Docket No. 110133-GU
Date: November 9, 2011

Table of Contents

Issue		Description		Page
		Case Background			3
1		Reporting Requirements (Slemkewicz, Young)			5
2		Positive Acquisition Adjustment (Slemkewicz, Springer, Salnova)			6
3		Regulatory Assets (Slemkewicz)			13
4		Straight-line Amortization Method (Kaproth, Slemkewicz)			16
5		Earnings Surveillance Report Consolidation (Slemkewicz)			18
6		Benchmark Mechanism (Kaproth)			20
7		Excess Earnings — Chesapeake (Slemkewicz)			21
8		Excess Earnings — FPUC (Slemkewicz, Springer)			22
9		Disposition of 2010 Excess Earnings (Slemkewicz, Draper)			23
10		Close Docket (Young)			24
		Attachment A			25
		Attachment B			26
		Attachment C			27

Docket No. 110133-GU
Date: November 9, 2011

Case Background

On October 28, 2009, Chesapeake Utilities Corporation (Chesapeake) and Florida Public Utilities Company (FPUC) announced their corporate merger, whereby the electric and gas operations of FPUC became a wholly owned subsidiary of Chesapeake. On November 5, 2009, pursuant to Rule 25-9.044(1), Florida Administrative Code (F.A.C.), Chesapeake notified the Commission of its acquisition of FPUC.

The existing Florida Division of Chesapeake Utilities Corporation (Florida Division), which provides service under the fictitious name “Central Florida Gas Company,” continues to operate its natural gas distribution utility using the rates, rales, and classifications on file with this Commission. With this acquisition of FPUC in 2009, Chesapeake expanded its energy presence throughout the state of Florida. Although often referred to as the “merger” of these companies, Chesapeake actually acquired FPUC through a stock transaction, as opposed to a cash purchase of the assets. Though technically this is an “acquisition” of FPUC by Chesapeake, the terms “merger” and “acquisition” are used interchangeably in this staff recommendation.

The newly acquired subsidiary, FPUC, continues to operate under the name “Florida Public Utilities Company,” with the rates, rules and classifications currently on file with the Commission for both the natural gas utility business and the electric utility business. On August 6, 2010, FPUC acquired Indiantown Gas Company and with it, approximately 700 additional customers. At the time of the acquisition by Chesapeake in October 2009, FPUC served approximately 51,000 natural gas distribution customers and 31,000 electric distribution customers in various parts of Florida. Chesapeake’s Florida Division served approximately 14,500 natural gas distribution customers at that time.

FPUC shareholders received 0.405 shares of Chesapeake common stock in exchange for each outstanding share of FPUC common stock. Chesapeake issued 2,487,910 shares of its common stock to redeem all outstanding FPUC common shares. The market price of Chesapeake stock at the time of the transaction was $30.42. The value of consideration exchanged for FPUC common shares was $75,698,624. This included $16,402 cash paid in lieu of issuing partial shares. Chesapeake also assumed FPUC’s short-term debt of $4,249,000 and long-term debt of $47,812,431. Thus, the total value of Chesapeake stock issued, cash paid and FPUC debt assumed in the acquisition was $127,760,055. The transaction between Chesapeake and FPUC, which was an exchange of stock rather than a sale of assets, was treated as a tax-free reorganization for income tax purposes in accordance with the Internal Revenue Code Section 368(a). Under a tax-free reorganization, the premium paid for the acquisition is considered to be capitalized as part of the investment basis and therefore, it is not deducted or amortized for income tax purposes.

Of the $127,760,055 total acquisition amount, $88,276,234 has been allocated to the FPUC natural gas operations. The book value of the FPUC natural gas business was $53,596,487 at the time of the acquisition. The purchase price paid by Chesapeake exceeded the book value of the acquired assets by $34,679,747.

Docket No. 110133-GU
Date: November 9, 2011

When Ernst and Young (E&Y) performed a valuation of FPUC (total company), it determined the fair value to be $127,600,000. This valuation of the total invested capital was based on the Discounted Cash Flow Method of the Income Approach and the Guideline Company Method of the Market Approach.¹ E&Y allocated 70 percent of the total purchase price to the natural gas operations, 24 percent to electric, and 7 percent to the propane business. E&Y used the same valuation methodology for each segment of the company.

Though the premium, which is the difference between the purchase price and book value of the acquired assets was $34,679,747, Chesapeake is asking for an acquisition adjustment of $34,192,493, the lower of the two amounts. The difference between the two amounts is the result of various accounting adjustments which include, but not limited to, the elimination of goodwill and other intangible assets and loss on reacquired debt. Though Chesapeake purchased all of FPUC, this recommendation pertains only to the part of the acquisition premium that has been allocated to FPUC’s natural gas operations.

This recommendation addresses the reporting requirements in Order No. PSC-10-0029-PAA-GU² and Chesapeake’s request for the recognition of a positive acquisition adjustment and associated regulatory assets on the books of FPUC Consolidated Natural Gas to reflect the purchase of FPUC by Chesapeake Utilities Corporation. In addition, Chesapeake seeks consolidation of certain regulatory filings for the Florida Division and FPUC, as well as approval of a benchmark mechanism for assessing, in future proceedings, incremental cost increases. At this time, Chesapeake is not requesting approval of any rate adjustment.

The Commission has jurisdiction over this matter pursuant to Sections 366.06 and 366.076, Florida Statutes (F.S.).

Docket No. 110133-GU
Date: November 9, 2011

Discussion of Issues

Issue 1: Has Chesapeake complied with the reporting requirements of Order No. PSC-10-0029-PAA-GU?

Recommendation: Yes. Chesapeake has complied with the reporting requirements of Order No. PSC-10-0029-PAA-GU. (Slemkewicz, Young)

Staff Analysis: In Order No. PSC-10-0029-PAA-GU, Chesapeake was ordered to submit data to this Commission no later than April 29, 2011, detailing all known benefits, synergies, and cost savings that have resulted from the merger of Chesapeake and FPUC. Chesapeake was also ordered to identify any costs that have increased as a result of the merger.

On April 29, 2011, Chesapeake filed said post-merger data along with expert testimony documenting the benefits, synergies, cost savings, as well as cost increases, associated with the acquisition of FPUC by Chesapeake. Therefore, staff believes that Chesapeake has complied with the reporting requirements of Order No. PSC-10-0029-PAA-GU.

Docket No. 110133-GU
Date: November 9, 2011

Issue 2: Should the Commission accept Chesapeake’s proposal to amortize the $34,192,493 positive acquisition adjustment over a 30 year period, beginning November 2009?

Recommendation: Yes. Chesapeake should be allowed to record the $34,192,493 purchase price premium as a positive acquisition adjustment to be amortized over a 30-year period beginning November 2009. The positive acquisition adjustment should be recorded in Account 114 — Gas Plant Acquisition Adjustments and the amortization expense should be recorded in Account 406 – Amortization of Gas Plant Acquisition Adjustment. The level of the actual cost savings supporting Chesapeake’s request should be subject to review in FPUC’s next rate case proceeding. In FPUC’s next rate proceeding, if it is determined that any of the cost savings no longer exist, the acquisition adjustment may be partially or totally removed as deemed appropriate by the Commission. FPUC should file its earnings surveillance reports with and without the effect of the acquisition adjustment. Chesapeake is not seeking approval of an acquisition adjustment associated with the Indiantown Gas Company transaction at this time. (Slemkewicz, Springer, Salnova)

Staff Analysis: Chesapeake requests the Commission allow it to record the $34,192,493 purchase price premium on the books of FPUC as a positive acquisition adjustment in Account 114 – Gas Plant Acquisition Adjustments and the amortization expense be recorded in Account 406 – Amortization of Gas Plant Acquisition Adjustment. Chesapeake also asks that it be allowed to amortize the recorded amount over a 30-year period beginning November 1, 2009, under a modified straight line amortization schedule which is discussed further in Issue 4. The corporate transaction between FPUC and Chesapeake was actually completed on October 28, 2009, but for purposes of administrative ease, Chesapeake is seeking amortization beginning November 1, 2009.

Chesapeake requests that the acquisition adjustment and the associated annual amortization be included in rate base and cost of service, respectively. Chesapeake believes that this regulatory treatment will more accurately portray Chesapeake’s actual investment and earnings level. Chesapeake is not requesting a rate adjustment associated with the acquisition adjustment at this time. Chesapeake is also requesting authorization to amortize, above the line, the Regulatory Assets for transaction and transition costs in the amount of $2,207,158 over a 5-year period using the proposed modified straight line amortization schedule. Transaction and transition costs are addressed in Issue 3.

Chesapeake recognizes that, in the past, the Commission has generally considered five factors when determining whether recognition of such an adjustment is appropriate for a regulated utility. Those factors are increased quality of service; lower operating costs; increased ability to attract capital for improvements; lower overall cost of capital; and more professional and experienced managerial, financial, technical and operational resources.³

Docket No. 110133-GU
Date: November 9, 2011

To determine if Chesapeake has adequately demonstrated the potential or actual qualitative and quantitative benefits to the customers of Chesapeake and FPUC as a result of the acquisition, staff has analyzed each of the five factors as follows:

1. Increased Quality of Service

FPUC customers are benefitting from increased service quality through Chesapeake’s investments in a new state-of-the-art telephone system, Customer Information System technology, the expansion of bill payment options, physical improvements to the FPUC energy delivery systems that have improved service reliability, and expanded access to web-based information and services. Chesapeake has also implemented a “service quality excellence” program with the goal of providing a positive customer experience every time a customer comes in contact with the organization.

Chesapeake has implemented a Customer Care strategy with a goal to be recognized as an industry leader in the execution of all meter-to-cash activities, including Contact Center services. There are four strategic objectives to Chesapeake’s plan: 1) Customer Centric — excellent service to customers is the number one priority; 2) Consistent Quality — provide professional, courteous, timely and accurate service to every customer in a fair, consistent and accessible manner; 3) Efficient and Effective — measure and improve work processes by implementing innovative ideas, applying appropriate technology, and training staff to be helpful and knowledgeable; and 4) Accountable — use feedback from processes and customers to improve performance. Chesapeake plans to use five key components to support the Customer Care strategy which include consolidation, performance management, development and training, process improvement, and technology.

In June 2010, Chesapeake integrated the Customer Information Systems of Chesapeake’s Florida operations with FPUC’s system, thus providing for the coordination of all Customer Care (customer call centers, billing and collections, and meter reading) and field services activities (service connections and disconnections, meter changes, etc.) that impact customers. As a result, customer inquiries can be handled by virtually any customer representative. Previously, customers would be required to contact specific customer service locations that had access to the specific account information and understood the approved tariff parameters applicable to that customer.

Chesapeake is providing more employee training specifically designed to assist in the understanding of the importance of providing quality customer service, enhancing the skill set of employees so that they have the capabilities to provide such service and mechanisms to assist FPUC in obtaining critical information that will provide the basis for continued improvement. Chesapeake also has expanded their payment locations by contracting with Fiserv, Inc. to accept utility payments at its network of locations, primarily at over 300 Wal-Mart stores in the state. The individual customers do not incur any additional charges or fees at the payment locations to use this service. This is very convenient for customers and provides all customers access to walk-in payment locations. Prior to the merger, walk-in payment options were only available for a relatively small percentage of customers that lived close to an FPUC or Chesapeake office.

Docket No. 110133-GU
Date: November 9, 2011

In examining the customer complaints filed with the Commission, FPUC had 128 complaints filed from November 2006 through October 2009, or an average of 3.6 complaints per month. During the 20 months from November 2009 through June 2011, FPUC experienced 40 complaints, for an average of 2.0 complaints per month. For Chesapeake, the number of customer complaints for the same 36 month pre-merger period was 23 for a monthly average of 0.6 complaints per month. During the 20 month post-merger period, Chesapeake recorded 14 complaints for a monthly average of 0.7. Though Chesapeake’s rate of complaints remained almost constant, the total of Chesapeake and FPUC complaints went from an average of 4.2 complaints per month pre-merger down to 2.7 complaints per month after the merger.

The “Summary of Customer Complaints with the Commission” filed as Exhibit JSS-2 attached to Mr. Jeffrey S. Sylvester’s testimony shows similar results. The difference in the numbers shown on witness Sylvester’s exhibit compared to the information stated above are attributable to the difference in time periods covered. Witness Sylvester’s pre-acquisition numbers included customer complaints from January 1, 2006 through October 2009 for a total of 46 months. His post-acquisition customer complaints only reflected 17 months from November 1, 2009 through March 31, 2011. Exhibit JSS-2 shows a decrease in the average number of customer complaints per month for FPUC from 3.5 (pre-merger) down to 1.7 (post-merger). For Chesapeake, the corresponding monthly average decreases from 0.8 down to 0.6.

2. Lower Operating Costs

Chesapeake states that it has already experienced significant savings across the Florida Division and FPUC. Chesapeake explains that it will have achieved total overall operating savings of $6,255,187 by the end of 2012 (Exhibit TAG-7). The Total Net Operating Cost Savings are outlined below in Table 2-1:

Table 2-1
Total Net Operating Cost Savings

Cost Savings — Capacity		$	941,266
Cost Savings — Cost of Capital			330,124
Cost Savings — Personnel Related			5,425,590
Cost Savings — Corporate			1,116,870
Cost Increases — Personnel Related			(982,707	)
Cost Increases — Corporate & Benefits			(575,956	)
TOTAL Net Operating Cost Savings		$	6,255,187

The $941,266 cost savings relate to the interstate pipeline capacity savings. Prior to the acquisition, FPUC and Chesapeake had contracts for interstate pipeline capacity with both Florida Gas Transmission Company (FGT) and Gulfstream Natural Gas Systems (Gulfstream). These contracts provided for the scheduling of natural gas deliveries from the wellhead to the city gate station. The contracts provided for specific levels of capacity each month, and were subscribed based upon peak customer usage requirements and future growth needs. Prior to the merger, each company contracted for sufficient capacity to meet peak seasonal requirements and for

Docket No. 110133-GU
Date: November 9, 2011

future system growth. An assessment of both the Florida Division’s and FPUC’s contracted capacity quantities indicates that, as a result of the merger, the combined interstate pipeline capacity quantity was greater than the quantity required to provide reliable service and meet the contractual obligations of both companies. Since the Florida Division and FPUC peak demands are not concurrent with each other, excess capacity existed. One of Chesapeake’s capacity reservation contracts expired on July 31, 2010 allowing Chesapeake the opportunity to permanently turn back 25 percent of its existing monthly capacity to FGT. Given that FPUC was able to relinquish capacity to Chesapeake, FPUC effectively reduced its overall capacity costs. All of the capacity savings are passed on to FPUC customers. FPUC’s PGA rates are lower than would otherwise be possible absent this transaction resulting in annual savings attributable to the permanent turn-back of FGT capacity of $941,266.

There have also been personnel related cost savings of $5,425,590. FPUC was organized by geographic location, with a General Manager at each location responsible for that area’s customer service, sales and marketing, engineering, and operations. Chesapeake was organized functionally, with a director or manager responsible for their respective function throughout the state. Chesapeake decided to follow the functional approach which has resulted in the elimination of many duplicated activities. This allowed both FPUC and Chesapeake to implement efficiency improvements, redefine job duties and responsibilities, begin to implement “best practices” throughout the business, and eliminate marginal or unnecessary activities. Chesapeake also initiated a Voluntary Reduction in Force (RIF) program to eliminate additional positions. The combination of these personnel changes and RIF have resulted in the elimination of 106 total positions from Chesapeake’s organizational chart reducing its natural gas operating costs.

Chesapeake explained that the combination of companies also allowed the elimination of duplicate corporate activities such as internal audit, external audit resources, stock related activities, and insurance policies. Sarbanes Oxley compliance audits, income tax preparation, and consulting fees no longer have to be incurred by both companies individually but rather can be done once. The cost savings related to corporate activities is $1,116,870.

Though over 100 positions have been eliminated, Chesapeake has also identified several personnel gaps. When management determined that existing employees did not possess the needed skill set for the required new job functions, Chesapeake replaced them with new employees. When positions did not exist to perform the needed job functions, new positions were created and filled. As a result, 12 new positions were added with a total annual cost (including benefits) of $982,707.

Chesapeake also incurred corporate cost increases of $108,016 and changes to the benefit plans resulting in an increase in costs of $467,940 for a total corporate and benefits increase of $575,956. The corporate cost increases included payroll software costs, investor relations, insurance, and directors’ fees. Chesapeake reviewed the existing pension, 401(k), health insurance, life insurance, dental, flex plan, disability, and college tuition benefit programs of the pre-merger companies. It was determined that there was a gap between the FPUC and Chesapeake employee benefits. As a result, the FPUC employee benefits were brought up to the level of the Chesapeake employee benefits generally keeping the Chesapeake employees “whole”. Chesapeake modified the 401(k) plan to a “safe harbor” reducing administrative costs and modified its matching provisions.

Docket No. 110133-GU
Date: November 9, 2011

3. Increased ability to attract capital for improvements

Staff believes that post-merger, FPUC, as an affiliate of Chesapeake, is in a better position to attract capital for system growth and improvements. At the time of the merger, FPUC had one committed line of credit for $26 million. Chesapeake has access to $100 million of short-term debt via four short-term lines of credit. In addition, FPUC, over the 10-year period immediately prior to the acquisition, had obtained only $29 million of long-term debt financing. By comparison, Chesapeake had obtained $100 million of long-term debt over the same period. Furthermore, FPUC had a lower credit rating than Chesapeake prior to the merger. FPUC’s long-term debt was rated by the National Association of Insurance Commissioners (NAIC) as NAIC 2, which is equivalent to Standard and Poor’s BBB to BBB- rating. By comparison, all of Chesapeake’s long-term debt is rated NAIC 1, which is equivalent to Standard and Poor’s A to A- rating.

4. Lower overall cost of capital

Post-merger, FPUC benefits from a lower overall cost of capital with demonstrated savings. The amount of savings is computed using the appropriate rate base and the pre-merger and post-merger weighted average cost of capital. Chesapeake compared an overall weighted average cost of capital of 8.17 percent, taken from FPUC’s last rate case, to the December 2010 earnings surveillance report (ESR) weighted average cost of capital of 7.88 percent. The difference of 29 basis points was multiplied by the rate base amount of $70,281,966. The result was savings of $203,818, which when multiplied by the net operating income multiplier, produced total savings of $330,124. Chesapeake’s proposed cost of capital savings amount of $330,124 is contained in Table 2-2 below:

Table 2-2
Company’s Cost of Capital Savings Calculation

Cost of Capital — 2009 Projected Test Year			8.17	%
Cost of Capital — 2010 Earning Surveillance Report			- 7.88	%
Difference in Average Cost of Capital			.29	%
Rate Base at December 31, 2010		x$	70,281,966
Required Net Operating Income		$	203,818
Net Operating Income Multiplier		x	1.61970
Company Computed Cost of Capital Savings		$	330,124

Docket No. 110133-GU
Date: November 9, 2011

Staff diverges from Chesapeake’s analysis by using a different starting point in lieu of FPUC’s projected test year weighted average cost of capital. Staff believes the September 30, 2009 ESR, which is the last actual surveillance report prior to the merger, is more indicative of the actual cost of capital at the time of the merger as opposed to the projected test year cost of capital from FPUC’s last rate case. The September 30, 2009 ESR cost of capital is 19 basis points less than the overall cost of capital from the projected test year. In addition, the staff audit and Chesapeake’s response to the staff audit resulted in specific adjustments to both the capital structure and rate base. To determine the amount of savings related to the cost of capital, staff subtracted the 7.66 percent overall cost of capital from Chesapeake’s response to the staff audit from the 7.98 percent overall cost of capital from the September 30, 2009 ESR. The difference of 32 basis points was multiplied by the staff determined rate base amount of $68,937,359. The result was a savings of $220,599 which, when multiplied by the net operating income multiplier of 1.6970, results in total savings related to the cost of capital of $357,239. The staff’s estimated cost of capital savings amount of $357,239 is shown in Table 2-3 below:

Table 2-3
Staff’s Cost of Capital Savings Calculation

Cost of Capital — 2009 Earning Surveillance Report			7.98	%
Cost of Capital — 2010 Staff Audit/Company Response			- 7.66	%
Difference in Average Cost of Capital			.32	%
Rate Base at December 31, 2010		x$	68,937,359
Required Net Operating Income		$	220,599
Net Operating Income Multiplier		x	1.61970
Staff’s Estimated Cost of Capital Savings		$	357,239

Based on staff’s analysis and the audit results, staff estimates the total savings related to the cost of capital is $27,115 ($357,239 — $330,124) greater than the amount provided by Chesapeake. Consequently, staff believes FPUC benefits from a lower overall cost of capital post-merger and that FPUC, as an affiliate of Chesapeake, is in a better position to attract capital.

5. More professional and experienced managerial, financial, technical and operational resources

Chesapeake states that it has owned and operated a number of gas-related business units. Those units include natural gas utilities and propane distribution operations in several states, both intrastate and interstate natural transmission pipelines, and a propane trading company. Chesapeake points out that it is experienced in mild and cold climates as well as both urban and rural areas. Chesapeake notes that the Florida system encompasses a wide variety of operational characteristics. Chesapeake serves customers in 13 counties in Florida, which includes approximately 70 industrial customers that each consume over 100,000 therms per year. Chesapeake also has approximately 25 city gate stations interconnected with three major interstate transmission pipelines. Chesapeake states that it has gained technical and operational skills and knowledge that can be used to further strengthen FPUC. Chesapeake believes that its experience sets the combined company apart from most other utilities in Florida. Chesapeake states that its “personnel have become very proficient with electronic measurement, communications, odorizing equipment and other highly technical distribution and transmission system devices.”

Docket No. 110133-GU
Date: November 9, 2011

Under Chesapeake, FPUC has increased its safety initiatives. Each of the five Division offices has a Safety Coordinator position. Chesapeake is also a multiple winner of the American Gas Association (AGA) Safety Award. Chesapeake explains that the AGA Safety Award recognizes companies that show exceptional employee safety performance throughout the year. To obtain this award, Chesapeake notes that they must have zero employee fatalities, employee days away from work because of injury that is lower than the industry average, and an Occupational Safety and Health Administration (OSHA) recordable incident rate lower than the industry average. Chesapeake states that it earned this award for seven consecutive years, from 2003 through 2009.

Based on the above analysis, staff recommends that Chesapeake be allowed to record the $34,192,493 purchase price premium as a positive acquisition adjustment to be amortized over a 30-year period beginning November 2009. The positive acquisition adjustment should be recorded in Account 114 — Gas Plant Acquisition Adjustments and the amortization expense should be recorded in Account 406 — Amortization of Gas Plant Acquisition Adjustment. The level of the cost savings supporting Chesapeake’s request should be subject to review in FPUC’s next rate proceeding. In FPUC’s next rate proceeding, if it is determined that the cost savings no longer exist, the acquisition adjustment may be partially or totally removed as deemed appropriate by the Commission. FPUC should file its earnings surveillance reports with and without the effect of the acquisition adjustment. Chesapeake is not seeking approval of an acquisition adjustment associated with the Indiantown Gas Company transaction at this time.

Although staff believes Chesapeake has demonstrated that there will be sufficient savings to offset the amortization of the acquisition adjustment, staff notes that the projected savings for 2013 through 2039 shown on Schedules 1 and 2 of Exhibit MK-5 may be overstated. In calculating future savings, an annual 3.0 percent escalation factor was used to increase the O&M and fuel cost savings each year. In staff’s opinion, most, if not all, of these cost savings are not subject to future escalation once they have been realized. For example if a $50,000 per year position is eliminated for 2011, that is the total amount of the cost savings. The cost savings for 2012 would also be $50,000, not $51,500 ($50,000 x 1.03). However, this does not affect staff’s analysis of this issue. As shown in Table 2-4 below, staff believes there still will be sufficient future savings even if the 3.0 percent escalation factor is eliminated.

Table 2-4
Staff’s Calculation of Net Savings/(Costs)

						Costs
						(Total Revenue				Net
Year		Savings				Requirement)				Savings/(Costs)
2009			0			$	1,052,698			$	(1,052,698	)
2010		$	3,589,457			$	6,222,456			$	(2,632,999	)
2011		$	5,720,977			$	6,049,406			$	(328,429	)
2012		$	6,255,187			$	5,876,357			$	378,830
2013		$	6,255,187			$	5,703,307			$	551,880
2014		$	6,255,187			$	5,434,275			$	820,912
2015		$	6,255,187			$	4,824,973			$	1,430,214

Total Revenue Requirement includes the Issue 3 regulatory asset.
The regulatory asset amortization ends in 2014.
The Net Savings increase $125,000 annually beginning in 2016.

Docket No. 110133-GU
Date: November 9, 2011

Issue 3: Should the Commission accept Chesapeake’s proposal to amortize, above the line, the regulatory assets established for transaction and transition costs of $2,207,158 over a five year period, beginning November 2009?

Recommendation: Yes. Transaction and transition costs should be recorded as a regulatory asset and amortized over five years beginning November 2009. The amounts should be $1,650,983 and $556,175, respectively, for a total of $2,207,158. The Commission should find that the approval to record the regulatory asset for accounting purposes does not limit the Commission’s ability to review the amounts for reasonableness now and in future rate proceedings. (Slemkewicz)

Staff Analysis: In addition to the purchase premium, Chesapeake incurred transaction costs and transition costs as a result of the acquisition. Chesapeake is requesting that it be allowed to record $2,207,158 as a regulatory asset to be amortized over a 5-year period beginning November 1, 2009.

Chesapeake asks that it be allowed to record the transaction and transition costs as a regulatory asset in Account 182.3 — Other Regulatory Assets, “consistent with the Commission’s express direction in Order No. PSC-10-0029-PAA-GU. . . .” Chesapeake also asks to be allowed to amortize the asset over a 5-year period from November 1, 2009, using the same modified straight line amortization schedule requested for the acquisition adjustment. The amortization expense for these costs would be recorded in Account 407.3 — Regulatory Debits.

In support of its request, Chesapeake states that transaction costs are those costs necessary to effect the acquisition of FPUC by Chesapeake. Chesapeake explains that the costs include fees paid to attorneys, Chesapeake’s financial advisor, accounting firms and other consultants, as well as costs to obtain necessary regulatory approvals and shareholder approval. Chesapeake also incurred transition costs after the completion of the acquisition to “facilitate the integration of Chesapeake and FPUC and, as a requirement of the transaction, to improve business efficiencies and to lower overall costs to serve.”

Transaction Costs

Chesapeake states that it incurred $2,375,033 in transaction costs, of which $2,218,683 or 93.4 percent was allocated to regulated utilities, based upon the enterprise value determined at the time of acquisition. Using the enterprise value, the allocation to the Natural Gas division of the regulated portion was $1,650,983 or 74.4 percent of the $2,218,683, as shown in Chesapeake witness Matthew Kim’s Exhibit MK-3. Approximately two thirds of the total costs were incurred for the corporate counsel ($809,342) and the financial advisor ($809,132). The portion allocated to Natural Gas was $562,409 and $562,263, respectively, or 69.5 percent. Other costs include such items as consultants, regulatory approval, and shareholder approval.

Docket No. 110133-GU
Date: November 9, 2011

Transition Costs

Transition costs are costs incurred after the acquisition. The details of these costs are discussed below. The total transition costs were $957,159. Of that amount, $556,175 or 58.1 percent was allocated to the Natural Gas division, as shown in Exhibit MK-3. A lower allocation percentage than that based on the enterprise value discussed above is a result of direct assignment of certain costs due to shareholder litigation and propane transfer marketing costs. Chesapeake listed these costs as non-recoverable because they were associated with the Propane operations.

1. Employee Severance Payments: The total cost was $451,572. Chesapeake explained that it eliminated over 100 positions and changed job responsibilities for other positions. Chesapeake was organized by functional area, while FPUC was organized by geographic location. The combined Chesapeake is now organized by function, resulting in the elimination of duplicated activities. Chesapeake initiated a Voluntary Reduction in Force (RIF) program to eliminate additional positions. This results in long-term savings to the customers.

2. Directors’ and Officers’ Insurance: This item consists of “run-off” or liability insurance for the former officers and directors of FPUC. The total cost was $252,832.

3. Legal: Legal fees associated with the severance and other integration-related matters. The total cost was $58,880.

These payments were the result of agreements between FPUC and certain FPUC executives that were made prior to the acquisition by Chesapeake. Under the agreements, the executives were to be compensated if they were terminated within a three-year period if there was a change in control, which in this case was an acquisition. The payments totaled $871,726.

4. Consulting: This consists of consulting expenses related to the integration of operations. The total cost was $40,833.

5. System Conversion: Chesapeake consolidated Chesapeake’s Customer Information Systems (CIS) with FPUC’s system. This allows for coordination of customer call centers, billing and collections and meter reading, and field services. Overall, a $3,882 reduction in costs occurred, offsetting some of the Transition costs.

Docket No. 110133-GU
Date: November 9, 2011

Analysis

A regulatory asset is a cost that is capitalized and recovered over a future period, rather than charged to expense when incurred. Account 182.3 — Other Regulatory Assets, includes “the amounts of regulatory-created assets, not includible in other accounts, resulting from the ratemaking actions of regulatory agencies.” (18 CFR 182.3) Staff believes that Account 182.3 is the correct place to record the regulatory asset, with amortization to be recorded in Account 407.3 — Regulatory Debits, as requested by Chesapeake.

Staff has reviewed the costs and believes Chesapeake’s proposed amounts and types of expenses are prudent, and that those costs will be offset by the savings to the customers in the future. However, since many of the savings are projected, to ensure that the customers will continue to benefit, staff believes it will be appropriate to review those cost savings in the future.

Staff recommends that transaction and transition costs should be recorded as a regulatory asset and amortized over five years beginning November 2009. The amounts to be recorded should be $1,650,983 and $556,175, respectively. The Commission should find that the approval to record the regulatory asset for accounting purposes does not limit the Commission’s ability to review the amounts for reasonableness in future rate proceedings.

Docket No. 110133-GU
Date: November 9, 2011

Issue 4: Should the Commission accept Chesapeake’s proposed use of the modified straight-line method to amortize the acquisition premium over 30 years and the regulatory assets over 5 years?

Recommendation: No, the unmodified straight-line amortization methodology should be used to amortize the acquisition adjustment and the transaction and transition costs. (Kaproth, Slemkewicz)

Staff Analysis: As discussed in Issues 2 and 3, staff is recommending that Chesapeake be allowed to amortize the $34,192,493 acquisition adjustment over 30 years and the $2,207,158 in transaction and transition costs over 5 years. However, Chesapeake has proposed a modification to the straight-line method for amortizing these costs.

Chesapeake used a 30 year amortization period for the acquisition adjustment and a 5 year period for the transaction and transition costs.⁴ The straight-line method amortizes the acquisition adjustment and other costs in equal yearly amounts over the prescribed number of years. Chesapeake’s modified straight-line method amortizes the acquisition adjustment and transition and transition costs over the appropriate prescribed number of years with varying amounts expensed for the years 2009 through 2014. For the remaining amortization period 2015 through 2039, the unamortized balance of the acquisition adjustment is amortized in equal yearly increments.

According to witness Kim, the modified straight-line method, as shown on Exhibit MK-4, Page 2 of 3, would be a benefit to the ratepayers. He believes that using the actual costs and savings for the first three years follows the economic benefits to the ratepayers of merging FPUC with Chesapeake. First, this method would allow FPUC to gradually increase the total amortization expense of the acquisition premium and the regulatory assets during the first three years to offset the savings acquired by FPUC. Because it takes time to determine the amount of and the best way to capture the savings generated by an acquisition, witness Kim contends the gradual ramping up of the actual costs and savings would better reflect the actual synergies of the acquisition. In his testimony, witness Kim stated that an example of identified initial savings is the permanent turn-back of $941,266 in Florida Gas Transmission (FGT) capacity, to offset costs that were needed to implement the synergies that gave rise to the savings. This reduction in gas capacity is an example of savings achieved and shared with its customers in the initial 18 months since the 2009 purchase of FPUC. Therefore, certain savings can be matched with the costs on a dollar to dollar basis. Witness Kim believes that after the first three years, the use of an additional straight-line method amortization for a total of 30 years, follows the past Commission practice of amortizing the acquisition premium cost over 30 years and regulatory assets over 5 years.

Docket No. 110133-GU
Date: November 9, 2011

Under Chesapeake’s proposed modified straight-line amortization method, net cost savings are not expected to occur until 2011. If the normal straight-line amortization method is used, there will be no anticipated net cost savings until 2012. However, staff believes the normal straight-line method will result in more overall net cost savings. Although both amortization methods will fully amortize the acquisition adjustment over 30 years and the other costs over 5 years, there is a disparity in the total revenue requirements between the 2 methods. Per Schedules 1 and 2 of Exhibit MK-5, the modified straight-line method revenue requirements are $5.4 million greater than those for the straight-line method over the 30 year amortization period. Depending on the timing of any base rate increases, it is likely that the ratepayers’ base rates would be higher if the modified straight-line amortization method is utilized.

In his Exhibit TAG-7, witness Geoffroy provided a list of $6,255,187 in total net operating cost savings to FPUC. In general, the full effects of synergies and savings from mergers and acquisitions do not occur immediately. It may take several years for the effects of any synergies and savings to be fully realized. Based on a review of Exhibit TAG-7, the only savings that staff can identify as an immediate and direct benefit to the ratepayers is the FGT savings of $941,266. This savings will flow back to the ratepayers as a reduction in the costs that are recovered through the Purchased Gas Adjustment (PGA).

As stated by witness Kim, the Commission’s practice is to amortize acquisition adjustments, as well as transaction and transition costs, using a straight-line method. As a general rule, staff believes there will normally be an initial disparity between costs and savings during the first several years following an acquisition or merger. In staffs opinion, there do not appear to be any unusual or compelling circumstances in this proceeding that would indicate a reason to deviate from the Commission’s normal practice of using a normal straight-line method. Therefore, staff recommends that the request to use a modified straight-line amortization method be denied. Instead, a normal straight-line amortization methodology should be used as shown on Exhibit MK-4, Page 1 of 3.

Docket No. 110133-GU
Date: November 9, 2011

Issue 5: Should the Commission accept Chesapeake’s proposal to consolidate the earnings surveillance reports and accounting records of the Florida Division of Chesapeake, the gas division of FPUC, and the FPUC — Indiantown Division with a combined midpoint return on equity of 10.85 percent?

Recommendation: No. Chesapeake should not be permitted to consolidate the earnings surveillance reports and accounting records of the three utilities until such time as the rates and tariffs are combined. (Slemkewicz)

Staff Analysis: Chesapeake requests that it be allowed to combine its earnings surveillance reports (ESRs) for FPUC and the Florida Division and to file the combined report on a quarterly basis. Chesapeake also asks to combine the accounting records of FPUC and the Florida Division. However, Chesapeake is not seeking approval to combine the tariffs of FPUC and the Florida Division.

In support of this request, witness Geoffroy states that consolidation of the accounting records “will allow the Company [Chesapeake] to simplify its processes and procedures that are currently in place to properly account for all regulated transactions of the combined company. This will, over time, result in additional cost savings which will ultimately be passed on to consumers.”

Chesapeake further states that it would like to streamline its internal accounting and reporting procedures, which it believes will necessitate consolidation of the ESRs of each division. For reporting purposes, Chesapeake would like to use an ROE with a mid-point of 10.85 percent for the combined ESR. Chesapeake contends that the mid-point ROE of 10.85 percent will not impact rates, but will only be used for surveillance purposes. Chesapeake explains that it has an approved ROE with a mid-point of 10.80 percent, FPUC’s ROE is set at 10.85 percent, and Indiantown’s ROE is 11.50 percent. Chesapeake states that these returns would remain unchanged for regulatory purposes, and that only the ESR would be affected.

Chesapeake also points to Order No. PSC-10-0029-PAA-GU,⁵ in which the Commission previously addressed Chesapeake’s request to base any future overearnings calculations on the combined Company. Chesapeake states that the basis for not allowing overearnings to be based on the combined Chesapeake and FPUC no longer exists, because the assets and operations of Chesapeake are operated and maintained interchangeably.

Docket No. 110133-GU
Date: November 9, 2011

Staff believes that it is inappropriate to consolidate the ESRs and accounting records at this time. As stated by Chesapeake, the divisions will still have separate rates and tariffs. The rates were established through individual rate proceedings.⁶ One of the purposes of the surveillance reports is to monitor earnings to ensure that the utility is not earning above its authorized rate of return on equity. While Chesapeake states that the current approved ROE for each of the divisions would not change, staff notes that they will serve no purpose if the ESRs are combined into one, with an ROE midpoint of 10.85 percent. Effectively, the approved ROEs will no longer exist. By combining the reports without a rate proceeding, one division of the company could be overearning while another is underearning.

Staff believes that rates should be combined only through a comprehensive proceeding. When rates are evaluated based on the combined company, it would be appropriate to consider combining the ESRs and accounting records. In such a review, rate base, ROE, net operating income (NOI), along with other issues, are considered together, not in a vacuum. While each utility has had a rate review, those reviews did not consider the combined company synergies of the combined operations. Therefore, staff recommends that Chesapeake not be permitted to consolidate the ESRs and accounting records until such time as the rates and tariffs are combined.

Docket No. 110133-GU
Date: November 9, 2011

Issue 6: Should Chesapeake’s request to establish a combined benchmark methodology for FPUC and the Florida Division for the purpose of evaluating incremental cost increases in future rate proceedings be approved?

Recommendation: No. It is premature to establish a combined benchmark for the Florida Division and FPUC since the two utilities are not functioning as a single utility for regulatory purposes. (Kaproth)

Staff Analysis: Chesapeake requests that the Commission establish a method, or benchmark, to be used on a going-forward basis to assess incremental cost increases in future proceedings. Witness Geoffroy states that the method that the Company proposes is simple and not inconsistent with the benchmark test that the Commission utilizes in a typical rate case to determine if O&M expenses are reasonable, as reflected in the minimum filing requirements (MFRs), Schedule C-34. Normally, the Base Year (BY) O&M expense amounts on Schedule C-34 are based on amounts from the most recent prior rate case adjusted for customer growth and inflation. The adjusted BY amounts are then compared to the Historical Test Year (HTY) amounts and the variance between the two amounts is calculated. Justifications for the benchmark variances must be provided.

Under Chesapeake’s proposal, the BY expenses from FPUC’s and the Florida Division’s prior rate cases would be projected out through 2012, the year by which the savings resulting from the acquisition will be fully realized. Those projected amounts would then be combined. The savings arising from the acquisition, as determined in this proceeding, would then be subtracted from the combined, projected 2012 O&M expenses. The resulting amount would serve as the baseline level for O&M expenses and trended in the usual manner in subsequent rate proceedings to assess incremental cost increases. Witness Geoffroy states that this would “accurately reflect the current situation in which two companies have consolidated, resulting in significant and ongoing savings...”

As addressed in Issue 5, staff recommends that Chesapeake not be permitted to consolidate the ESRs and accounting records of the three utilities until such time as the rates and tariffs are combined. At the present time, the Florida Division, FPUC and FPUC — Indiantown are all operating as separate entities with unique rates and tariffs. In staff’s opinion, it is premature to establish a combined benchmark for the Florida Division and FPUC since the two utilities are not functioning as a single utility for regulatory purposes. Therefore, staff recommends that Chesapeake’s request be denied.

Docket No. 110133-GU
Date: November 9, 2011

Issue 7: What is the amount, if any, of excess earnings for 2010 for the Florida Division?

Recommendation: The Florida Division does not have any excess earnings for 2010. (Slemkewicz)

Staff Analysis: The Florida Division submitted its December 2010 ESR on March 15, 2011. The reported “FPSC Adjusted” rate of return (ROR) was 6.69 percent resulting in an achieved ROE of 9.68 percent. This return is less than the top of the authorized ROE range of 11.80 percent.

Staff has reviewed the Florida Division’s December 2010 ESR and believes that the calculations contained therein appropriately reflect the Florida Division’s earnings for 2010. Therefore, staff recommends that the Florida Division does not have any excess earnings for 2010.

Docket No. 110133-GU
Date: November 9, 2011

Issue 8: What is the amount, if any, of excess earnings for 2010 for the gas division of FPUC?

Recommendation: The gas division of FPUC does not have any excess earnings for 2010 based on the inclusion of the acquisition adjustment and the transaction and transition costs recommended in previous issues. (Slemkewicz, Springer)

Staff Analysis: FPUC submitted its December 2010 ESR on March 15, 2011. The reported “FPSC Adjusted” ROR was 12.56 percent resulting in an achieved ROE of 20.88 percent. This return exceeded the top of the authorized ROE range of 11.85 percent. The ROE of 20.88 percent was calculated excluding the effects of the acquisition adjustment and the transaction and transition costs. Per FPUC’s calculations, the inclusion of these costs would reduce the ROR and ROE to 6.77 percent and 8.46 percent, respectively, lowering the achieved ROE below the authorized maximum of 11.85 percent.

FPUC’s December 2010 ESR was audited by the staff auditors and the audit report⁷ was submitted on August 11, 2011. FPUC filed its response⁸ to the audit report on September 2, 2011. Based on a review of the audit report and FPUC’s response, staff made certain adjustments to the rate base, net operating income and capital structure (Attachments A and B). After making these adjustments, staff calculated a revised ROR of 12.73 percent and revised ROE of 21.87 percent, representing $5,174,115 in excess earnings for 2010 (Attachment C). Although this calculation excludes any consideration of the acquisition adjustment and the transaction and transition costs, it does include the cost savings actually realized during 2010.

As discussed in previous issues, staff is recommending approval of the recovery and amortization of the acquisition adjustment and the transaction and transition costs. When these costs are included in the calculations, the ROE is reduced to 9.40 percent (Attachment C) which is less than the authorized maximum ROE of 11.85 percent. Therefore, staff recommends that the gas division of FPUC does not have any excess earnings for 2010 based on the inclusion of the acquisition adjustment and the transaction and transition costs.

Docket No. 110133-GU
Date: November 9, 2011

Issue 9: What is the appropriate disposition of the 2010 excess earnings, if any, for the Florida Division and the gas division of FPUC?

Recommendation: Depending on the level of any excess earnings, the appropriate disposition of any refund, with interest, would be a credit on the customers’ bills or a refund through the Purchased Gas Adjustment (PGA) cost recovery clause. Interest should be calculated using the commercial paper rate as provided in Rule 25-7.091(4), F.A.C. This issue is moot if the recommendations in Issues 7 and 8 are approved. (Slemkewicz, Draper)

Staff Analysis: As discussed in Issues 7 and 8, staff is recommending that there are not any excess earnings for 2010. However, if the Commission determines there are any excess earnings and a refund is warranted, the disposition of the excess earnings should be based on the amount of the refund. In evaluating the appropriate method for disposing of any refund amounts, consideration should be given to the dollar amount, the administrative efficiency and cost of the disposition method, and the potential benefit to the ratepayers. Any refund should also be made with interest calculated using the commercial paper rate as provided in Rule 25-7.091(4), F.A.C.

Although staff is recommending that any refund be made directly to the ratepayers, the Commission has various other options at its disposal, including: increasing the storm damage reserve; offsetting depreciation reserve deficiencies, if any; and offsetting the bare steel replacement program costs.

This issue is moot if the recommendations in Issues 7 and 8 are approved.

Docket No. 110133-GU
Date: November 9, 2011

Issue 10: Should this docket be closed?

Recommendation: If no person whose substantial interests are affected by the proposed agency action files a protest within 21 days of the issuance of the order, this docket should be closed upon the issuance of a consummating order. (Young)

Staff Analysis: At the conclusion of the protest period, if no protest is filed this docket should be closed upon the issuance of a consummating order.

Docket No. 110133-GU
Date: November 9, 2011

ATTACHMENT A

										FLORIDA PUBLIC UTILITIES COMPANY
										CONSOLIDATED GAS DIVISION
										DOCKET NO. 110133-GU
										REVIEW OF 2010 EARNINGS
		As Filed				Audit Finding				Audit Finding				Audit Finding
		FPSC				No. 1				No. 2				No. 3																Total
		Adjusted				13 Month Avg.				Non-Utility				Income								Interest				Total				Adjusted
		Basis				Recalculation				Adjustment				Statement								Synch				Adjustments				Rate Base
RATE BASE
Plant in Service			114,037,210				1,179,763				(7,348	)															1,172,415				115,209,625
Accumulated Depreciation			(43,630,692	)			197,798				28,317																226,115				(43,404,577	)
Net Plant in Service			70,406,518				1,377,561				20,969				0				0				0				1,398,530				71,805,048
Property Held for Future Use			0				0				0																0				0
Construction Work in Progress			2,431,727				(71,223	)			0																(71,223	)			2,360,504
Net Utility Plant			72,838,245				1,306,338				20,969				0				0				0				1,327,307				74,165,552
Working Capital			(2,556,278	)			(2,659,362	)			(12,553	)															(2,671,915	)			(5,228,193	)
Total Rate Base			70,281,967				(1,353,024	)			8,416				0				0				0				(1,344,608	)			68,937,359
INCOME STATEMENT
Operating Revenues			36,610,408												115,936												115,936				36,726,344
Operating Expenses:
Operation & Maintenance — Fuel			0												96,421												96,421				96,421
Operation & Maintenance — Other			16,250,686												172,686												172,686				16,423,372
Depreciation & Amortization			5,099,592												(452,060	)											(452,060	)			4,647,532
Taxes Other Than Income			2,149,024												376,031												376,031				2,525,055
Income Taxes — Current			4,280,370												(89,246	)							64,424				(24,822	)			4,255,548
Deferred Income Taxes (Net)			0																								0				0
Investment Tax Credit (Net)			0																								0				0
(Gain)/Loss on Disposition			0																								0				0
Total Operating Expenses			27,779,672				0				0				103,832				0				64,424				168,256				27,947,928
Net Operating Income			8,830,736				0				0				12,104				0				(64,424	)			(52,320	)			8,778,416
OVERALL RATE OF RETURN			12.56	%																							0.17	%			12.73	%
RETURN ON EQUITY			20.88	%																							0.99	%			21.87	%

Docket No. 110133-GU
Date: November 9, 2011

ATTACHMENT B

						FLORIDA PUBLIC UTILITIES COMPANY
						CONSOLIDATED GAS DIVISION
						DOCKET NO. 110133-GU
						REVIEW OF 2010 EARNINGS
CAPITAL STRUCTURE														Weighted
AS FILED - FPSC ADJUSTED		Amount				Ratio				Cost Rate				Cost
Long Term Debt		$	21,612,974				30.75	%			6.96	%			2.14	%
Short Term Debt			0				0.00	%			0.00	%			0.00	%
Preferred Stock			0				0.00	%			0.00	%			0.00	%
Customer Deposits			7,628,340				10.85	%			6.21	%			0.67	%
Common Equity			32,803,609				46.67	%			11.85	%			5.53	%
Deferred Income Taxes			8,154,499				11.60	%			0.00	%			0.00	%
Tax Credits — Zero Cost			0				0.00	%			0.00	%			0.00	%
Tax Credits — Weighted Cost			82,545				0.12	%			9.59	%			0.01	%
Total		$	70,281,967				100.00	%							8.35	%

						Adjustments								Adjusted												Weighted
ADJUSTED		Amount				Specific				Pro Rata				Total				Ratio				Cost Rate				Cost
Long Term Debt		$	21,612,974			$	(6,191,695	)		$	0			$	15,421,279				22.37	%			7.16	%			1.60	%
Short Term Debt			0				1,722,871				0				1,722,871				2.50	%			1.78	%			0.04	%
STD Refinanced LTD			0				3,857,962				0				3,857,962				5.60	%			5.66	%			0.32	%
Customer Deposits			7,628,340				1,356				0				7,629,696				11.07	%			6.00	%			0.66	%
Common Equity			32,803,609				(956,924	)			0				31,846,685				46.20	%			11.85	%			5.47	%
Deferred Income Taxes			8,154,499				221,822				0				8,376,321				12.15	%			0.00	%			0.00	%
Tax Credits — Zero Cost			0				0				0				0				0.00	%			0.00	%			0.00	%
Tax Credits — Weighted Cost			82,545				0				0				82,545				0.12	%			9.70	%			0.01	%
Total		$	70,281,967			$	(1,344,608	)		$	0			$	68,937,359				100.00	%							8.10	%

INTEREST SYNCHRONIZATION

										Effect on								Effect on
		Adjustments				Cost Rate				Interest Exp.				Tax Rate				Income Taxes
Long Term Debt		$	(6,191,695	)			7.16	%		$	(443,325	)			38.575	%		$	171,013
Short Term Debt			1,722,871				1 .78	%			30,667				38.575	%			(11,830	)
STD Refinanced LTD			3,857,962				5.66	%			218,361				38.575	%			(84,233	)
Customer Deposits			1,356				6.00	%			81				38.575	%			(31	)
Total		$	(609,506	)						$	(194,216	)						$	74,919

CHANGE IN COST RATE

		Cost Rate				Revised												Effect on								Effect on
		as Filed				Cost Rate				Difference				$ Amount				Interest Exp.				Tax Rate				Income Taxes
Long Term Debt			6.96	%			7.16	%			0.20	%			21,612,974				43,226				38.575	%			(16,674	)
Customer Deposits			6.21	%			6.00	%			-0.21	%			7,628,340				(16,020	)			38.575	%			6,180
Total																			27,206								(10,495	)

TOTAL EFFECT ON INCOME TAXES

Interest Synchronization		$	74,919
Change in Cost Rate			(10,495	)
Total		$	64,424

Docket No. 110133-GU
Date: November 9, 2011

ATTACHMENT C

FLORIDA PUBLIC UTILITIES COMPANY
CONSOLIDATED GAS DIVISION
DOCKET NO. 110133-GU
REVIEW OF 2010 EARNINGS

		Excluding								Including
		Acquisition				Acquisition				Acquisition
		Adjustment				Adjustment				Adjustment
Adjusted Rate Base		$	68,937,359			$	35,725,189			$	104,662,548
Adjusted Required Rate of Return @ 11.85% ROE		x	8.10	%						x	8.10	%
Required Net Operating Income		$	5,583,926							$	8,477,666
Adjusted Achieved Net Operating Income			-8,778,416			$	(1,480,445	)			-7,297,971
Net Operating Income Excess/(Deficiency)			3,194,490								(1,179,695	)
Revenue Expansion Factor		x	1.6197							x	1.6197
Revenue Excess/( Deficiency)		$	5,174,115							$	(1,910,753	)
Achieved Rate of Return			12.73	%							6.97	%
Achieved Return on Equity			21.87	%							9.40	%