Overview of 2009 and Future Outlook

Overview

The following is a discussion of the segments we operate, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during 2009. Our Company has two segments: (i) a regulated natural gas distribution, transmission and storage segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production.

Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors. Regulated sales volumes are temperature-sensitive. Our regulated sales volumes in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes. The impact of winter temperatures on our revenues is partially reduced given our ability to adjust our winter rates for residential and small non-residential customers based on the degree to which actual winter temperatures deviate from normal.

Our non-regulated segment markets natural gas to large-use customers both on and off our regulated system. We endeavor to enter sales agreements when we can match estimated demand with a supply that provides an acceptable margin.

Earnings per share decreased between 2009 and 2008 by $.50 per share. Our non-regulated segment's contribution to earnings decreased as a result of decreased non-regulated sales volumes and lower sales prices that resulted in a $2,800,000 reduction in gross margins. Additionally, we incurred a non-recurring inventory adjustment for our gas in storage of $1,350,000 ($838,000 net of income tax benefit), as further discussed in Note 15 of the Notes to Consolidated Financial Statements.

Future Outlook

In 2010 and beyond, our success will depend, in part, on our regulated segment's ability to maintain a reasonable rate of return. The Kentucky Public Service Commission sets the rates we are permitted to charge our customers in the regulated segment. We monitor our need to file a general rate case with the Kentucky Public Service Commission to seek approval to adjust the rates we charge our regulated customers. The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers. We control remaining expenses through budgeting, approval and review.

Future profitability of the non-regulated segment is dependent on the business plans of a few industrial and other large use customers and the market prices of natural gas, all of which are out of our control. Although in Fiscal 2009 we experienced a decline of gross margins in this segment due to decreased prices and decreases in the volumes sold to our non-regulated customers due to a decrease in our non-regulated customers' gas requirements, we anticipate our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2010 in a manner at least similar to fiscal 2009. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production activities. However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities.

Liquidity and Capital Resources

Sources and Uses of Cash

Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes, gains on the sale of assets and changes in working capital.

Our ability to maintain liquidity depends on our bank line of credit, shown as notes payable on the accompanying Consolidated Balance Sheets. Notes payable decreased to $3,653,000 at June 30, 2009, compared with $6,829,000 at June 30, 2008. The $3,176,000 decrease reflects a decrease in the cost of gas purchased for our gas in storage.

Our liquidity is impacted by the fact that we sometimes generate internally only a portion of the cash necessary for our capital expenditure requirements. We made capital expenditures of $8,422,000, $5,564,000 and $8,803,000 during the fiscal years ended 2009, 2008 and 2007, respectively.

Long-term debt decreased to $57,599,000 at June 30, 2009, compared with $58,318,000 at June 30, 2008. The $719,000 decrease resulted from the redemption of the Debentures and Insured Quarterly Notes, which allow for limited redemptions to be made by certain holders or their beneficiaries.

Cash and cash equivalents were $123,000 at June 30, 2009 compared with $250,000 at June 30, 2008 and $188,000 at June 30, 2007. These changes in cash and cash equivalents are summarized in the following table:

($000)                                               2009         2008         2007

Provided by operating activities                     15,434        6,592       14,486
Used in investing activities                         (7,956 )     (5,266 )     (7,936 )
Used in financing activities                         (7,605 )     (1,264 )     (6,512 )

Increase (decrease) in cash and cash equivalents       (127 )         62           38

In 2009, cash provided by operating activities increased $8,842,000 as compared to 2008. In 2009, $8,626,000 less was paid for natural gas due to lower natural gas prices and $5,202,000 more cash was received from customers due to the timing of collections on customer accounts receivable. These increases were partially offset by a $1,932,000 increase in contributions we made to our pension plan and a $1,473,000 increase in cash paid for taxes.

In 2008, cash provided by operating activities decreased $7,894,000 as compared to 2007. In 2008, we paid $15,288,000 more for gas due to increased natural gas prices, increased volumes purchased and the timing of gas payables. This increase was partially offset due to $7,120,000 more cash received from customers due to increased prices and volumes sold.

Changes in cash used in investing activities result primarily from changes in the level of capital expenditures between years.

In 2009, $6,341,000 more cash was used in financing activities due to increased net repayments on our bank line of credit.

In 2008, $5,248,000 less cash was used in financing activities due to increased net borrowings on our bank line of credit.

Cash Requirements

Our capital expenditures result in a continued need for capital. These capital expenditures are being made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2010 to be approximately $6.3 million.

Due to the conditions in the debt and equity markets, we experienced a decline in the value of assets held by our defined benefit pension plan and thus we contributed $2,677,000 to the plan in fiscal 2009.

The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2009:

                                                          Payments Due by Fiscal Year
($000)                                 2010         2011-2012       2013-2014      After 2014        Total

Interest payments (a)               $   4,192     $     7,859     $     7,400     $     28,700     $  48,151
Long-term debt (b)                      1,200           2,400           2,400           52,799        58,799
Pension contributions (c)                 500           1,000           1,000            9,182        11,682
Gas purchases (d)                       3,764             143               -                -         3,907
Total contractual obligations (e)   $   9,656     $    11,402     $    10,800     $     90,681     $ 122,539

(a) Our long-term debt, notes payable, customers' deposits and unrecognized tax positions all require interest payments. Interest payments are projected based on fiscal 2009 interest payments until the underlying obligation is satisfied. Interest on notes payable represents interest payments expected on the bank line of credit which extends through June 30, 2011. As of June 30, 2009, we have accrued $60,000 of interest related to uncertain tax positions. This amount has been excluded from the above table of contractual obligations as the timing of such payments is uncertain.

(b) See Note 9 of the Notes to Consolidated Financial Statements for a description of this debt. The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date. Our long-term debt does not have any sinking fund requirements.

(c) This represents currently projected contributions to the defined benefit plan through 2019, as recommended by our actuary.

(d) As of June 30, 2009, we had ten contracts which have minimum purchase obligations. These contracts have various terms with the last contract expiring November 1, 2010. The remainder of our gas purchase contracts are requirement-based contracts or if a minimum purchase obligation exists the contract does not extend for a time period greater than one month.

(e) We have other long-term liabilities which include deferred income taxes ($27,538,000), regulatory liabilities ($1,711,000), asset retirement obligations ($1,670,000) and deferred compensation ($281,000). Based on the nature of these items their expected settlement dates cannot be estimated.

All of our operating leases are year-to-year and cancelable at our option.

See Note 12 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

Sufficiency of Future Cash Flows

Current economic conditions have resulted in increased credit risk for us due to the potential for default from our customers. For the twelve months ended June 30, 2009, we have experienced an increase in customer accounts written off, net of recoveries of $42,000 (10%). Based on current outstanding receivables and expecting this trend to continue into fiscal 2010, our allowance for doubtful accounts has increased to $819,000 at June 30, 2009, as compared to $465,000 at June 30, 2008. However, we are unable to estimate the impact this trend will have on future earnings and liquidity.

We expect that cash provided by operations, coupled with short-term and long-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future.

To the extent that internally generated cash is not sufficient to satisfy operating and capital expenditure requirements and to pay dividends, we will rely on our bank line of credit. Our current available bank line of credit with Branch Banking and Trust Company, shown as notes payable on the accompanying Consolidated Balance Sheets, is $40,000,000, of which $3,653,000 was borrowed at June 30, 2009. The current bank line of credit extends through June 30, 2011.

Our ability to borrow on our bank line of credit is dependent on our compliance with covenants. Our bank line of credit agreement and the Indentures relating to all of our publicly held Debentures and Insured Quarterly Notes contain defined "events of default" which, among other things, can make the obligations immediately due and payable. Of these, we consider the following covenants to be most restrictive:

· Dividend payments cannot be made unless consolidated shareholders' equity of other Company exceeds $25,800,000 (thus no retained earnings were restricted); and

· We may not assume any additional mortgage indebtedness in excess of $5,000,000 without effectively securing all Debentures and Insured Quarterly Notes equally to such additional indebtedness.

Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes. We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during fiscal 2009. We are not aware of any events that would cause us to be in default in fiscal 2010.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices, and we monitor our need to file rate requests with the Kentucky Public Service Commission for a general rate increase for our regulated services.

On April 20, 2007, we filed a request for increased rates with the Kentucky Public Service Commission. This general rate case, Case No. 2007-00089, requested an annual revenue increase of approximately $5,642,000, an increase of 9.3%. The rate case requested a return on common equity of 12.1%. During October 2007, we negotiated a settlement with the Kentucky Attorney General regarding this rate case. The settlement agreement provided for $3,920,000 of additional annual revenues, and stipulated for settlement purposes a 10.5% return on common shareholders' equity. The increase in rates was allocated primarily to the monthly customer charge, and therefore the increase in revenue occurred more evenly throughout the year and was not as dependent on customer usage. An order from the Kentucky Public Service Commission was received on October 19, 2007 approving the terms of the settlement with rates effective October 20, 2007.

Critical Accounting Policies and Estimates

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the use of assumptions and estimates regarding future events, including the likelihood of success of particular investments or initiatives, estimates of future prices or rates, legal and regulatory challenges and anticipated recovery of costs. Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions. We consider an accounting estimate to be critical if
(i) the accounting estimate requires us to make assumptions about matters that were reasonably uncertain at the time the accounting estimate was made, and (ii) changes in the estimate are reasonably likely to occur from period to period.

These critical accounting estimates should be read in conjunction with the Notes to Consolidated Financial Statements. We have other accounting policies that we consider to be significant; however, these policies do not meet the definition of critical accounting estimates, because they generally do not require us to make estimates or judgments that are particularly difficult or subjective.

Regulatory Accounting

Our accounting policies historically reflect the effects of the rate-making process in accordance with Financial Accounting Standards Board Statement No. 71, entitled Accounting for the Effects of Certain Types of Regulation. Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of Statement No. 71 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that the regulated segment no longer meets the criteria of regulatory accounting under Statement No. 71, that segment will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements.

The application of Statement No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the Kentucky Public Service Commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred, or they represent probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements. We believe it is probable that we will recover the regulatory assets that have been recorded.

Pension

Our reported costs of providing pension benefits (as described in Note 5(a) of the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.

Pension costs associated with our defined benefit pension plan, for example, are impacted by employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plan and earnings on plan assets. Additionally, changes made to the provisions of the plan may impact current and future pension costs. Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

Changes in pension obligations associated with the above factors may not be immediately recognized as pension costs in the Consolidated Statements of Income, but may be deferred and amortized in the future over the average remaining service period of active plan participants. For the years ended June 30, 2009, 2008 and 2007, we recorded pension costs for our defined benefit pension plan of $608,000, $670,000 and $567,000, respectively.

Our pension plan assets are principally comprised of equity and fixed income investments. Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods. Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.

In selecting our discount rate assumption we considered rates of return on high-quality fixed-income investments that are expected to be available through the maturity dates of the pension benefits. Our expected long-term rate of return on pension plan assets was 7% for 2009 and was based on our targeted asset allocation assumption of approximately 65% equity investments and approximately 35% fixed income investments. Our target investment allocation for equity investments includes allocations to domestic, international, and emerging markets. Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

We calculate the expected return on assets in our determination of pension costs based on the market value of assets at the measurement date. Using the market value recognizes investment gains or losses in the year in which they occur.

Based on an assumed long-term rate of return of 7%, discount rate of 6.25%, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plan will increase from $608,000 in 2009 to $1,040,000 in 2010. Modifying the expected long-term rate of return on our pension plan assets by .25% would change pension costs for 2010 by approximately $34,000. Increasing the discount rate assumption by .25% would decrease pension costs by approximately $43,000. Decreasing the discount rate assumption by .25% would increase pension costs by approximately $45,000.

Effective May 9, 2008, any employees hired on and after that date are not eligible to participate in our defined benefit pension plan. Freezing the plan to new entrants did not impact the level of benefits for existing participants.

Effective July 1, 2008, we adopted the measurement date provision of Financial Accounting Standards Board Statement No. 158 entitled Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, which required us to change the measurement date of our defined benefit plan from March 31 to June 30. Pension costs from April 1, 2008 to June 30, 2009 were $760,000. Of this amount, $152,000 is attributable to the change in measurement dates and (net of tax effects of $58,000) was charged directly to retained earnings on July 1, 2008.

Provisions for Doubtful Accounts

We encounter risks associated with the collection of our accounts receivable. As such, we record a monthly provision for accounts receivable that are considered to be uncollectible. In order to calculate the appropriate monthly provision, we primarily utilize our historical experience related to accounts written-off. Quarterly, at a minimum, we review the reserve for reasonableness based on the level of revenue and the aging of the receivable balance. The underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the Consolidated Statements of Income and working capital. The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact operating income.

Unbilled Revenues and Gas Costs

At each month-end, we estimate the gas service that has been rendered from the date the customer's meter was last read to month-end. This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather-sensitive usage for each degree day during the unbilled period. Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month-end. Actual usage patterns may vary from these assumptions and may impact operating income.

Asset Retirement Obligations

We have accrued asset retirement obligations for gas well plugging and abandonment costs. Additionally, we have recorded asset retirement obligations required pursuant to Federal regulations related to the retirement of our service lines and mains, although the timing of such retirements is uncertain. The fair value of our retirement obligations are recorded at the time the obligations are incurred. We do not recognize asset retirement obligations relating to assets with indeterminate useful lives. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time the liabilities are accreted for the change in their present value, through depreciation, and the initial capitalized costs are depreciated over the useful lives of the related assets. For asset retirement obligations attributable to assets of our regulated operations, the depreciation and accretion are deferred as a regulatory asset. We must use judgment to identify all appropriate asset retirement obligations. The underlying assumptions used for the value of the retirement obligations and related capitalized costs can change from period to period. These assumptions include the estimated future retirement costs, the estimated retirement date and the assumed credit-adjusted risk-free interest rate. Our asset retirement obligations are discussed in Note 3 of the Notes to Consolidated Financial Statements.

New Accounting Pronouncements

Significant management judgment is generally required during the process of adopting new accounting pronouncements. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of these pronouncements.

Forward-Looking Statements

Management's Discussion and Analysis of Financial Condition and Results of Operations and the other sections of this report contain forward-looking statements that relate to future events or our future performance. We have attempted to identify these statements by using words such as "estimates", "attempts", "expects", "monitors", "plans", "anticipates", "intends", "continues", "strives" ,"seeks", "will rely", "believes" and similar expressions.

These forward-looking statements include, but are not limited to, statements about:

· operational plans,

· the cost and availability of our natural gas supplies,

· capital expenditures,

· sources and availability of funding for our operations and expansion,

· anticipated growth and growth opportunities through system expansion and acquisition,

· competitive conditions that we face,

· production, storage, gathering and transportation activities,

· acquisition of service franchises from local governments,

· pension fund costs and management,

· contractual obligations and cash requirements,

· management of our gas supply and risks due to potential fluctuation in the price of natural gas,

· revenues, income, margins and profitability,

· efforts to purchase and transport locally produced natural gas,

· recovery of regulatory assets,

· regulatory and legislative matters, and

· dividends.

Our forward-looking statements are not guarantees of future performance and are based upon currently available competitive, financial and economic data along with our operating plans.

Item 1A. Risk Factors lists factors that could cause future results to differ
materially from those expressed in or implied by the forward-looking statements or historical results.

Results of Operations

Gross Margins

Our regulated and non-regulated revenues, other than transportation, have offsetting gas expenses. Therefore, throughout the following Results of Operations, we refer to "gross margin". With respect to our regulated and non-regulated segments, gross margin refers to operating revenues less purchased gas expense, which can be derived directly from our Consolidated Statements of Income. Operating Income as presented in the Consolidated Statements of Income, is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States ("GAAP"). "Gross margin" is a "non-GAAP financial measure", as defined in accordance with SEC rules. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key . . .