tier 1 AL to create new Environmental Regulations Balancing Accounts. Per the decision, utilities should not begin to recover Natural Gas Leak Abatement costs in rates until the CPUC has adopted cost forecasts and cost limits in response to Tier 3 ALs and approved Compliance Plans required by this decision. In the meantime, utilities are permitted to record costs in the new NERBA and to track and required administrative costs in separate Natural Gas Leak Abatement Memorandum Accounts.

The rulemaking remains open in order to address implementation issues in a second phase.

May 23, 2017Company CenterPoint Energy Resources CorporationState TexasDocket Number D-GUD-10567Approved $16.5 million ($31.4 million requested)

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April 1 through June 30, 2017

Rate & Regulatory UpdateIncreaseApproved ROE 9.6%Intervenors Gulf Coast Coalition of Cities, City of Houston/Houston Coalition of

Cities, Texas Utilities Coalition

Case SummaryOn May 23, the Railroad Commission of Texas adopted a settlement authorizing CenterPoint Energy Resources Corporation, a subsidiary of CenterPoint Energy, a $16.5 million gas distribution base rate increase. The increase is premised on a 9.6% return on equity and an 8.0237% return.

The settlement reached in the instant case also calls for the partial consolidation of the Houston and Texas Coast service areas as requested by CenterPoint Energy Resources in its initial filing.

June 6, 2017Company Delmarva Power & Light Co.State DelawareDocket Number D-16-0650 Approved Increase

$4.9 million ($21.5 million originally requested)

Approved ROE 9.7%Intervenors Delaware Division of the Public Advocate

Case SummaryOn June 6, the Delaware Public Service Commission adopted a proposed order authorizing Delmarva Power & Light Co., a subsidiary of Exelon Corporation, a $4.9 million gas distribution base rate increase. The order approves the settlement agreement of 9.7% ROE but is silent with respect to other traditional rate case parameters.

In its initial application, the Company cited its increase in capital investments to ensure a safe and reliable gas transmission and distribution system for its customers as the need for the requested natural gas base rate increase. Since its last base rate case in 2012, Delmarva has made capital investments in its gas facilities in the amount of $120.9 million. Of that investment, $79.7 million was incurred for reliability investments—including amounts spent to comply with federal requirements to rehabilitate and replace cast iron piping—and the remaining amount pertained to the installation of gas mains and services for new load.

Key settlement provisions include the following:

With respect to depreciation, a major issue in the case, the settling parties agreed that annual depreciation expense will be calculated using accrual rates set forth in Exhibit 1 Column (4), and will also include a net salvage allowance calculated using the Rolling 5-Year Average consistent with Order No. 6930.

The Company’s incremental labor costs arising out of the IMU battery replacement

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April 1 through June 30, 2017

Rate & Regulatory Updateproject will be deferred in the continued AMI regulatory asset related to IMU deployment for review and, if appropriate, recovery in a future proceeding.

“Costs to achieve synergy savings (CTAs) out of the PHI/Delmarva Power/Exelon Corporation merger will be amortized over 60 months, on a monthly basis. Projected synergy savings and CTAs will be reviewed in the Company’s next gas distribution base rate case and compared to actual figures provided to the parties in the Company’s report.

The Settling Parties agreed to the allocation of the base rate revenue changes among all customer classes; The Parties further agreed to maintain the Residential declining block volumetric rate structure for space heating customers during the heating season.

Notably, within 6 months following the final approval of the Settlement Agreement, the Settling Parties will define the scope of a microgrid report to be filed with the Commission. As part of that endeavor, within 9 months, the Company will select one or more sites to evaluate for the purposes of a potential microgrid project and prepare and file a report with the Commission containing analysis, including specifics pertaining to customer response and benefits of a potential microgrid project as well as the costs and cost recovery for the project (s).

June 22, 2017Company Louisville Gas & Electric Co.State KentuckyDocket Number C-2016-00371Approved Increase

$7.5 million ($13.4 million requested)

Approved ROE 9.75%Intervenors Attorney General of the Commonwealth of Kentucky—Office of Rate

Intervention, Kentucky Industrial Utility customers, Kroger Company, Wal Mart Stores East LP and Sam’s East LP, Kentucky School Boards Association, Kentucky Cable Telecommunications Association, Amy Waters and Sierra Club, BellSouth Telecommunications, Department of Defense and all other Federal Executive Agencies, Association of Community Ministries, Metropolitan Housing Coalition, Louisville/Jefferson County Metro Government, JBS Swift & Co.

Case SummaryOn June 22, the Kentucky Public Service Commission adopted a settlement with modifications, thereby authoring a $6.5 million gas base rate increase for Louisville Gas & Electric Co., a subsidiary of PPL Corporation. The increase is premised on a 9.7% ROE, but the settlement and order were silent regarding other rate case parameters including rate base and rate of return. Subsequently on June 29, the PSC issued a corrected order revising the rate increase and ultimately authorizing a $7 million gas base rate increase.

As part of its initial filing, LG&E requested that its Gas Line Tracker Mechanism (GLT) rates be updated for services rendered on or after July 1, 2017. LG&E proposed to implement a

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April 1 through June 30, 2017

Rate & Regulatory Update$101 million, 15-year program to replace steel customer service lines—known as the Gas Service Line Replacement Program—and a $60 million, three-year program to replace 15.5 miles of transmission pipeline—known as the Transmission Pipeline Modernization Program.

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