Exhibit 99.1
INDIANA GAS COMPANY, INC.
REPORTING PACKAGE
For the year ended December 31, 2008
Contents
Page Number | ||
| Audited Financial Statements | ||
Additional Information
This annual reporting package provides additional information regarding the operations Indiana Gas Company, Inc. (Indiana Gas) that is supplemental to the information contained in the 2008 annual reports filed on Form 10-K of Vectren Corporation (Vectren) and Vectren Utility Holdings, Inc. (Utility Holdings), the parent companies of Indiana Gas. Vectren and Utility Holdings make available their Securities and Exchange Commission filings and recent annual reports free of charge through Vectren’s website at www.vectren.com.
Frequently Used Terms
AFUDC: allowance for funds used during construction | MCF / MMCF / BCF: thousands / millions / billions of cubic feet |
APB: Accounting Principles Board | MDth / MMDth: thousands / millions of dekatherms |
EITF: Emerging Issues Task Force | OUCC: Indiana Office of the Utility Consumer Counselor |
FASB: Financial Accounting Standards Board | PUCO: Public Utilities Commission of Ohio |
FERC: Federal Energy Regulatory Commission | SFAS: Statement of Financial Accounting Standards |
IDEM: Indiana Department of Environmental Management | USEPA: United States Environmental Protection Agency |
| IURC: Indiana Utility Regulatory Commission | Throughput: combined gas sales and gas transportation volumes |
INDEPENDENT AUDITORS’ REPORT
To the Shareholder and Board of Directors of
Indiana Gas Company, Inc.:
We have audited the accompanying balance sheets of Indiana Gas Company, Inc. (the “Company”) as of December 31, 2008 and 2007, and the related statements of income, common shareholder’s equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Indiana Gas Company, Inc. as of December 31, 2008 and 2007, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
| /s/DELOITTE & TOUCHE, LLP |
| Indianapolis, Indiana |
| February 18, 2009 |
FINANCIAL STATEMENTS
INDIANA GAS COMPANY, INC.
BALANCE SHEETS
(In thousands)
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| ASSETS | ||||||||
| Utility Plant | ||||||||
| Original cost | $ | 1,503,756 | $ | 1,430,999 | ||||
| Less: accumulated depreciation & amortization | 551,004 | 514,868 | ||||||
| Net utility plant | 952,752 | 916,131 | ||||||
| Current Assets | ||||||||
| Cash & cash equivalents | 2,712 | 2,249 | ||||||
| Accounts receivable - less reserves of $2,736 & | ||||||||
| $1,218, respectively | 65,955 | 50,580 | ||||||
| Receivables due from other Vectren companies | 3,686 | 74 | ||||||
| Accrued unbilled revenues | 86,837 | 69,083 | ||||||
| Inventories | 16,225 | 11,690 | ||||||
| Prepayments & other current assets | 76,248 | 70,715 | ||||||
| Total current assets | 251,663 | 204,391 | ||||||
| Investment in the Ohio operations | 245,965 | 238,462 | ||||||
| Other investments | 6,626 | 6,355 | ||||||
| Regulatory assets | 32,382 | 35,243 | ||||||
| Other assets | 5,650 | 7,651 | ||||||
| TOTAL ASSETS | $ | 1,495,038 | $ | 1,408,233 | ||||
The accompanying notes are an integral part of these financial statements.
INDIANA GAS COMPANY, INC.
BALANCE SHEETS
(In thousands)
| December 31, | ||||||||
| 2008 | 2007 | |||||||
| LIABILITIES & SHAREHOLDER'S EQUITY | ||||||||
| Common Shareholder's Equity | ||||||||
| Common stock (no par value) | $ | 367,995 | $ | 367,995 | ||||
| Retained earnings | 106,997 | 102,026 | ||||||
| Total common shareholder's equity | 474,992 | 470,021 | ||||||
| Long-term debt payable to third parties - net of current maturities & | ||||||||
| debt subject to tender | 121,000 | 121,000 | ||||||
| Long-term debt payable to Utility Holdings | 279,935 | 257,855 | ||||||
| Total long-term debt, net | 400,935 | 378,855 | ||||||
| Commitments & Contingencies (Notes 4, 7-8) | ||||||||
| Current Liabilities | ||||||||
| Accounts payable | 56,650 | 52,055 | ||||||
| Accounts payable to affiliated companies | 61,022 | 56,954 | ||||||
| Payables to other Vectren companies | 16,654 | 15,422 | ||||||
| Refundable natural gas costs | 1,618 | 11,933 | ||||||
| Accrued liabilities | 62,994 | 54,054 | ||||||
| Short-term borrowings payable to Utility Holdings | 116,887 | 86,234 | ||||||
| Current maturities of long-term debt | - | - | ||||||
| Long-term debt subject to tender | - | - | ||||||
| Total current liabilities | 315,825 | 276,652 | ||||||
| Deferred Income Taxes & Other Liabilities | ||||||||
| Deferred income taxes | 100,729 | 88,263 | ||||||
| Regulatory liabilities | 172,099 | 162,775 | ||||||
| Deferred credits & other liabilities | 30,458 | 31,667 | ||||||
| Total deferred income taxes & other liabilities | 303,286 | 282,705 | ||||||
| TOTAL LIABILITIES & SHAREHOLDER'S EQUITY | $ | 1,495,038 | $ | 1,408,233 | ||||
| The accompanying notes are an integral part of these financial statements. |
INDIANA GAS COMPANY, INC.
STATEMENTS OF INCOME
(In thousands)
| Year Ended December 31, | ||||||||
| 2008 | 2007 | |||||||
| OPERATING REVENUES | $ | 864,955 | $ | 762,858 | ||||
| COST OF GAS | 594,890 | 512,800 | ||||||
| 270,065 | 250,058 | |||||||
| OPERATING EXPENSES | ||||||||
| Other operating | 105,826 | 101,350 | ||||||
| Depreciation & amortization | 52,951 | 50,272 | ||||||
| Taxes other than income taxes | 20,254 | 20,740 | ||||||
| Total operating expenses | 179,031 | 172,362 | ||||||
| OPERATING INCOME | 91,034 | 77,696 | ||||||
| Other expense - net | (547 | ) | (575 | ) | ||||
| Interest expense | 29,217 | 27,087 | ||||||
| INCOME BEFORE INCOME TAXES | 61,270 | 50,034 | ||||||
| Income taxes | 24,878 | 23,132 | ||||||
| Equity in earnings of the | ||||||||
| Ohio operations - net of tax | 7,503 | 6,641 | ||||||
| NET INCOME | $ | 43,895 | $ | 33,543 | ||||
The accompanying notes are an integral part of these financial statements.
INDIANA GAS COMPANY, INC.
STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, | ||||||||
| 2008 | 2007 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||
| Net income | $ | 43,895 | $ | 33,543 | ||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||
Depreciation & amortization | 52,951 | 50,272 | ||||||
Provision for uncollectible accounts | 7,003 | 6,743 | ||||||
Deferred income taxes & investment tax credits | 16,281 | 5,706 | ||||||
Expense portion of pension & postretirement periodic benefit cost | 860 | 1,207 | ||||||
Equity in earnings of the Ohio operations - net of tax | (7,503 | ) | (6,641 | ) | ||||
Other non-cash charges - net | 3,120 | 2,267 | ||||||
Changes in working capital accounts: | ||||||||
| Accounts receivable, including due from Vectren companies | ||||||||
& accrued unbilled revenue | (43,745 | ) | 3,136 | |||||
Inventories | (5,439 | ) | 5,595 | |||||
Recoverable/refundable natural gas costs | (10,316 | ) | (14,119 | ) | ||||
Prepayments & other current assets | (7,612 | ) | 111 | |||||
Accounts payable, including to Vectren companies | ||||||||
& affiliated companies | 10,216 | 23,685 | ||||||
Accrued liabilities | 6,758 | (1,572 | ) | |||||
| Changes in noncurrent assets | 3,726 | (12,325 | ) | |||||
| Changes in noncurrent liabilities | (10,302 | ) | (6,725 | ) | ||||
| Net cash flows from operating activities | 59,893 | 90,883 | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||
| Proceeds from long-term term debt payable to Utility Holdings | 22,220 | 14,017 | ||||||
| Requirements for: | ||||||||
| Retirement of long-term debt | (140 | ) | (6,500 | ) | ||||
| Dividend to parent | (38,924 | ) | (30,803 | ) | ||||
| Net change in short-term borrowings, including from Utility Holdings | 30,653 | 19,608 | ||||||
| Net cash flows from financing activities | 13,809 | (3,678 | ) | |||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||
| Proceeds from: | ||||||||
Other investments | 339 | - | ||||||
Requirements for : | ||||||||
Capital expenditures | (71,963 | ) | (87,136 | ) | ||||
Other investments | (1,615 | ) | (473 | ) | ||||
| Net cash flows from investing activities | (73,239 | ) | (87,609 | ) | ||||
| Net change in cash & cash equivalents | 463 | (404 | ) | |||||
| Cash & cash equivalents at beginning of period | 2,249 | 2,653 | ||||||
| Cash & cash equivalents at end of period | $ | 2,712 | $ | 2,249 | ||||
| Cash paid during the year for: | ||||||||
| Interest | $ | 28,475 | $ | 26,399 | ||||
| Income taxes | 2,973 | 17,276 | ||||||
The accompanying notes are an integral part of these financial statements.
INDIANA GAS COMPANY, INC.
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
(In thousands)
| Common | Retained | |||||||||||
| Stock | Earnings | Total | ||||||||||
| Balance at January 1, 2007 | $ | 367,995 | $ | 99,286 | $ | 467,281 | ||||||
| Net income & comprehensive income | 33,543 | 33,543 | ||||||||||
| Common stock: | ||||||||||||
| Dividends to parent | (30,803 | ) | (30,803 | ) | ||||||||
| Balance at December 31, 2007 | $ | 367,995 | $ | 102,026 | $ | 470,021 | ||||||
| Net income & comprehensive income | 43,895 | 43,895 | ||||||||||
| Common stock: | ||||||||||||
| Dividends to parent | (38,924 | ) | (38,924 | ) | ||||||||
| Balance at December 31, 2008 | $ | 367,995 | $ | 106,997 | $ | 474,992 | ||||||
The accompanying notes are an integral part of these financial statements.
INDIANA GAS COMPANY, INC.
NOTES TO THE FINANCIAL STATEMENTS
| 1. | Organization and Nature of Operations |
Indiana Gas Company, Inc. (the Company, Indiana Gas or Vectren North), an Indiana corporation, provides energy delivery services to over 568,000 natural gas customers located in central and southern Indiana. Indiana Gas is a direct, wholly owned subsidiary of Vectren Utility Holdings, Inc. (Utility Holdings). Utility Holdings is a direct, wholly owned subsidiary of Vectren Corporation (Vectren). Indiana Gas generally does business as Vectren Energy Delivery of Indiana, Inc. Vectren is an energy holding company headquartered in Evansville, Indiana.
Investment in the Ohio Operations
The Company holds a 47 percent interest in the Ohio operations, which provide energy delivery services to approximately 317,000 natural gas customers located near Dayton in west central Ohio. The remaining 53 percent ownership in the Ohio operations interest is held by Vectren Energy Delivery of Ohio, Inc. (VEDO or Vectren Ohio), and VEDO is the operator of the assets. VEDO is also a wholly owned subsidiary of Utility Holdings. The Ohio operations typically do business as Vectren Energy Delivery of Ohio, Inc.
Indiana Gas’ ownership is accounted for using the equity method in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” and is included in Investment in the Ohio operations, and its interest in the results of operations is included in Equity in earnings of the Ohio operations. Additional information on the Company’s investment in the Ohio operations is included in Note 3.
| 2. | Summary of Significant Accounting Policies |
| A. | Revenues |
Revenues are recorded as products and services are delivered to customers. To more closely match revenues and expenses, the Company records revenues for all gas delivered to customers but not billed at the end of the accounting period.
| B. | Utility Receipts Taxes |
Excise taxes and a portion of utility receipts taxes are included in rates charged to customers. Accordingly, the Company records these taxes received as a component of operating revenues. Expense associated with excise and utility receipts taxes are recorded as a component of Taxes other than income taxes.
| C. | Earnings Per Share |
Earnings per share information is not presented herein. The common stock of Indiana Gas is wholly owned by Vectren Utility Holdings, Inc.
| D. | Cash & Cash Equivalents |
All highly liquid investments with an original maturity of three months or less at the date of purchase are considered cash equivalents.
| E. | Inventories |
Inventories consist of the following:
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Gas in storage - at LIFO cost | $ | 12,096 | $ | 8,336 | ||||
| Materials & supplies | 3,313 | 2,666 | ||||||
| Other | 816 | 688 | ||||||
| Total inventories | $ | 16,225 | $ | 11,690 | ||||
Based on the average cost of gas purchased during December, the cost of replacing gas in storage carried at LIFO cost exceeded LIFO cost at December 31, 2008, and 2007, by approximately $21 million and $26 million, respectively. All other inventories are carried at average cost.
| F. | Utility Plant & Depreciation |
Utility plant is stated at historical cost, including AFUDC. Depreciation rates are established through regulatory proceedings and are applied to all in-service utility plant. The original cost of utility plant, together with depreciation rates expressed as a percentage of original cost, follows:
| At and For the Year Ended December 31, | ||||||||||||||||
| (In thousands) | 2008 | 2007 | ||||||||||||||
| Original Cost | Depreciation Rates as a Percent of Original Cost | Original Cost | Depreciation Rates as a Percent of Original Cost | |||||||||||||
| Utility plant | $ | 1,453,408 | 3.8 | % | $ | 1,402,680 | 3.8 | % | ||||||||
| Construction work in progress | 50,348 | - | 28,319 | - | ||||||||||||
| Total original cost | $ | 1,503,756 | $ | 1,430,999 | ||||||||||||
AFUDC represents the cost of borrowed and equity funds which are used for construction purposes, and charged to construction work in progress during the construction period. AFUDC is included in Other – net in the Statements of Income. The total AFUDC capitalized into utility plant and the portion of which was computed on borrowed and equity funds for all periods reported follows:
| Year Ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| AFUDC – borrowed funds | $ | 427 | $ | 838 | ||||
| AFUDC – equity funds | - | 27 | ||||||
| Total AFUDC capitalized | $ | 427 | $ | 865 | ||||
Maintenance and repairs, including the cost of removal of minor items of property and planned major maintenance projects, are charged to expense as incurred. When property that represents a retirement unit is replaced or removed, the remaining historical value of such property is charged to Utility plant, with an offsetting charge to Accumulated depreciation. Costs to dismantle and remove retired property are recovered through the depreciation rates identified above.
| G. | Impairment Review of Long-Lived Assets |
Long-lived assets are reviewed as facts and circumstances indicate that the carrying amount may be impaired. This review is performed in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). SFAS 144 establishes one accounting model for all impaired long-lived assets and long-lived assets to be disposed of by sale or otherwise. SFAS 144 requires that the evaluation for impairment involve the comparison of an asset’s carrying value to the estimated future cash flows that the asset is expected to generate over its remaining life. If this evaluation were to conclude that the carrying value of the asset is impaired, an impairment charge would be recorded based on the difference between the asset’s carrying amount and its fair value (less costs to sell for assets to be disposed of by sale) as a charge to operations or discontinued operations.
| H. | Regulation |
Retail public utility operations affecting Indiana customers are subject to regulation by the IURC, and retail public utility operations affecting customers of the Ohio operations are subject to regulation by the PUCO. The Company’s accounting policies give recognition to the rate-making and accounting practices of these agencies and to accounting principles generally accepted in the United States, including the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).
Refundable or Recoverable Gas Costs
All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. The Company records any under-or-over-recovery resulting from gas adjustment clauses each month in revenues. A corresponding asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers.
Regulatory Assets and Liabilities
Regulatory assets represent probable future revenues associated with certain incurred costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable expenditures by the Company for removal costs or future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. The Company assesses the recoverability of costs recognized as regulatory assets and liabilities and the ability to continue to account for its activities based on the criteria set forth in SFAS 71. Based on current regulation, the Company believes such accounting is appropriate. If all or part of the Company's operations cease to meet the criteria of SFAS 71, a write-off of related regulatory assets and liabilities could be required. In addition, the Company would be required to determine any impairment to the carrying value of its utility plant and other regulated assets.
Regulatory assets consist of the following:
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Amounts currently recovered through customer rates related to: | ||||||||
| Authorized trackers | $ | 16,263 | $ | 18,841 | ||||
| Unamortized debt issue costs & premiums paid to reacquire debt | 6,918 | 7,788 | ||||||
| Rate case expenses | 597 | - | ||||||
| 23,778 | 26,629 | |||||||
| Future amounts recoverable from ratepayers related to: | ||||||||
| Income taxes- deferred income taxes | 7,577 | 7,639 | ||||||
| Income taxes- transition to SFAS 109 | 1,001 | 975 | ||||||
| Other | 26 | - | ||||||
| Total regulatory assets | $ | 32,382 | $ | 35,243 | ||||
Indiana Gas is not earning a return on the $23.7 million currently being recovered through base rates. The weighted average recovery period of regulatory assets currently being recovered is 14 years. The Company has rate orders for deferred costs not yet in rates and therefore believes that future recovery is probable.
Regulatory liabilities
At December 31, 2008 and 2007, the Company has approximately $172.1 million and $162.8 million, respectively, in regulatory liabilities. Of these amounts, $161.9 million and $156.4 million relate to cost of removal obligations.
The Company collects an estimated cost of removal of its utility plant through depreciation rates established in regulatory proceedings. The Company records amounts expensed in advance of payments as a Regulatory liability because the liability does not meet the threshold of an asset retirement obligation as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” and its related interpretations (SFAS 143).
| I. | Asset Retirement Obligations |
A portion of removal costs related to interim retirements of gas utility pipeline meet the definition of an asset retirement obligation (ARO). SFAS 143 requires entities to record the fair value of a liability for a legal ARO in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. The liability is accreted, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. To the extent regulation is involved, such gain or loss may be deferred.
ARO’s included in Other liabilities total $11.9 million and $7.5 million at December 31, 2008 and 2007, respectively. During 2008, the Company recorded accretion of $0.4 million and increases in estimates, net of cash payments of $4.0 million. During 2007, the Company recorded accretion of $0.4 million.
| J. | Use of Estimates |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
| K. | Other Significant Policies |
Included elsewhere in these notes are significant accounting policies related to the investment in the Ohio operations (Note 3), intercompany allocations and income taxes (Note 4) and derivatives (Note 10).
| 3. | Investment in the Ohio Operations |
The Company’s investment in the Ohio operations is accounted for using the equity method of accounting. The Company’s share of the Ohio operations after tax earnings is recorded in Equity in earnings of the Ohio operations. Because the Ohio operations is responsible for its income taxes and is also within Vectren’s consolidated tax group, no additional tax provision for these earnings is included in these financial statements. Dividends are recorded as a reduction of the carrying value of the investment when received. Goodwill, which is a component of the Company’s net investment, is accounted for in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). SFAS 142 uses an impairment-only approach to account for the effect of goodwill on the operating results.
Following is summarized financial data of the Ohio operations:
| Year Ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Operating revenues | $ | 408,098 | $ | 374,320 | ||||
| Operating income after income taxes | 15,623 | 14,882 | ||||||
| Net income | 15,965 | 14,129 | ||||||
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Net utility plant | $ | 346,567 | $ | 336,489 | ||||
| Current assets | 194,700 | 146,312 | ||||||
| Goodwill - net | 199,457 | 199,457 | ||||||
| Other non-current assets | 21,171 | 20,095 | ||||||
| Total assets | $ | 761,895 | $ | 702,353 | ||||
| Owners' net investment | $ | 442,874 | $ | 433,520 | ||||
| Current liabilities | 167,103 | 134,578 | ||||||
| Noncurrent liabilities | 151,918 | 134,255 | ||||||
| Total liabilities & owners' net investment | $ | 761,895 | $ | 702,353 | ||||
Vectren Energy Delivery of Ohio, Inc. (VEDO) Gas Base Rate Order Received
On January 7, 2009, the PUCO issued an order approving the stipulation reached in the VEDO rate case. The order provides for a rate increase of nearly $14.8 million, an overall rate of return of 8.89 percent on rate base of about $235 million; an opportunity to recover costs of a program to accelerate replacement of cast iron and bare steel pipes, as well as certain service risers; and base rate recovery of an additional $2.9 million in conservation program spending.
The order also adjusts the rate design that will be used to collect the agreed-upon revenue from VEDO's residential customers. The order authorizes the use of a straight fixed variable rate design which places all, or most, of the fixed cost recovery in the customer service charge. Using a phased in approach, revenues based on volumes sold will be entirely replaced with a fixed charge after one year. A straight fixed variable design mitigates some weather risk as well as the effects of declining usage, similar to the Company’s lost margin recovery mechanism, which expired when this new rate design went into effect in February 2009. In 2008, results include approximately $4.3 million of revenue from the existing lost margin recovery mechanism that will not continue once this base rate increase is in effect. The OCC has filed a request for rehearing on the rate design finding by the PUCO. The rehearing request mirrors similar requests filed by the OCC in each case where the PUCO has approved similar rate designs, and all such requests have been denied.
With this rate order the Company has in place for its Ohio gas territory rates that allow for the phased implementation of a straight fixed variable rate design that mitigates both weather risk and lost margin; tracking of bad debt and percent of income payment plan (PIPP) expenses; base rate recovery of pipeline integrity management expense; timely recovery of costs associated with the accelerated replacement of bare steel and cast iron pipes, as well as certain service risers; and expanded conservation programs now totaling up to $5 million in annual expenditures.
Vectren Energy Delivery of Ohio, Inc. Begins Process to Exit the Merchant Function
On August 20, 2008, the PUCO approved an auction selecting qualified wholesale suppliers to provide the gas commodity to the Company for resale to its customers at auction-determined standard pricing. This standard pricing is comprised of the monthly NYMEX settlement price plus a fixed adder. This auction, which is effective from October 1, 2008 through March 31, 2010, is the initial step in exiting the merchant function in the Company’s Ohio service territory. The approach eliminates the need for monthly gas cost recovery (GCR) filings and prospective PUCO GCR audits. On October 1st, VEDO’s entire natural gas inventory was transferred, receiving proceeds of approximately $107 million. The PUCO has also provided for an Exit Transition Cost rider, which allows the Company to recover costs associated with the transition. As the cost of gas is currently passed through to customers through a PUCO approved recovery mechanism, the impact of exiting the merchant function should not have a material impact on Company earnings or financial condition.
| 4. | Transactions with Other Vectren Companies |
Support Services and Purchases
Vectren and Utility Holdings provide corporate and general and administrative assets and services to the Company and allocates costs to the Company, including costs for share-based compensation and for pension and other postretirement benefits that are not directly charged to subsidiaries. These costs have been allocated using various allocators, including number of employees, number of customers and/or the level of payroll, revenue contribution and capital expenditures. Allocations are at cost. Indiana Gas received corporate allocations totaling $73.8 million and $69.3 million for the years ended December 31, 2008, and 2007, respectively.
Retirement Plans and Other Postretirement Benefits
Vectren has multiple defined benefit pension plans and postretirement plans that require accounting as described in SFAS No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158), which it adopted on December 31, 2006. An allocation of cost is determined, comprised of only service cost and interest on that service cost, by subsidiary based on headcount at each measurement date. These costs are directly charged to individual subsidiaries. Other components of costs (such as interest cost and asset returns) are charged to individual subsidiaries through the corporate allocation process discussed above. Neither plan assets nor the ending liability is allocated to individual subsidiaries since these assets and obligations are derived from corporate level decisions. Further, Vectren satisfies the future funding requirements of plans and the payment of benefits from general corporate assets. This allocation methodology is consistent with “multiemployer” benefit accounting as described in SFAS 87 and 106.
For the years ended December 31, 2008 and 2007, periodic pension costs totaling $0.9 million and $1.5 million, respectively, was directly charged by Vectren to the Company. For the years ended December 31, 2008 and 2007, other periodic postretirement benefit costs totaling $0.3 million and $0.2 million, respectively, was directly charged by Vectren to the Company. As of December 31, 2008, and 2007, $2.8 million and $6.4 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren, and $3.2 million and $4.5 million, respectively, is included in Other assets for amounts funded in advance to Vectren.
Share-Based Incentive Plans and Deferred Compensation Plans
Indiana Gas does not have share-based compensation plans separate from Vectren. An insignificant number of Indiana Gas’ employees participate in Vectren’s share-based compensation plans. The Company recognizes its allocated portion of expenses in accordance with FASB Statement 123 (revised 2004), “Share-Based Payments” (SFAS 123R). As of December 31, 2008 and 2007, $12.3 million and $11.6 million, respectively, is included in Deferred credits & other liabilities and represents costs directly charged to the Company that is yet to be funded to Vectren.
Cash Management Arrangements
The Company participates in Vectren’s centralized cash management program. See Note 6 regarding long-term and short-term intercompany borrowing arrangements.
Guarantees of Parent Company Debt
Vectren’s three operating utility companies, Southern Indiana Gas Company, Inc., Indiana Gas, and Vectren Energy Delivery of Ohio, Inc. are guarantors of Utility Holdings’ $515 million in short-term credit facilities, of which approximately $192 million is outstanding at December 31, 2008, and Utility Holdings’ $823 million unsecured senior notes outstanding at December 31, 2008. The guarantees are full and unconditional and joint and several, and Utility Holdings has no subsidiaries other than the subsidiary guarantors.
Miller Pipeline Corporation
Miller Pipeline Corporation (Miller), a wholly owned subsidiary of Vectren, performs natural gas and water distribution, transmission, and construction repair and rehabilitation primarily in the Midwest and the repair and rehabilitation of gas, water, and wastewater facilities nationwide. Miller’s customers include Indiana Gas. Fees paid by Indiana Gas totaled $26.8 million in 2008 and $31.4 million in 2007. Amounts owed to Miller at December 31, 2008 and 2007 are included in Payables to other Vectren companies.
Income Taxes
Vectren files a consolidated federal income tax return. Pursuant to an intercompany tax sharing agreement and for financial reporting purposes, Indiana Gas’ current and deferred tax expense is computed on a separate company basis. Current taxes payable/receivable are settled with Vectren in cash. The liability method of accounting is used for income taxes under which deferred income taxes are recognized to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities at currently enacted income tax rates. Significant components of the net deferred tax liability follow:
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Non-current deferred tax liabilities (assets): | ||||||||
| Depreciation & cost recovery timing differences | $ | 94,778 | $ | 81,751 | ||||
| Regulatory assets recoverable through future rates | 10,693 | 10,255 | ||||||
| Regulatory liabilities to be settled through future rates | (3,136 | ) | (2,616 | ) | ||||
| Employee benefit obligations | (6,956 | ) | (5,214 | ) | ||||
| Other – net | 5,350 | 4,087 | ||||||
| Net non-current deferred tax liability | 100,729 | 88,263 | ||||||
| Current deferred tax liabilities (assets): | ||||||||
| Deferred fuel costs - net | 4,710 | (37 | ) | |||||
| Other – net | (2,527 | ) | (2,042 | ) | ||||
| Net deferred tax liability | $ | 102,912 | $ | 86,184 | ||||
At December 31, 2008, and 2007, investment tax credits totaling $0.7 million and $1.2 million, respectively, are included in Deferred credits and other liabilities. These investment tax credits are amortized over the lives of the related investments.
A reconciliation of the federal statutory rate to the effective income tax rate follows:
| Year Ended December 31, | ||||||||
| 2008 | 2007 | |||||||
| Statutory rate | 35.0 | % | 35.0 | % | ||||
| State & local taxes, net of federal benefit | 5.3 | 6.2 | ||||||
| Amortization of investment tax credit | (0.7 | ) | (1.3 | ) | ||||
| Adjustment to federal income tax accruals & other, net | 1.0 | 6.3 | ||||||
| Effective tax rate | 40.6 | % | 46.2 | % | ||||
The components of income tax expense and utilization of investment tax credits follow:
| Year Ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Current: | ||||||||
| Federal | $ | 3,844 | $ | 12,781 | ||||
| State | 4,753 | 4,645 | ||||||
| Total current taxes | 8,597 | 17,426 | ||||||
| Deferred: | ||||||||
| Federal | 15,444 | 5,171 | ||||||
| State | 1,270 | 1,181 | ||||||
| Total deferred taxes | 16,714 | 6,352 | ||||||
| Amortization of investment tax credits | (433 | ) | (646 | ) | ||||
| Total income taxes | $ | 24,878 | $ | 23,132 | ||||
Accounting for Uncertainty in Income Taxes
On January 1, 2007, the Company adopted FASB Interpretation No. 48 (FIN 48) “Accounting for Uncertainty in Income Taxes” an interpretation of SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken in an income tax return. FIN 48 also provides guidance related to reversal of tax positions, balance sheet classification, interest and penalties, interim period accounting, disclosure and transition. The Company records interest and penalties associated with uncertain tax positions in income taxes. The adoption of FIN 48 did not have a material impact on the Company, and activity related to uncertain tax positions since adoption has also been insignificant.
Indiana Gas does not file federal or Indiana state income tax returns separate from those filed by its parent, Vectren Corporation. The Internal Revenue Service (IRS) has conducted examinations of Vectren’s U.S. federal income tax returns for tax years through December 31, 2005. The State of Indiana, Vectren’s primary state tax jurisdiction, has conducted examinations of state income tax returns for tax years through December 31, 2002. The statutes of limitations for assessment of federal and Indiana income tax have expired with respect to tax years through 2002.
| 5. | Transactions with ProLiance Holdings, LLC |
ProLiance Holdings, LLC (ProLiance), a nonutility energy marketing affiliate of Vectren and Citizens Energy Group (Citizens), provides services to a broad range of municipalities, utilities, industrial operations, schools, and healthcare institutions located throughout the Midwest and Southeast United States. ProLiance’s customers include Vectren’s Indiana utilities and nonutility gas supply operations as well as Citizens’ utilities. ProLiance’s primary businesses include gas marketing, gas portfolio optimization, and other portfolio and energy management services. Indiana Gas purchases all of its natural gas through ProLiance and has regulatory approval from the IURC to continue to do so through March 2011.
Purchases made from ProLiance for resale and for injections into storage for the years ended December 31, 2008 and 2007, totaled $606.4 million and $506.2 million, respectively. Amounts owed to ProLiance at December 31, 2008 and 2007, for those purchases were $61.0 million and $56.9 million, respectively, and are included in Accounts payable to affiliated companies in the Balance Sheets. Amounts charged by ProLiance for gas supply services are established by supply agreements with the utility.
| 6. | Borrowing Arrangements & Other Financing Transactions |
Long-Term Debt
Senior unsecured obligations outstanding and classified as long-term follow:
| At December 31, | ||||||
| (In thousands) | 2008 | 2007 | ||||
| Fixed Rate Senior Unsecured Notes Payable to Utility Holdings: | ||||||
| 2011, 6.625% | $ 98,954 | $ 98,954 | ||||
| 2018, 5.75% | 37,129 | 37,129 | ||||
| 2015, 5.45% | 24,716 | 24,716 | ||||
| 2035, 6.10% | 50,569 | 50,569 | ||||
| 2036, 5.95% | 46,487 | 46,487 | ||||
| 2039, 6.25% | 22,080 | - | ||||
| Total long-term debt payable to Utility Holdings | $ 279,935 | $ 257,855 | ||||
| Fixed Rate Senior Unsecured Notes Payable to Third Parties: | ||||||
| 2013, Series E, 6.69% | 5,000 | 5,000 | ||||
| 2015, Series E, 7.15% | 5,000 | 5,000 | ||||
| 2015, Series E, 6.69% | 5,000 | 5,000 | ||||
| 2015, Series E, 6.69% | 10,000 | 10,000 | ||||
| 2025, Series E, 6.53% | 10,000 | 10,000 | ||||
| 2027, Series E, 6.42% | 5,000 | 5,000 | ||||
| 2027, Series E, 6.68% | 1,000 | 1,000 | ||||
| 2027, Series F, 6.34% | 20,000 | 20,000 | ||||
| 2028, Series F, 6.36% | 10,000 | 10,000 | ||||
| 2028, Series F, 6.55% | 20,000 | 20,000 | ||||
| 2029, Series G, 7.08% | 30,000 | 30,000 | ||||
| Total long-term debt outstanding payable to third parties | $ 121,000 | $ 121,000 | ||||
2039 Notes Payable to Utility Holdings
In March 2008, the Company issued a note payable to Utility Holdings. The term of the note is identical to the terms of notes issued by Utility Holdings in March 2008. These notes issued by Utility Holdings have an aggregate principal amount of $125 million, are priced at par with an interest rate of 6.25%, and are due April 1, 2039. The notes have no sinking fund requirements, and interest payments are due monthly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after April 1, 2013, at 100 percent of principal amount plus accrued interest. During 2007, Utility Holdings entered into several interest rate hedges with an $80 million notional amount. Upon issuance of the notes, these instruments were settled resulting in the payment of approximately $9.6 million, which was recorded as a Regulatory asset pursuant to existing regulatory orders. The value paid is being amortized as an increase to interest expense over the life of the issue. The proceeds from the sale of these notes less settlement of the hedging arrangements and payments of issuance costs amounted to approximately $111.1 million, of which $22.1 million was issued to Indiana Gas. Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in it financing arrangements to account for debt issuance costs and any related hedging arrangements.
2036 Notes Payable to Utility Holdings
In December 2007, the Company issued a note payable to Utility Holdings for $14 million bringing its total allocation of notes issued by Utility Holdings that are due in 2036 to $46.5 million. These notes have an aggregate principle amount of $100 million with an interest rate of 5.95%, priced at par. The 2036 Notes have no sinking fund requirements, and interest payments are due quarterly. The notes may be called by Utility Holdings, in whole or in part, at any time on or after October 1, 2011, at 100% of the principal amount plus accrued interest. Utility Holdings adjusts the interest rate it charges to its subsidiaries from those stated in it financing arrangements to account for debt issuance costs and any related hedging arrangements.
Long-Term Debt Sinking Fund Requirements & Maturities
The Company has no sinking fund requirements on long-term debt during the five years following 2008. Long-term debt maturities in the five years following 2008 total $99.0 million in 2011 and $5.0 million in 2013.
Long-Term Debt Put & Call Provisions
Certain long-term debt issues contain put and call provisions that can be exercised on various dates before maturity. Other than certain instruments that can be put to the Company upon the death of the holder (death puts), these put or call provisions are not triggered by specific events, but are based upon dates stated in the note agreements. During 2008 the Company repaid approximately $0.1 million related to death puts. In 2007, no debt was put to the Company. Debt which may be put to the Company for reasons other than a death during the years following 2008 (in millions) is zero in 2009, $10.0 in 2010, $30.0 in 2011, zero in 2012 and thereafter. Debt that may be put to the Company within one year is classified as Long-term debt subject to tender in current liabilities.
Short-Term Borrowings
Indiana Gas relies entirely on the short-term borrowing arrangements of Utility Holdings for its short-term working capital needs. Borrowings outstanding at December 31, 2008 and 2007 were $116.9 million and $86.2 million, respectively. The intercompany credit line totals $325 million, but is limited to Utility Holdings’ available capacity ($323 million at December 31, 2008) and is subject to the same terms and conditions as Utility Holdings’ short term borrowing arrangements, including its commercial paper program. Short-term borrowings bear interest at Utility Holdings’ weighted average daily cost of short-term funds. See the table below for interest rates and outstanding balances:
| Year ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Weighted average total outstanding during | ||||||||
the year due to Utility Holdings (in thousands) | $ | 46,864 | $ | 36,115 | ||||
| Weighted average interest rates during the year: | ||||||||
| Utility Holdings | 3.80 | % | 5.52 | % | ||||
Covenants
Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage and interest coverage, among other restrictions. As of December 31, 2008, the Company was in compliance with all financial covenants.
| 7. | Commitments & Contingencies |
Legal Proceedings
The Company is party to various legal proceedings arising in the normal course of business. In the opinion of management, there are no legal proceedings pending against the Company that are likely to have a material adverse effect on its financial position or results of operations. See Note 8 regarding environmental matters.
| 8. | Environmental Matters |
In the past, Indiana Gas and others operated facilities for the manufacture of gas. Given the availability of natural gas transported by pipelines, these facilities have not been operated for many years. Under currently applicable environmental laws and regulations, those that owned or operated these facilities may now be required to take remedial action if certain contaminants are found above the regulatory thresholds at these sites.
Indiana Gas identified the existence, location, and certain general characteristics of 26 gas manufacturing and storage sites for which it may have some remedial responsibility. Indiana Gas completed a remedial investigation/feasibility study (RI/FS) at one of the sites under an agreed order between Indiana Gas and the IDEM, and a Record of Decision was issued by the IDEM in January 2000. Indiana Gas submitted the remainder of the sites to the IDEM's Voluntary Remediation Program (VRP) and is currently conducting some level of remedial activities, including groundwater monitoring at certain sites, where deemed appropriate, and will continue remedial activities at the sites as appropriate and necessary.
Indiana Gas accrued the estimated costs for further investigation, remediation, groundwater monitoring, and related costs for the sites. While the total costs that may be incurred in connection with addressing these sites cannot be determined at this time, Indiana Gas has recorded cumulative costs that it reasonably expects to incur totaling approximately $21.6 million. The estimated accrued costs are limited to Indiana Gas’ share of the remediation efforts. Indiana Gas has arrangements in place for 19 of the 26 sites with other potentially responsible parties (PRP), which serve to limit Indiana Gas’ share of response costs at these 19 sites to between 20 percent and 50 percent.
With respect to insurance coverage, Indiana Gas has received and recorded settlements from all known insurance carriers under insurance policies in effect when these plants were in operation in an aggregate amount approximating $20.5 million.
Environmental remediation costs related to Indiana Gas’ manufactured gas plants and other sites have had a minor impact on results of operations or financial condition since cumulative costs recorded to date approximate PRP and insurance settlement recoveries. Such cumulative costs are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments, and inflation factors, among others. While the Company has recorded all costs which it presently expects to incur in connection with activities at these sites, it is possible that future events may require some level of additional remedial activities which are not presently foreseen and those costs may not be subject to PRP or insurance recovery. As of December 31, 2008, approximately $2.9 million is included in Other Liabilities related to the remediation of these sites.
| 9. | Rate & Regulatory Matters |
Gas Base Rate Order Received
On February 13, 2008, the Company received an order from the IURC which approved the settlement agreement reached in its Vectren North gas rate case. The order provided for a base rate increase of $16.3 million and a return on equity (ROE) of 10.2 percent, with an overall rate of return of 7.8 percent on rate base of approximately $793 million. The order also provides for the recovery of $10.6 million of costs through separate cost recovery mechanisms rather than base rates.
Further, additional expenditures for a multi-year bare steel and cast iron capital replacement program will be afforded certain accounting treatment that mitigates earnings attrition from the investment between rate cases. The accounting treatment allows for the continuation of the accrual for allowance for funds used during construction (AFUDC) and the deferral of depreciation expense after the projects go in service but before they are included in base rates. To qualify for this treatment, the annual expenditures are limited to $20 million and the treatment cannot extend beyond four years on each project.
With this order, the Company has in place for its North gas territory weather normalization, a conservation and lost margin recovery tariff, tracking of gas cost expense related to a bad debt expense level based on historical experience and unaccounted for gas through the existing gas cost adjustment mechanism, and tracking of pipeline integrity management expense.
| 10. | Derivatives & Other Financial Instruments |
Accounting Policy for Derivatives
The Company periodically executes derivative contracts in the normal course of operations while buying and selling commodities to be used in operations and managing risk. The Company accounts for its derivative contracts in accordance with SFAS 133, “Accounting for Derivatives” and its related amendments and interpretations. In most cases, SFAS 133 requires a derivative to be recorded on the balance sheet as an asset or liability measured at its market value and that a change in the derivative's market value be recognized currently in earnings unless specific hedge criteria are met.
When an energy contract that is a derivative is designated and documented as a normal purchase or normal sale, it is exempted from mark-to-market accounting. Otherwise, energy contracts and financial contracts that are derivatives are recorded at market value as current or noncurrent assets or liabilities depending on their value and on when the contracts are expected to be settled. Contracts and any associated collateral with counter-parties subject to master netting arrangements are presented net in the Balance Sheets. The offset resulting from carrying the derivative at fair value on the balance sheet is charged to earnings unless it qualifies as a hedge or is subject to SFAS 71. When hedge accounting is appropriate, the Company assesses and documents hedging relationships between the derivative contract and underlying risks as well as its risk management objectives and anticipated effectiveness. When the hedging relationship is highly effective, derivatives are designated as hedges. The market value of the effective portion of the hedge is marked to market in accumulated other comprehensive income for cash flow hedges. Ineffective portions of hedging arrangements are marked-to-market through earnings. For fair value hedges, both the derivative and the underlying hedged item are marked to market through earnings. The offset to contracts affected by SFAS 71 are marked-to-market as a regulatory asset or liability. Market value for derivative contracts is determined using quoted market prices from independent sources. Following is a more detailed discussion of the Company’s use of mark-to-market accounting in the natural gas procurement area.
The Company’s regulated operations have limited exposure to commodity price risk for purchases and sales of natural gas for retail customers due to current Indiana regulations which, subject to compliance with those regulations, allow for recovery of such purchases through natural gas cost adjustment mechanisms. Although regulated operations are exposed to limited commodity price risk, volatile natural gas prices can result in higher working capital requirements, increased expenses including interest costs, uncollectible accounts expense, and unaccounted for gas, and some level of price-sensitive reduction in volumes sold. The Company may mitigate these risks by using derivative contracts. These contracts are subject to regulation which allows for reasonable and prudent hedging costs to be recovered through rates. When regulation is involved, SFAS 71 controls when the offset to mark-to-market accounting is recognized in earnings. At December 31, 2008 and 2007, the market values of these contracts were not significant.
Fair Value Measurements
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements; however, the standard will impact how other fair value based GAAP is applied. Subsequently, the FASB issued FSP FAS 157-2 which delayed the effective date of SFAS 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually) to fiscal years beginning after November 15, 2008. The Company adopted SFAS 157 on January 1, 2008, except as it applies to those nonfinancial assets and nonfinancial liabilities as described in FSP FAS 157-2. The partial adoption of SFAS 157 did not materially impact the Company’s financial position, results of operations or cash flows. The potential impact of applying SFAS 157 to its nonfinancial assets and liabilities is not expected to have a material impact on the Company’s financial statements.
The Company measures certain financial instruments at fair value on a recurring basis. SFAS 157 defines a hierarchy for disclosing fair value measurements based primarily on the level of public data used in determining fair value. Level 1 inputs include quoted market prices in active markets for identical assets or liabilities; Level 2 inputs include inputs other than Level 1 inputs that are directly or indirectly observable; and Level 3 inputs include unobservable inputs using estimates and assumptions developed in-house, which reflect what a market participant would use to determine fair value. At December 31, 2008 and 2007, the Company had no material assets or liabilities recorded at fair value outstanding and none outstanding valued using Level 3 inputs.
SFAS 159
Also on January 1, 2008, the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (SFAS 159). SFAS 159 permitted entities to choose to measure many financial instruments and certain other items at fair value. The Company did not choose to apply the option provided in SFAS 159 to any of its eligible items; therefore, its adoption did not have any impact on the Company’s financial statements or results of operations.
Fair Value of Other Financial Instruments
The carrying values and estimated fair values of the Company's other financial instruments follow:
| At December 31, | ||||||||||||||||
| 2008 | 2007 | |||||||||||||||
| (In thousands) | Carrying Amount | Est. Fair Value | Carrying Amount | Est. Fair Value | ||||||||||||
| Long-term debt due to third parties | $ | 121,000 | $ | 113,599 | $ | 121,000 | $ | 124,042 | ||||||||
| Long-term debt due to Utility Holdings | 279,935 | 244,261 | 257,855 | 255,504 | ||||||||||||
| Short-term debt due to Utility Holdings | 116,887 | 116,887 | 86,234 | 86,234 | ||||||||||||
Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates and variable interest rates of short-term borrowings, its carrying amount approximates its fair value.
Under current regulatory treatment, call premiums on reacquisition of long-term debt are generally recovered in customer rates over the life of the refunding issue or over a 15-year period. Accordingly, any reacquisition would not be expected to have a material effect on the Company's results of operations.
| 11. | Additional Balance Sheet & Statement of Income Information |
Accrued liabilities in the Balance Sheets consist of the following:
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Customer advances & deposits | $ | 24,955 | $ | 21,468 | ||||
| Accrued gas imbalance | 6,974 | 6,838 | ||||||
| Accrued taxes | 22,335 | 15,697 | ||||||
| Accrued interest | 3,834 | 5,565 | ||||||
| Deferred income taxes | 2,183 | - | ||||||
| Accrued salaries & other | 2,713 | 4,486 | ||||||
| Total accrued liabilities | $ | 62,994 | $ | 54,054 | ||||
Prepayments and other current assets in the Balance Sheets consist of the following:
| At December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Prepaid gas delivery service | $ | 74,987 | $ | 65,169 | ||||
| Deferred income taxes | - | 2,079 | ||||||
| Prepaid taxes & other | 1,261 | 3,467 | ||||||
| Total prepayments & other current assets | $ | 76,248 | $ | 70,715 | ||||
Other – net in the Statements of Income consists of the following:
| Year Ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| AFUDC | $ | 427 | $ | 865 | ||||
| Other income/(expense) | (599 | ) | 761 | |||||
| Donations & regulatory expenses | (375 | ) | (2,201 | ) | ||||
| Total other – net | $ | (547 | ) | $ | (575 | ) | ||
12. Adoption of Other Accounting Standards
SFAS 141 (Revised 2007)
In December 2007, the FASB issued SFAS No. 141, “Business Combinations” (SFAS 141R). SFAS 141R establishes principles and requirements for how the acquirer of an entity (1) recognizes and measures the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree (2) recognizes and measures acquired goodwill or a bargain purchase gain and (3) determines what information to disclose in its financial statements in order to enable users to assess the nature and financial effects of the business combination. SFAS 141R applies to all transactions or other events in which one entity acquires control of one or more businesses and applies to all business entities. SFAS 141R applies prospectively to business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Early adoption is not permitted. The Company will adopt SFAS 141R on January 1, 2009, and because the provisions of this standard are applied prospectively, the impact to the Company cannot be determined until the transactions occur.
SFAS 161
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” (SFAS 161). SFAS 161 enhances the current disclosures under SFAS 133 and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation in order to better convey the purpose of derivative use in terms of the risks that the entity is intending to manage. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. Tabular disclosure of fair value amounts and gains and losses on derivative instruments and related hedged items is required. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. The Company will adopt SFAS 161 on January 1, 2009, and the impact is not expected to be material to the Company’s financial position or results of operations.
SFAS 162
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS No. 162). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting principles used in the preparation of financial statements. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles”. The implementation of this standard will not have a material impact on its financial position and results of operations.
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The following discussion and analysis provides additional information regarding Indiana Gas’ results of operations that is supplemental to the information provided in Vectren Corporation’s and Utility Holdings’ management’s discussion and analysis of results of operations and financial condition contained in those 2008 annual reports filed on Forms 10-K, which include forward looking statement disclaimers. The following discussion and analysis should be read in conjunction with Indiana Gas’ financial statements and notes thereto.
Executive Summary of Results of Operations
Indiana Gas generates revenue primarily from the delivery of natural gas to its customers, and Indiana gas’ primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of gas and electric services.
Indiana Gas has in place a disclosure committee that consists of senior management as well as financial management. The committee is actively involved in the preparation and review of Indiana Gas’ financial statements.
Operating Results
In 2008, Indiana Gas had $43.9 million in net income compared to net income of $33.5 million in 2007. The $10.4 million increase was due largely to the impact of rate increases implemented on February 14, 2008, the impacts of decoupling/lost margin recovery mechanisms and a lower effective tax rate in 2008, offset by increased operating expenses and interest costs.
Significant Fluctuations
Margin
Throughout this discussion, the term Gas Utility margin is used. Gas Utility margin is calculated as Gas utility revenues less the Cost of gas. The Company believes Gas Utility margin is better indicators of relative contribution than revenues since gas prices can be volatile and are generally collected on a dollar-for-dollar basis from customers.
Sales of natural gas to residential and commercial customers are seasonal and are impacted by weather. Trends in average use among natural gas residential and commercial customers have tended to decline in recent years as more efficient appliances and furnaces are installed and the price of natural gas has increased. Normal temperature adjustment (NTA) and lost margin recovery mechanisms largely mitigate the effect on Gas Utility margin that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. Indiana Gas’ territory has both an NTA since 2005 and lost margin recovery since December 2006.
Gas margin generated from sales to large customers (generally industrial and other contract customers) is primarily impacted by overall economic conditions and changes in demand for those customers’ products. The recent recession may have some negative impact large customers. This impact may include tempered growth, significant conservation measures, and perhaps even plant closures or bankruptcies. Deteriorating economic conditions may also lead to continued lower residential and commercial customer counts.
Margin is also impacted by the collection of state mandated taxes, which fluctuate with gas and fuel costs, as well as other tracked expenses. Expenses subject to tracking mechanisms include gas pipeline integrity management costs and costs to fund Indiana energy efficiency programs. The latest rate case implemented in February 2008 also provide for the tracking of the gas cost component of bad debt expense based on historical experience and unaccounted for gas. Following is a discussion and analysis of gas utility margin.
Gas Utility Margin (Gas utility revenues less Cost of gas)
Gas Utility margin and throughput by customer type follows:
| Year Ended December 31, | ||||||||
| (In thousands) | 2008 | 2007 | ||||||
| Gas utility revenues | $ | 864,955 | $ | 762,858 | ||||
| Cost of gas | 594,890 | 512,800 | ||||||
| Total gas utility margin | $ | 270,065 | $ | 250,058 | ||||
| Margin attributed to: | ||||||||
| Residential & commercial customers | $ | 234,091 | $ | 217,202 | ||||
| Industrial customers | 28,936 | 26,838 | ||||||
| Other customers | 7,038 | 6,018 | ||||||
| Sold & transported volumes in MDth attributed to: | ||||||||
| Residential & commercial customers | 66,791 | 62,267 | ||||||
| Industrial customers | 53,241 | 51,423 | ||||||
| Total sold & transported volumes | 120,032 | 113,690 | ||||||
Gas utility margins were $270.1 million for the year ended December 31, 2008, an increase of $20.0 million compared to 2007. Margin increases associated with the rate increases, effective February 14, 2008, were $11.8 million year over year. The increases were also impacted by the recovery of tracked operating costs and revenue taxes, which increased margin $3.6 million year over year. The remaining increases are primarily due to lost margin recovery mechanisms and small customer growth. The average cost per dekatherm of gas purchased was $8.35 in 2008 and $8.04 in 2007.
Operating Expenses
Other Operating
For the year ended December 31, 2008, Other operating expenses were $105.8 million, which is an increase of $4.5 million, compared to 2007. Operating costs recovered dollar for dollar in margin increased $2.2 million year over year. The remaining increase is primarily attributable to increased maintenance and other activities contemplated in the recent rate case, offset by lower levels of accrued performance compensation.
Depreciation & Amortization
For the year ended December 31, 2008, depreciation expense increased $2.7 million compared to 2007. The increase resulted primarily from normal additions to utility plant.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $0.5 million as the impact of property tax and other tax adjustments offset higher revenue taxes.
Interest Expense
For the year ended December 31, 2008 Interest expense was $29.2 million, an increase of $2.1 million compared to 2007. The increase is primarily due to higher debt balances which include Indiana Gas’ issuance of approximately $22 million in senior unsecured notes at 6.25 percent due in 2039 to Utility Holdings in March 2008.
Vectren continues to develop plans to issue additional long-term debt over the next twelve to twenty four months, assuming its investment grade credit ratings will allow it to access the capital markets, as the need arises. However, while debt markets have improved somewhat, such long-term debt issued during this period could be more expensive than in recent history.
Income Taxes
For the year ended December 31, 2008, income taxes increased $1.7 million compared to 2007. The increase in income taxes is due higher pre tax income offset by a lower effective tax rate. Income taxes in 2007 include unfavorable adjustments to reflect income taxes reported on final state and federal income tax returns while adjustments recorded in 2008 were favorable.
Equity in Earnings of the Ohio Operations
Equity in earnings of the Ohio operations represents Indiana Gas’ 47% interest in the Ohio operations’ net income. The Ohio operations’ net income was $16.0 million in 2008 and $14.1 million in 2007. Indiana Gas’ share of those earnings was $7.5 million and $6.6 million, respectively. The increased earnings were primarily due to gas margins $5.4 million higher than 2007, of which $3.2 million was due to weather. In addition, during 2007, the Ohio operations resolved all remaining issues related to a 2005 disallowance by the PUCO of gas costs, resulting in an additional charge of $1.1 million.
Interest costs arising from financing arrangements utilized by Indiana Gas and VEDO for the purchase of the Ohio operations are not reflected in the above earnings data. Had the financing arrangements of Indiana Gas and VEDO used to facilitate the purchase of the Ohio operations been pushed down, the Ohio operations’ net income would have been approximately $7.2 million and $5.3 million for the years ended December 31, 2008 and 2007, respectively.
SELECTED GAS OPERATING STATISTICS:
| INDIANA GAS COMPANY | ||||||||||
| SELECTED UTILITY | ||||||||||
| OPERATING STATISTICS | ||||||||||
| (Unaudited) | ||||||||||
| For the Year Ended | ||||||||||
| December 31, | ||||||||||
| 2008 | 2007 | |||||||||
OPERATING REVENUES (In thousands): | ||||||||||
| Residential | $ 589,438 | $ 522,783 | ||||||||
| Commercial | 232,277 | 201,499 | ||||||||
| Industrial | 36,202 | 32,557 | ||||||||
| Misc Revenue | 7,038 | 6,019 | ||||||||
| $ 864,955 | $ 762,858 | |||||||||
MARGIN (In thousands): | ||||||||||
| Residential | $ 179,024 | $ 167,042 | ||||||||
| Commercial | 55,067 | 50,160 | ||||||||
| Industrial | 28,936 | 26,838 | ||||||||
| Misc Revenue | 7,038 | 6,018 | ||||||||
| $ 270,065 | $ 250,058 | |||||||||
GAS SOLD & TRANSPORTED (In MDth): | ||||||||||
| Residential | 45,978 | 43,016 | ||||||||
| Commercial | 20,813 | 19,251 | ||||||||
| Industrial | 53,241 | 51,423 | ||||||||
| 120,032 | 113,690 | |||||||||
| AVERAGE CUSTOMERS: | ||||||||||
| Residential | 510,764 | 509,645 | ||||||||
| Commercial | 49,363 | 49,076 | ||||||||
| Industrial | 849 | 847 | ||||||||
| 560,976 | 559,568 | |||||||||
WEATHER AS A % OF NORMAL:(1) | ||||||||||
| Heating Degree Days | 99% | 91% | ||||||||
(1) The impact of weather on residential and commercial customers is mitigated by an NTA mechanism | ||||||||||