Regulatory Matters

Regulatory Assets and Liabilities

We follow the accounting and reporting requirements of ASC Topic 980, which provides that regulated entities account for and report assets and liabilities consistent with the economic effect of regulatory rate-making procedures if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected from customers. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income or expense are deferred on the balance sheet and are recognized in the income statement as the related amounts are included in customer rates and recovered from or refunded to customers.

Regulatory assets were comprised of the following items:



At December 31, (in millions)	2018		2017
Regulatory Assets
Unrecognized pension and other postretirement benefit costs (see Note 11)	$	798.3	$	733.5
Deferred pension and other postretirement benefit costs (see Note 11)	74.1		70.7
Environmental costs (see Note 18-D)	61.5		63.4
Regulatory effects of accounting for income taxes (see Note 1-N and Note 10)	233.1		238.8
Under-recovered gas and fuel costs (see Note 1-K)	34.7		25.5
Depreciation	209.6		181.0
Post-in-service carrying charges	206.6		173.3
Safety activity costs	91.7		66.5
DSM programs	45.5		40.0
Bailly Generating Station	244.3		—
Other	238.1		208.5
Total Regulatory Assets	$	2,237.5	$	1,801.2

Regulatory liabilities were comprised of the following items:



At December 31, (in millions)	2018		2017
Regulatory Liabilities
Over-recovered gas and fuel costs (see Note 1-K)	$	32.0	$	27.6
Cost of removal (see Note 7)	1,076.0		1,096.8
Regulatory effects of accounting for income taxes (see Note 1-O and Note 10)	1,428.3		1,563.4
Deferred pension and other postretirement benefit costs (see Note 11)	62.7		59.0
Other	61.0		48.8
Total Regulatory Liabilities	$	2,660.0	$	2,795.6

Regulatory assets, including under-recovered gas and fuel cost, of approximately $1,552.6 million as of December 31, 2018 are not earning a return on investment. These costs are recovered over a remaining life of up to 41 years. Regulatory assets of approximately $1,917.1 million include expenses that are recovered as components of the cost of service and are covered by regulatory orders. Regulatory assets of approximately $320.4 million at December 31, 2018, require specific rate action.

Assets:

Unrecognized pension and other postretirement benefit costs. In 2007, we adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer these gains or losses as a regulatory asset in accordance with regulatory orders or as a result of regulatory precedent, to be recovered through base rates.

Deferred pension and other postretirement benefit costs. Primarily relates to the difference between postretirement expense recorded by certain subsidiaries due to regulatory orders and the postretirement expense recorded in accordance with GAAP. These costs are expected to be collected through future base rates, revenue riders or tracking mechanisms.

Environmental costs. Includes certain recoverable costs of investigating, testing, remediating and other costs related to gas plant sites, disposal sites or other sites onto which material may have migrated. Certain of our companies defer the costs as a regulatory asset in accordance with regulatory orders, to be recovered in future base rates, billing riders or tracking mechanisms.

Regulatory effects of accounting for income taxes. Represents the deferral and under collection of deferred taxes in the rate making process. In prior years, we have lowered customer rates in certain jurisdictions for the benefits of accelerated tax deductions. Amounts are expensed for financial reporting purposes as we recover deferred taxes in the rate making process.

Under-recovered gas and fuel costs. Represents the difference between the costs of gas and fuel and the recovery of such costs in revenue and is used to adjust future billings for such deferrals on a basis consistent with applicable state-approved tariff provisions. Recovery of these costs is achieved through tracking mechanisms.

Depreciation. Represents differences between depreciation expense incurred on a GAAP basis and that prescribed through regulatory order. Significant components of this balance include:

•

Columbia of Ohio depreciation rates. Prior to 2005, the PUCO-approved depreciation rates for rate-making had been lower than those which would have been utilized if Columbia of Ohio were not subject to regulation resulting in the creation of a regulatory asset. In 2005, the PUCO authorized Columbia of Ohio to revise its depreciation accrual rates for the period beginning January 1, 2005. The revised depreciation rates are now higher than those which would have been utilized if Columbia of Ohio were not subject to regulation allowing for amortization of the previously created regulatory asset. The amount of depreciation that would have been recorded from 2005 through 2018 had Columbia of Ohio not been subject to rate regulation is a cumulative $806.8 million, $92.2 million less than that reflected in rates. The resulting regulatory asset balance was $39.5 million and $49.3 million as of December 31, 2018 and 2017, respectively.

•

Columbia of Ohio IRP and CEP. Columbia of Ohio also has PUCO approval to defer depreciation and debt-based post-in-service carrying charges (see "Post-in-service carrying charges" below) associated with its IRP and CEP. As of December 31, 2018, depreciation of $29.1 million and $76.0 million was deferred for the respective programs. Depreciation deferral balances for the respective programs as of December 31, 2017 were $26.5 million and $49.8 million. Recovery of the IRP depreciation is approved annually through the IRP rider. The equivalent of annual depreciation expense, based on the average life of the related assets, is included in the calculation of the IRP rider approved by the PUCO and billed to customers. Deferred depreciation expense is recognized as the IRP rider is billed to customers. The recovery mechanism for depreciation associated with the CEP is discussed in "Additional Regulatory Matters," below.

•

NIPSCO ECRM. NIPSCO obtained approval from the IURC to recover certain environmental related costs including operation and maintenance and depreciation expense once the environmental facilities become operational. The ECRM deferred charges represent expenses that will be recovered from customers through an annual ECRM Cost Tracker (ECT) which authorizes the collection of deferred balances over a six month period. Recovery of these costs will continue until such assets are included in rate base through an electric base rate case. Depreciation of $14.4 million and $13.9 million was deferred to a regulatory asset as of December 31, 2018 and 2017, respectively.

•

NIPSCO TDSIC. NIPSCO obtained approval from the IURC to recover costs for certain system modernization projects outside of a base rate proceeding. Eighty percent of the related costs, including depreciation, property taxes, and debt and equity based carrying charges (see "Post-in-service carrying charges" below) are recovered through a semi-annual recovery mechanism. Recovery of these costs will continue through the TDSIC tracker until such assets are included in rate base through a gas or electric base rate case, respectively. The remaining twenty percent of the costs are deferred until the next base rate case. As of December 31, 2018 and 2017, depreciation of $16.5 million and $10.3 million, respectively, was deferred as a regulatory asset.

Post-in-service carrying charges. Represents deferred debt-based carrying charges incurred on certain assets placed into service but not yet included in customer rates. This balance includes:


•	Columbia of Ohio IRP and CEP. See description of IRP and CEP programs above under the heading "Depreciation." As of December 31, 2018 and 2017, Columbia of Ohio had deferred PISCC of $197.1 million and $164.6 million, respectively.

•

NIPSCO TDSIC. See description of TDSIC program above under the heading "Depreciation." Deferral of equity-based carrying charges for the TDSIC program is allowed; however, such amounts are not reflected in regulatory asset balances for financial reporting as equity-based returns do not meet the definition of incurred costs under ASC 980. As of December 31, 2018 and 2017, NIPSCO had deferred PISCC of $9.5 million and $8.7 million, respectively.

Safety activity costs. Represents the difference between costs incurred in eligible safety programs in excess of those being recovered in rates. The eligible cost deferrals represent necessary business expenses incurred in compliance with PHMSA regulations and are targeted to enhance the safety of the pipeline systems. Certain subsidiaries defer the excess costs as a regulatory asset in accordance with regulatory orders and recovery of these costs will be address in future base rate proceedings.

DSM programs. Represents costs associated with Gas Distribution Operations and Electric Operations segments' energy efficiency and conservation programs. Costs are recovered through tracking mechanisms.

Bailly Generating Station. Represents the net book value of Units 7 and 8 of Bailly Generating Station that was retired during 2018. These amounts are currently being amortized at a rate consistent with their inclusion in customer rates.

Liabilities:

Over-recovered gas and fuel costs. Represents the difference between the cost of gas and fuel and the recovery of such costs in revenues, and is the basis to adjust future billings for such refunds on a basis consistent with applicable state-approved tariff provisions. Refunding of these revenues is achieved through tracking mechanisms.

Cost of removal. Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in customer rates of the rate-regulated subsidiaries for future costs to be incurred.

Regulatory effects of accounting for income taxes. Represents amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates and liabilities associated with accelerated tax deductions owed to customers that are established during the rate making process. Balance includes excess deferred taxes recorded upon implementation of the TCJA in December 2017, net of amounts amortized during 2018.

Deferred pension and other postretirement benefit costs. Primarily represents cash contributions in excess of postretirement benefit expense that is deferred as a regulatory liability by certain subsidiaries in accordance with regulatory orders.

Cost Recovery and Trackers

Comparability of our line item operating results is impacted by regulatory trackers that allow for the recovery in rates of certain costs such as those described below. Increases in the expenses that are the subject of trackers generally result in a corresponding increase in operating revenues and therefore have essentially no impact on total operating income results.

Certain costs of our operating companies are significant, recurring in nature and generally outside the control of the operating companies. Some states allow the recovery of such costs through cost tracking mechanisms. Such tracking mechanisms allow for abbreviated regulatory proceedings in order for the operating companies to implement charges and recover appropriate costs. Tracking mechanisms allow for more timely recovery of such costs as compared with more traditional cost recovery mechanisms. Examples of such mechanisms include GCR adjustment mechanisms, tax riders, bad debt recovery mechanisms, electric energy efficiency programs, MISO non-fuel costs and revenues, resource capacity charges, federally mandated costs and environmental-related costs.

A portion of the Gas Distribution revenue is related to the recovery of gas costs, the review and recovery of which occurs through standard regulatory proceedings. All states in our operating area require periodic review of actual gas procurement activity to determine prudence and to permit the recovery of prudently incurred costs related to the supply of gas for customers. Our distribution companies have historically been found prudent in the procurement of gas supplies to serve customers.

A portion of the Electric Operations revenue is related to the recovery of fuel costs to generate power and the fuel costs related to purchased power. These costs are recovered through a FAC, a quarterly regulatory proceeding in Indiana.

Infrastructure Replacement and Federally-Mandated Compliance Programs

Certain of our operating companies have completed rate proceedings involving infrastructure replacement or enhancement or are embarking upon regulatory initiatives to replace significant portions of their operating systems that are nearing the end of their useful lives. Each operating company's approach to cost recovery may be unique, given the different laws, regulations and precedent that exist in each jurisdiction.

Columbia of Ohio, IRP - On December 3, 2008, the PUCO issued an order which established Columbia of Ohio’s IRP. Pursuant to that order, the IRP provides for recovery of costs resulting from: (1) the maintenance, repair and replacement of customer-owned service lines that have been determined by Columbia of Ohio to present an existing or probable hazard to persons and property; (2) Columbia of Ohio’s replacement of cast iron, wrought iron, unprotected coated steel and bare steel pipe and associated company and customer-owned metallic service lines; (3) the replacement of customer-owned natural gas risers identified by the PUCO as prone to failure; and (4) the installation of AMR devices on all residential and commercial meters served by Columbia of Ohio. Recoverable costs include a return on investment, depreciation and property taxes, offset by specified cost savings. Columbia of Ohio’s five-year IRP plan renewal was last approved on January 31, 2018 for the years 2018-2022.

NIPSCO Gas and Electric, TDSIC - On April 30, 2013, the Indiana Governor signed Senate Enrolled Act 560, known as the TDSIC statute, into law. Among other provisions, the TDSIC statute provides for cost recovery outside of a base rate proceeding for new or replacement electric and gas transmission, distribution, and storage projects that a public utility undertakes for the purposes of safety, reliability, system modernization or economic development. Provisions of the TDSIC statute require that, among other things, requests for recovery include a seven-year plan of eligible investments. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the TDSIC mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. The semi-annual rate adjustment mechanism is capped at an annual increase of two percent of total retail revenues.

NIPSCO Electric, ECRM - NIPSCO has approval from the IURC to recover certain environmental related costs through an ECT (environmental cost tracker). Under the ECT, NIPSCO is permitted to recover (1) AFUDC and a return on the capital investment expended by NIPSCO to implement environmental compliance plan projects and (2) related operation and maintenance and depreciation expenses once the environmental facilities become operational.

NIPSCO Gas and Electric, FMCA - The FMCA statute provides for cost recovery outside of a base rate proceeding for projected federally mandated costs. Once the plan is approved by the IURC, eighty percent of eligible costs can be recovered using a periodic rate adjustment mechanism, known as the FMCA mechanism. Recoverable costs include a return on the investment, including AFUDC, PISCC, mandated operation and maintenance expenses, depreciation and property taxes. The remaining twenty percent of recoverable costs are deferred for future recovery in NIPSCO's next general rate case. Actual costs that exceed the projected federally mandated costs of the approved compliance project by more than twenty-five percent shall require specific justification by NIPSCO and specific approval by the IURC before being authorized in the next general rate case.

Columbia of Massachusetts, GSEP - On July 7, 2014, the Governor of Massachusetts signed into law Chapter 149 of the Acts of 2014, an Act Relative to Natural Gas Leaks (“the Act”). The Act authorizes natural gas distribution companies to file a GSEP for capital investments made on or after January 1, 2015, that are not included in the Company’s current rate base as determined in the most recent base rate case, with the Massachusetts DPU to (1) address the replacement or improvement of existing aging natural gas pipeline infrastructure to improve public safety or infrastructure reliability, and (2) reduce the lost and unaccounted for natural gas through a reduction in natural gas system leaks. In addition, the Act provides that the Massachusetts DPU may, after review of the plan, allow the proposed estimated costs of the plan into rates as of May 1 of the subsequent year. Recoverable costs include a return on investment, depreciation and property taxes, offset by identified operations and maintenance cost savings. Rates are subject to a capped annual revenue increase of one and a half percent of total annual delivery and cost of gas revenues from sales and transportation, including imputed gas revenues for transportation, for the calendar year preceding the projected GSEP calendar year being filed. At the end of each 12-month period, in May of the subsequent year, Columbia of Massachusetts must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers over a 12-month period beginning in November. Once new base rates are established under a base rate proceeding, the GSEP factor is re-set to remove the capital investment and associated revenue reflected in the base rates.

Columbia of Pennsylvania, DSIC - On February 14, 2012, the Governor of Pennsylvania signed into law Act 11 of 2012, which provided a DSIC mechanism for certain utilities to recover costs related to repair, replacement or improvement of eligible distribution property that has not previously been reflected in rates or rate base. Through a DSIC, a utility may recover the fixed costs of eligible infrastructure incurred during the three months ended one month prior to the effective date of the charge, thereby reducing the historical regulatory lag associated with cost recovery through the traditional rate-making process. On March 14, 2013, the Pennsylvania PUC approved Columbia of Pennsylvania’s petition to implement a DSIC as of April 1, 2013. Accordingly, Columbia of Pennsylvania is authorized to recover the cost of eligible plant associated with repair, replacement or improvement that was not previously reflected in rate base and has been placed in service during the applicable three-month period. After the initial charge is established, the DSIC is updated quarterly to recover the cost of further plant additions and cannot exceed five percent of distribution revenues. Recoverable costs include a return on investment, exclusive of accumulated deferred income taxes from the calculation of rate base, and depreciation. Once new base rates are established under a base rate proceeding, the DSIC is set to zero. Additionally, the DSIC rate is also reset to zero if, in any quarter, the data reflected in the Columbia of Pennsylvania's most recent quarterly financial earnings report show that the utility will earn an overall rate of return that would exceed the allowable rate of return used to calculate its fixed costs under the DSIC mechanism. A utility is exempt from filing a quarterly financial earnings report when a base rate proceeding is pending before the Pennsylvania PUC.

Columbia of Virginia, SAVE - On March 11, 2010, the Virginia Governor signed legislation into law that allows natural gas utilities to implement programs to replace qualifying infrastructure on an expedited basis and provides for timely cost recovery. Known as the SAVE Act, the law allows natural gas utilities to file programs with the VSCC providing a timeline and estimated costs for replacing eligible infrastructure. Eligible infrastructure replacement projects are those that (1) enhance safety or reliability by reducing system integrity risks associated with customer outages, corrosion, equipment failures, material failures, or natural forces; (2) do not increase revenues by directly connecting the infrastructure replacement to new customers; (3) reduce or have the potential to reduce greenhouse gas emissions; (4) are not included in the natural gas utility’s rate base in its most recent rate case; and (5) are commenced on or after January 1, 2010. The SAVE Act provides for recovery of costs associated with the eligible infrastructure through a rate rider. Recoverable costs include a return on investment, depreciation and property taxes. Columbia of Virginia’s current five year SAVE plan was approved by the VSCC in 2016 and amended in 2017 for the years 2016 through 2020.

Columbia of Kentucky, AMRP - On October 26, 2009, the Kentucky PSC approved a mechanism for recovering the costs of Columbia of Kentucky’s AMRP not previously reflected in rate base through an annual fixed monthly rate rider filed in October. In its 2013 rate case, Columbia of Kentucky was allowed to base the AMRP rider on the expected annual cost of service. Recoverable costs include a return on investment, depreciation and property taxes, offset by specific cost savings. At the end of each 12-month period, Columbia of Kentucky must file a reconciliation of the amount collected and actual costs. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge over a 12-month period beginning in June of the subsequent year. Once new base rates are established under a base rate proceeding, the AMRP rider is set to zero.

Columbia of Maryland, STRIDE - On May 2, 2013, the Governor of Maryland signed Senate Bill 8 into law, authorizing gas companies to accelerate recovery of eligible infrastructure replacement, effective June 1, 2013. The STRIDE statute provides recovery for gas pipeline upgrades outside of the context of a base rate proceeding through an annual surcharge, IRIS, as approved by, Maryland PSC. The STRIDE statute directs gas utilities to file a plan to invest in eligible infrastructure replacement projects and to list the specific projects and elements in any such STRIDE plan with the Maryland PSC. The calendar year projected capital projects to be placed into plant in service and included in Columbia of Maryland's surcharge recovery request must satisfy a number of criteria per the statute, including a requirement that they be designed to improve public safety or infrastructure reliability. Columbia of Maryland’s five-year STRIDE Plan renewal for years 2019 through 2023, as with the preceding five years, is focused on replacing (1) existing cast iron and bare steel mains, (2) associated services and meters, and (3) identified prone-to-failure vintage plastic piping. Columbia of Maryland’s IRIS mechanism recovers a return on investment, depreciation and property taxes of the STRIDE-eligible capital infrastructure statutorily capped at $2 per month for residential customers, and proportionally capped for commercial and industrial customer classes, and is reconciled to actual costs on an annual basis. Any over-collection or under-collection balance is passed back to, or recovered from, customers through the surcharge effective in May of the subsequent year.

The following table describes regulatory programs to recover infrastructure replacement and other federally-mandated compliance investments currently in rates and those pending commission approval:



(in millions)
Company	Program	Incremental Revenue			Incremental Capital Investment		Investment Period	Filed	Status	Rates Effective
Columbia of Ohio	IRP - 2018⁽¹⁾	$	2.3		$	207.0	1/17-12/17	February 27, 2018	Approved April 25, 2018	May 2018
NIPSCO - Gas	TDSIC 7	$	1.5		$	59.0	1/17-6/17	August 31, 2017	Approved December 28, 2017	January 2018
NIPSCO - Gas	TDSIC 8	$	1.8		$	54.0	7/17-12/17	February 27, 2018	Approved August 22, 2018	September 2018
NIPSCO - Gas	TDSIC 9⁽¹⁾⁽²⁾	$	(10.6	)	$	54.4	1/18 - 6/18	August 28, 2018	Approved December 27, 2018	January 2019
NIPSCO - Gas	FMCA 1	$	9.9		$	1.5	11/17-9/18	November 30, 2018	Order Expected Q1 2019	April 2019
Columbia of Massachusetts	GSEP - 2018⁽¹⁾⁽³⁾	$	6.5		$	80.0	1/18-12/18	October 31, 2017	Approved April 30, 2018	May 2018
Columbia of Massachusetts	GSEP - 2019⁽⁴⁾	$	10.7		$	64.0	1/19-12/19	October 31, 2018	Order expected Q2 2019	May 2019
Columbia of Pennsylvania	DSIC - 2018	$	0.4		$	14.8	12/17-2/18	March 22, 2018	Approved March 29, 2018	April 2018
Columbia of Pennsylvania	DSIC - 2018	$	0.9		$	31.8	3/18-5/18	June 20, 2018	Approved June 28, 2018	July 2018
Columbia of Pennsylvania	DSIC - 2018	$	1.6		$	55.4	6/18-8/18	September 20, 2018	Approved September 28, 2018	October 2018
Columbia of Virginia	SAVE - 2018	$	2.9		$	33.3	1/18-12/18	August 18, 2017	Approved December 13, 2017	January 2018
Columbia of Virginia	SAVE - 2019	$	2.4		$	36.0	1/19-12/19	August 17, 2018	Approved October 26, 2018	January 2019
Columbia of Kentucky	AMRP - 2018	$	4.5		$	24.0	1/18-12/18	October 13, 2017	Approved December 22, 2017	January 2018
Columbia of Kentucky	AMRP - 2019	$	3.6		$	30.1	1/19-12/19	October 15, 2018	Approved December 5, 2018	January 2019
Columbia of Maryland	STRIDE - 2018	$	1.2		$	20.8	1/18-12/18	November 1, 2017	Approved December 20, 2017	January 2018
Columbia of Maryland	STRIDE - 2019	$	1.2		$	19.7	1/19-12/19	November 1, 2018	Approved December 12, 2018	January 2019
NIPSCO - Electric	TDSIC - 3	$	(2.0	)	$	75.0	5/17-11/17	January 30, 2018	Approved May 30, 2018	June 2018
NIPSCO - Electric	TDSIC - 4⁽¹⁾	$	(11.8	)	$	72.2	12/17-5/18	July 31, 2018	Approved November 28, 2018	December 2018
NIPSCO - Electric	TDSIC - 5⁽¹⁾	$	15.9		$	58.8	6/18-11/18	January 29, 2019	Order Expected Q2 2019	June 2019
NIPSCO - Electric	ECRM - 31	$	(2.1	)	$	2.9	6/17-12/17	January 31, 2018	Approved April 25, 2018	May 2018
NIPSCO - Electric	ECRM - 32	$	1.0		$	—	1/18-6/18	July 31, 2018	Approved October 11, 2018	November 2018
NIPSCO - Electric	FMCA - 8	$	1.3		$	4.4	4/17-9/17	November 1, 2017	Approved January 31, 2018	February 2018
NIPSCO - Electric	FMCA - 9	$	4.1		$	90.2	10/17-3/18	April 27, 2018	Approved July 25, 2018	August 2018
NIPSCO - Electric	FMCA - 10	$	2.2		$	45.7	4/18-8/18	October 18, 2018	Approved January 29, 2019	February 2019

⁽¹⁾Incremental revenue is net of amounts due back to customers as a result of the TCJA.

⁽²⁾Incremental revenue is net of $5.2 million of adjustments in the TDSIC-9 settlement.

⁽³⁾A cap waiver was approved by the Massachusetts DPU on June 21, 2018 and related rates became effective July 2018.

⁽⁴⁾The filing included a request for approval of a waiver to allow collection of the $2.9 million revenue requirement that exceeds the GSEP cap provision.

Rate Case Actions

The following table describes current rate case actions as applicable in each of our jurisdictions net of tracker impacts:



(in millions)
Company	Requested Incremental Revenue		Approved Incremental Revenue		Filed	Status	Rates Effective
NIPSCO - Gas⁽¹⁾	$	138.1	$	107.3	September 27, 2017	Approved September 19, 2018	October 2018
Columbia of Massachusetts	$	24.1	N/A		April 13, 2018	Withdrawn September 19, 2018	N/A
Columbia of Pennsylvania	$	46.9	$	26.0	March 16, 2018	Approved December 6, 2018	December 2018
Columbia of Virginia⁽²⁾	$	14.2	In process		August 28, 2018	Order expected Second half of 2019	February 2019
Columbia of Maryland	$	4.6	$	2.2	April 13, 2018	Approved November 21, 2018	November 2018
NIPSCO - Electric	$	21.4	In process		October 31, 2018	Order expected Q3 2019	September 2019

⁽¹⁾Rates will be implemented in three steps, with implementation of step 1 rates effective October 1, 2018. Step 2 rates will be effective on or about March 1, 2019, and step 3 rates will be effective on January 1, 2020. The IURC’s order also dismissed NIPSCO from phase 2 of the IURC’s TCJA investigation.

⁽²⁾Rates implemented subject to refund pending a final order from the VSCC.

Additional Regulatory Matters

Columbia of Ohio. On December 1, 2017, Columbia of Ohio filed an application that requested authority to implement a rider to begin recovering plant and associated deferrals related to its CEP. The CEP was established in 2011 and allows for deferral of interest, depreciation and property taxes on certain plant investments not recovered through its IRP modernization tracker. The application requested authority to increase annual revenues, through the requested rider, by approximately $70 million, with biennial increases up to approximately $98 million in 2022. On May 9, 2018, the PUCO appointed an independent auditor to assist the PUCO with the review of the accounting accuracy, prudency and compliance of Columbia of Ohio with its PUCO-approved CEP deferrals. The independent audit report was filed on September 4, 2018 and the PUCO Staff's Report on the investigation was filed on September 14, 2018. On October 25, 2018, a joint stipulation and recommendation was filed recommending an initial revenue requirement of $74.5 million to recover CEP investments and deferrals through December 31, 2017, with annual adjustments for capital investments made in subsequent years. Additionally, the signatory parties to the stipulation agreed to a reduction in rates to adjust for the impacts of the TCJA and for a base rate case filing to be made by Columbia of Ohio with a test period of calendar year 2021. On November 28, 2018 the PUCO issued an order unanimously approving the settlement filed on October 25, 2018, without modification, for rates effective beginning November 29, 2018. This order finalizes Columbia of Ohio's TCJA resolution related to the CEP tracker, as well as base rates.

NIPSCO Gas. On November 8, 2017, NIPSCO filed a petition with the IURC seeking approval of NIPSCO’s federally mandated pipeline safety compliance plan. As part of the settlement agreement filed in NIPSCO’s gas base rate case proceeding, NIPSCO and the parties to the settlement agreement settled all issues in this proceeding as well, including moving certain costs from the base rate proceeding to this pipeline safety compliance plan. The updated four year compliance plan includes a total estimated $91.5 million of capital costs and $35.5 million of expected operating and maintenance costs. NIPSCO received approval for accounting and rate-making relief, including establishment of a periodic rate adjustment mechanism. NIPSCO filed the first tracker proceeding in this case on November 30, 2018. On December 31, 2018, NIPSCO filed a petition with the IURC seeking approval of an additional PHMSA compliance plan including capital expenditures of $228.8 million. An IURC order is expected in the second half of 2019.

On January 3, 2018, the IURC initiated an investigation to review and consider the possible implications of the TCJA on utility rates. The IURC ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. In accordance with the procedural schedule, on March 26, 2018, NIPSCO filed revised gas tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's Phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. The stipulation and settlement agreement filed on April 20, 2018, in NIPSCO’s gas rate case resolved all issues in Phase 2, including the return of excess income tax revenue recovered through its base rates and any applicable charges between January 1, 2018 and April 30, 2018. Beginning January 2019, and continuing through June 2019, NIPSCO is passing back the excess tax expense through the TDSIC mechanism.

On December 27, 2018, the IURC issued an order for TDSIC-9 approving the settlement agreement filed on November 4, 2018. This order, along with the Court of Appeals dismissal on December 31, 2018 and January 8, 2019, resolved all outstanding issues related to the appeals of TDSIC-4 though TDSIC-8.

Columbia of Massachusetts. On October 9, 2018, Columbia of Massachusetts filed an application with the Massachusetts DPU, seeking authority to pass back approximately $95.8 million in excess deferred taxes associated with TCJA with an effective date of rates to be determined by the Massachusetts DPU. On December 21, 2018 the Massachusetts DPU issued an order approving the treatment of TCJA-related excess deferred taxes. Columbia Gas of Massachusetts filed a compliance filing on January 4, 2019, reflecting revised LDAF rates inclusive of credit factors to return excess deferred taxes associated with TCJA to customers for rates effective on February 1, 2019, per the Massachusetts DPU’s order.

Columbia of Kentucky. On April 30, 2018, Columbia of Kentucky received an order from the Kentucky PSC requiring implementation of interim proposed rates effective May 1, 2018 reflecting the impact of TCJA subject to future adjustment. The order directed Columbia of Kentucky to file, by September 1, 2018, revised TCJA adjustment factors reflecting the tax expense savings from January 1, 2018 through April 30, 2018, and an estimate of the annual reduction due to the excess deferred taxes to be effective with the first billing cycle of October 2018. On August 31, 2018, Columbia of Kentucky filed updated rate schedules with the Kentucky PSC for rates proposed to be effective October 1, 2018. On October 25, 2018, the Kentucky PSC authorized the TCJA adjustment factors, as proposed, with an October 29, 2018 effective date to pass-back the overcollection of taxes over a six month period.

Columbia of Maryland. On February 13, 2018, Columbia of Maryland filed a proposal with the Maryland PSC to reduce rates as a result of TCJA with an annual revenue decrease of $1.3 million. Columbia of Maryland was directed to account for any revenues associated with the difference between previous and current income tax rates and excess deferred taxes as regulatory liabilities effective January 1, 2018. On March 14, 2018, Columbia of Maryland received approval, effective April 2, 2018, to implement new rates and pass-back the overcollection of taxes from the first quarter of 2018 over a seven month period.

NIPSCO Electric. On October 31, 2018, NIPSCO submitted its 2018 Integrated Resource Plan with the IURC. The plan evaluated demand-side and supply-side resource alternatives to reliably and cost effectively meet NIPSCO customers' future energy requirements over the ensuing 20 years. Refer to Note 18-E, "Other Matters," in the Notes to Consolidated Financial Statements for additional information.

On March 29, 2018, WCE, which is currently owned by BP p.l.c ("BP") and BP Products North America, which operates the BP Refinery, filed a petition at the IURC asking that the combined operations of WCE and BP be treated as a single premise, and the WCE generation be dedicated primarily to BP Refinery operations beginning in May 2019 as WCE has self-certified as a qualifying facility at FERC. BP Refinery planned to continue to purchase electric service from NIPSCO at a reduced demand level beginning in May 2019. A settlement agreement was filed on November 2, 2018 agreeing that BP and WCE would not move forward with construction of a private transmission line to serve BP until conclusion of NIPSCO’s pending electric rate case.

On February 1, 2018, NIPSCO and certain other MISO transmission owners filed with the FERC a request for waiver of tariff provisions to allow for implementation of TCJA tax rate change provisions into 2018 transmission formula rates. On March 15, 2018, the FERC issued an order granting the request for waiver and set the effective date of the waiver at January 1, 2018. In the March billing cycle, the MISO began billing the new transmission rates reflecting the lower federal tax rate. In addition, the MISO began to re-bill January and February 2018 affected revenues and costs in the March 2018 billing cycle, and completed the re-settlement in the April 2018 billing cycle. The new 2018 transmission formula rates will reduce revenue by $8.5 million in 2018 associated with NIPSCO's multi-value projects. Additionally, on November 1, 2018, MISO submitted revised tariffs to provide for adjustments to income tax, including accumulated deferred income tax, resulting from tax law or rate changes. On December 20, 2018, FERC accepted the submission, effective January 1, 2019, as requested.

As noted above in the NIPSCO Gas regulatory matters, the IURC initiated an investigation on January 3, 2018, to review and consider the implications of the TCJA on utility rates. The commission ordered a two phase investigation. Phase 1 solely dealt with the prospective changes in rates to reflect the change in tax rates. On March 26, 2018, NIPSCO filed revised electric tariffs reflecting the impact of the change in tax rate for its applicable rates and charges. The IURC approved NIPSCO's phase 1 filing on April 26, 2018. The revised tariffs were effective May 1, 2018. On July 31, 2018, NIPSCO filed an unopposed motion requesting that the over-collection of income taxes from January 1, 2018 through April 30, 2018 be passed back in NIPSCO’s TDSIC-4 filing, also filed on July 31, 2018, and requesting that all other phase 2 issues be handled in a rate case filing to be made in the fourth quarter of 2018. On August 15, 2018, the IURC approved the motion to pass back the over-collection through the TDSIC-4 rates effective December 2018 through May 2019. All other phase 2 issues are addressed in the base rate case filed October 31, 2018.