RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

Rate Case Filing: In December 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. The Delaware Division, Delaware PSC Staff, the Division of the Public Advocate and other intervenors met and reached a settlement agreement in November 2016. The terms of the settlement agreement include an annual increase of $2.25 million in base rates. The order became final in December 2016, and the new rates became effective January 1, 2017. Amounts collected through interim rates in excess of $2.25 million have been accrued for refund as of December 31, 2016 and will be distributed to ratepayers beginning in the first quarter of 2017. We recognized incremental revenue of approximately $1.5 million ($897,000 net of tax) in 2016.

Maryland

Sandpiper Rate Case Filing: In May 2013, the Maryland PSC approved our application to acquire ESG operating assets and the transfer of the ESG franchise to Sandpiper. As part of this application, the Maryland PSC directed that Sandpiper file a base rate proceeding within two years, six months. As a result, in December 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. The parties reached a settlement agreement, which Sandpiper filed with the Maryland PSC in August 2016. The terms of the agreement include revenue neutral rates for the first year, followed by a schedule of rate reductions in subsequent years based upon the projected rate of propane to natural gas conversions. A revenue normalization mechanism and stratification of rate classes were also included in the settlement agreement. The order became final in October 2016 with the new rates effective December 1, 2016.

Florida

In September 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held in December 2015. In January 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs were filed by the Florida PSC, FPU, and the Office of Public Counsel and oral arguments were heard by the Florida Supreme Court in November 2016. To date, the Court has not issued a decision.

In February 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held in April 2016.

In April 2016, FPU’s natural gas divisions and Chesapeake Utilities' Florida division filed a joint petition for approval to allow FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchased gas adjustment and operational balancing account, which is currently allocated to a limited number of customers. The expanded allocation of these costs includes additional customers, primarily transportation customers, benefiting from these costs but not currently paying for them. This petition was approved by the Florida PSC at its Agenda Conference in September 2016.

In July 2016, Chesapeake Utilities' Florida division filed for approval of the final environmental true-up relating to expected future remediation costs at our former MGP site in Winter Haven, Florida. This petition was approved by the Florida PSC in December 2016.

In February, 2017, FPU’s electric division filed a petition with the Florida PSC, requesting a temporary surcharge mechanism to recover costs, inclusive of an appropriate return on investment, associated with an essential reliability and modernization project on its electric distribution system. We are seeking approval to invest approximately $59.8 million, over a five-year period associated with this project. In February, 2017, the Office of Public Counsel intervened in this petition. The outcome of our petition is not known at this time.

Eastern Shore

White Oak Mainline Expansion Project: In November 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposed to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware.

In November 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route and shortened the total miles of the proposed pipeline to 5.4 miles.

In July 2016, the FERC authorized Eastern Shore to construct and operate the proposed White Oak Mainline Project. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment in the certificate proceeding. However, FERC’s determination is without prejudice to Eastern Shore filing rolled-in rate treatment of these project facilities in a future general rate case. The certificate required Eastern Shore to comply with 19 environmental conditions.

In July 2016, Eastern Shore accepted the certificate of public convenience and necessity and, in August 2016, filed its Implementation Plan to comply with each environmental condition and to request approval to begin construction. In August 2016, the FERC issued a “Notice to Proceed,” and Eastern Shore commenced construction during August 2016.

In December 2016, Eastern Shore filed a request to place the pipeline looping located in Chester County, Pennsylvania into service. The FERC granted approval to place the Daleville and Kemblesville Loops into operation in December 2016. Construction is continuing on the remaining component of the project, the Delaware City Compressor Station, which is expected to be completed and in service in March 2017. The entire project, when completed, is expected to cost $39.8 million. Eastern Shore continues to file weekly status reports with the FERC in compliance with the environmental conditions.

System Reliability Project: In May 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project. In July 2016, the FERC ordered that Eastern Shore’s request for a determination of rolled-in rate treatment may be addressed in its next rate base proceeding and required Eastern Shore to comply with 19 environmental conditions.

In September 2016, the FERC granted approval to start construction on all phases of the project. Construction commenced on the Bridgeville Compressor Station and the Porter Road Loop in August 2016 and on the Dover Loop in September 2016.

In December 2016, Eastern Shore filed a request to place the pipeline looping located in New Castle County, Delaware into service. The FERC granted approval to place the Porter Road Loop into service in December 2016. The remaining components of the project, the Bridgeville Compressor Station and the Dover Loop, are anticipated to be completed by the end of April 2017. Eastern Shore continues to file weekly status reports with the FERC in compliance with the environmental conditions. The estimated cost of the project is $36.0 million.

2017 Expansion Project: In May 2016, Eastern Shore submitted a request to the FERC to initiate the FERC’s pre-filing review procedures for Eastern Shore's 2017 expansion project. The expansion project's facilities include approximately23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional 3,550 horsepower compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. In May 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore entered into Precedent Agreements with four existing customers as well as Chesapeake affiliates, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

In December 2016, Eastern Shore submitted an application for a certificate of public convenience and necessity seeking authorization to construct the expansion facilities. Interventions or comments were accepted through February 1, 2017. Six of Eastern Shore's existing customers have intervened to become parties to the docket, and comments have been submitted by two landowners. FERC has issued two sets of data requests to assist in its evaluation of the project. Eastern Shore submitted responses to both data request sets on February 14, 2017. Upon receipt and evaluation of the environmental-related responses, FERC will be able to establish a schedule for completing its environmental assessment on the project. The estimated cost of this expansion project is $98.6 million.

2017 Rate Case Filing

In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates are based on the mainline cost of service of approximately $60 million resulting in an overall revenue increase of approximately $18.9 million and a rate of return on common equity of 13.75 percent. In addition to the mainline cost of service, the filing includes incremental rates for the White Oak Mainline Expansion and Lateral projects. Eastern Shore is also proposing to revise its depreciation rates and negative salvage rate based on the results of independent, third party depreciation and negative salvage value studies. The FERC issued a notice of the filing in January 2017, and the comment period ended in February 2017. Fourteen parties intervened in the proceeding with six of those parties filing protests. New rates are proposed to be effective on March 1, 2017, however, the FERC typically suspends the rates for a period of five months. At the end of the suspension period, Eastern Shore will file a motion to implement new rates, subject to refund, effective August 1, 2017.

At December 31, 2016 and 2015, the regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.



	As of December 31,
	2016		2015
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery ⁽¹⁾	$	5,703	$	4,598
Under-recovered GRIP revenue ⁽²⁾	1,469		3,091
Deferred postretirement benefits ⁽³⁾	18,379		19,479
Deferred conversion and development costs ⁽¹⁾	8,051		5,729
Environmental regulatory assets and expenditures ⁽⁴⁾	3,694		4,158
Acquisition adjustment ⁽⁵⁾	41,864		43,735
Loss on reacquired debt ⁽⁶⁾	1,145		1,259
Other	4,192		3,738
Total Regulatory Assets	$	84,497	$	85,787


Regulatory Liabilities
Self-insurance ⁽⁷⁾	$	987	$	1,031
Over-recovered purchased fuel and conservation cost recovery ⁽¹⁾	808		6,994
Storm reserve ⁽⁷⁾	2,310		2,973
Accrued asset removal cost ⁽⁸⁾	39,826		39,206
Other	424		225
Total Regulatory Liabilities	$	44,355	$	50,429


⁽¹⁾	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

⁽²⁾

The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade and Chesapeake’s Florida division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.


⁽³⁾	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.


⁽⁴⁾	All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

⁽⁵⁾

We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.


⁽⁶⁾	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.


⁽⁷⁾	We have self-insurance and storm reserves in our Florida regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.


⁽⁸⁾	See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.