PART I - FINANCIAL INFORMATION

ITEM 1.   FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF LOSS

(UNAUDITED)

  

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

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DELTA NATURAL GAS COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED) 

 

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

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DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)	Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. ("Delta" or "the Company") distributes or transports natural gas to approximately 36,000 customers.  Our distribution and transmission systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky.  We transport natural gas to our industrial customers who purchase their natural gas in the open market and we transport natural gas on behalf of local producers and customers not on our distribution system.  We also sell liquids extracted from natural gas in our storage field and on our distribution system.  We have three wholly-owned subsidiaries.  Delta Resources, Inc. ("Delta Resources") buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. ("Delgasco") buys gas and resells it to Delta Resources and to customers not on Delta's system.  Enpro, Inc. ("Enpro") owns and operates production properties and undeveloped acreage.

All subsidiaries of Delta are included in the condensed consolidated financial statements. Intercompany balances and transactions have been eliminated.  All adjustments necessary for a fair presentation of the unaudited results of operations for the three months ended September 30, 2012 and 2011 are included.  All such adjustments are accruals of a normal and recurring nature other than the amounts accrued by Delta Resources related to an assessment of the Utility Gross Receipts License Tax discussed in Note 7.

The results of operations for the period ended September 30, 2012 are not necessarily indicative of the results of operations to be expected for the full fiscal year.  Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably.  Most construction activity and gas storage injections take place during these warmer months.

The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the financial statements, and the notes thereto, included in our Annual Report on Form 10-K for the year ended June 30, 2012.

(2)	Fair Value Measurements

Our financial assets and liabilities measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in other non-current assets on the Condensed Consolidated Balance Sheets.  Contributions to the trust are presented in other investing activities on the Condensed Consolidated Statements of Cash Flows.  The assets of the trust are recorded at fair value and consist of exchange traded mutual funds.  The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy.  The fair value of the trust assets are as follows:

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The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value.

Our Series A Notes, presented as current portion of long-term debt and long-term debt on the Condensed Consolidated Balance Sheets, are stated at historical cost.  Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate.  The credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date.  The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy.

(3)	Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk.  We purchase our natural gas supply through a combination of spot market and forward purchases.  We mitigate commodity price risk by efforts to balance supply and demand.  For our regulated segment, we have minimal price risk resulting from these forward natural gas purchases because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.  None of our gas contracts are accounted for using the fair value method of accounting.  While some of our natural gas purchase contracts and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

(4)	Unbilled Revenue

We bill our customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled.

Unbilled revenues and gas costs include the following:

Unbilled revenues are included in accounts receivable and unbilled gas costs are included in deferred gas costs on the accompanying Condensed Consolidated Balance Sheets.  Unbilled revenues are included in regulated revenues and unbilled gas costs are included in regulated purchased gas on the accompanying Condensed Consolidated Statements of Loss.

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(5)	Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, noncontributory defined benefit retirement plan for the periods ended September 30 include the following:

(6)	Debt Instruments

Notes Payable

The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available as of September 30, 2012 and June 30, 2012.  The bank line of credit extends through June 30, 2013.  The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.15%.  The annual cost of the unused bank line of credit is .125%.

We were not in default on our bank line of credit during any period presented in the Condensed Consolidated Financial Statements.

Long-Term Debt

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031.  Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. The following table summarizes the contractual maturities of our Series A Notes by fiscal year:

Any additional prepayment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with a maturity equal to the remaining average life of the Series A Notes.

We were not in default on any covenants on our long-term debt during any period presented in the Condensed Consolidated Financial Statements.

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(7)	Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change of control agreements with our other four officers.  The agreements expire or may be terminated at various times.  The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company.  In the event all of these agreements were exercised in the form of lump sum payments, approximately $3.7 million would be paid in addition to continuation of specified benefits for up to five years.  Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements, would immediately vest.

The Kentucky Department of Revenue has assessed Delta Resources $5,565,000, which includes $3,013,000 in taxes, $1,963,000 in penalties and $589,000 in interest, for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011.  The tax is a 3% license tax levied on the gross receipts derived from furnishing utility services and is passed through to customers.  The Kentucky Department of Revenue has not asserted a claim for the tax periods after June, 2011 or interest accrued subsequent to the initial assessments.  Regarding the penalties, Kentucky law provides for the assessment of penalties for failure to pay a tax, unless it is shown to the satisfaction of the Kentucky Department of Revenue that the failure to pay is due to reasonable cause.  Applicable regulatory authority provides that reasonable cause exists when the tax position is based on advice by a tax advisor on whom the taxpayer had a reasonable right to rely or substantial legal authority, as we have done in this matter.  Therefore, as of September 30, 2012, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,978,000, which includes $3,055,000 in taxes and $923,000 in interest.

We protested the assessment with the Kentucky Department of Revenue.  Our position with the Department is that the Utility Gross Receipts License Tax applies only to utilities regulated by the Kentucky Public Service Commission.  Delta Resources is a natural gas marketer which is not regulated by the Kentucky Public Service Commission and, thus, we contend, it is exempt from the utility tax.  The position is based on case law and long-standing opinions issued by the State Attorney General and was further upheld in an opinion by the Commonwealth of Kentucky Fayette Circuit Court in May, 2010 in a case styled Commonwealth of Kentucky, Finance and Administration Cabinet, Department of Revenue v. Saint Joseph Health System, Inc.; Constellation New Energy-Gas Division, LLC; and Board of Education of Fayette County, Kentucky, stating that the Utility Gross Receipts License Tax did not apply to sales of gas by Constellation, a gas marketer, because it is not a utility.  

However, in October, 2011, the Kentucky Court of Appeals reversed the May, 2010 Fayette Circuit Court opinion and Saint Joseph Health System, Inc. subsequently filed a petition for rehearing the Kentucky Court of Appeals decision.  In  January, 2012, upon the denial of the petition for re-hearing, Saint Joseph Health System, Inc. filed a petition for discretionary review of the case by the Kentucky Supreme Court. In October, 2012, the Kentucky Supreme Court denied discretionary review of the case, therefore, the October, 2011 Kentucky Court of Appeals decision will likely become final in November, 2012.

As a result of the uncertainty created by the October, 2011 opinion issued by the Kentucky Court of Appeals, in September, 2011 we accrued $3,803,000 of taxes and interest and continue to accrue interest on the assessment.  Delta Resources' began billing customers the Utility Gross Receipts License Tax prospectively with our October, 2011 billings and since then has billed its customers $189,000, substantially all of which has been collected.  The publication of the October, 2011 Kentucky Court of Appeals decision increases the probability of Delta Resources having to either pay the assessment or appeal the denial of the assessment through the courts.

In the event we are required to pay the assessment of $3,978,000, Delta Resources would have the right to seek reimbursement from its customers for $3,055,000 of taxes, leaving Delta Resources liable for $923,000 of interest in addition to any uncollectible amounts.  We estimate that Delta Resources' potential liability for interest and taxes deemed uncollectible from Delta Resources' customers to be in the range of $930,000 to $3,978,000.  This estimate is based on the assumption that we will not be held liable for any penalties.

 

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As of September 30, 2012, we have recorded the total liability of $3,978,000, a receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $923,000 of accrued interest and $7,000 of allowance for doubtful accounts.  Included in the receivable is $196,000 due from a Delta Resources customer which is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the Condensed Consolidated Balance Sheets, the liability for taxes is included in accrued taxes, the receivable from Delta Resources' customers is included in accounts receivable, less accumulated allowances for doubtful accounts, and the liability for interest is included in accrued interest on debt.  In the Condensed Consolidated Statements of Loss, interest accrued is included in interest charges and uncollectible amounts are included in operation and maintenance.

We are not a party to any other material pending legal proceedings.

We have entered into forward purchase agreements beginning in October, 2012 and expiring at various dates through December, 2013.  These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements.  These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements.  These agreements have aggregate minimum purchase obligations of $614,000 and $211,000 for our fiscal year ended June 30, 2013 and June 30, 2014, respectively.

(8)	Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services.  Their regulation of our business includes approving the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services.  They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.  We do not have any matters pending before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial positions or cash flows.

(9)	Operating Segments

Our Company has two reportable segments:  (i) a regulated natural gas distribution and transmission segment and (ii) a non-regulated segment that participates in related ventures, consisting of natural gas marketing, natural gas production and sales of natural gas liquids.  Virtually all of the revenues recorded under both segments come from the sale or transportation of natural gas, or related sales of natural gas liquids.  The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky.  Price risk for the regulated segment is mitigated through our gas cost recovery clause, approved quarterly by the Kentucky Public Service Commission.  Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand.  However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict our demand.  In addition, we are exposed to price risk resulting from changes in the market price of natural gas, natural gas liquids and uncommitted natural gas inventory of our non-regulated companies.

The reportable segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements that are included in our Annual Report on Form 10-K for the year ended June 30, 2012.  Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services.  Intersegment transportation revenues and expenses represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates.  Operating expenses, taxes and interest are allocated to the non-regulated segment.

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Segment information is shown in the following table:

Under our incentive compensation plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements.  Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met.  If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end.  The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  As of September 30, 2012 and 2011, there were 39,000 and 36,000 unvested non-participating shares outstanding, respectively, which are not dilutive as the underlying performance condition has not yet been met.

Additionally, certain awards provide recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares.  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive.  As of September 30, 2012 and 2011 there were 29,000 and 21,000 unvested participating shares outstanding, respectively.  The unvested participating shares are excluded from the computation of diluted weighted average common shares as of September 30, 2012 and 2011, as the shares would have an antidilutive effect on the net loss per common share.

We have a shareholder approved incentive compensation plan (the "Plan") that provides for incentive compensation awards payable in shares of our common stock. The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining which employees, officers and outside directors shall be eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan.  In accordance with the provisions of the Plan, the number of shares that may be issued under the Plan and all unvested shares have been adjusted for the two-for-one stock split that was distributed on May 1, 2012, as further discussed in Note 12 of Notes to Condensed Consolidated Financial Statements.

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The number of shares of our common stock that may be issued pursuant to the Plan may not exceed in the aggregate 1,000,000 shares.  As of September 30, 2012, 889,000 shares of common stock were available for issuance under the Plan.  Shares of common stock may be issued from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market. 

Compensation expense for share-based compensation is recorded in operation and maintenance expense in the Condensed Consolidated Statements of Loss based on the fair value of the awards at the grant date and is amortized over the requisite service period.  Fair value is the closing price of our common shares at the grant date.  The grant date is the date at which our commitment to issue the share-based awards arises, which is generally when the award is approved and the terms of the awards are communicated to the employee or director.  We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met.

For the three months ended September 30, 2012 and 2011, a $26,000 and $22,000 tax benefit, respectively, was recognized as an increase to premium on common shares on our Condensed Consolidated Balance Sheets, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation.  This excess tax benefit can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods.

Stock Awards

For the three months ended September 30, 2012 and 2011, common stock was awarded as a stock bonus to virtually all Delta employees and directors having grant date fair values of $264,000 (12,000 shares) and $337,000 (22,000 shares), respectively.  The recipients vested in the awards shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock bonus awards were immediately transferable.

Performance Shares

For the three months ended September 30, 2012 and 2011, performance shares were awarded to the Company's executive officers having grant date fair values of $844,000 (39,000 shares) and $552,000 (36,000 shares),  respectively. The performance share awards vest only if the performance objectives of the awards are met, which are based on the Company's earnings per common share for the fiscal year in which the performance shares are awarded, before any cash bonuses or share-based compensation. Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest equally over a three-year period beginning each August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period.  The recipients of the awards also become vested as a result of certain events such as death or disability of the holders. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards.  Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

For the three months ended September 30, 2012 and 2011, compensation expense related to the performance shares was $104,000 and $78,000, respectively.   As of September 30, 2012 and 2011, there were 29,000 and 21,000 unvested performance shares outstanding, respectively, for which the performance objectives have been satisfied.

Our performance shares have graded vesting schedules, and each separate annual vesting tranche is treated as a separate award for expense recognition.  Compensation expense is amortized over the vesting period of the individual awards based on the probable outcome of meeting the performance objectives.

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On February 17, 2012, the Company's Board of Directors declared a two-for-one stock split of the Company's issued and outstanding common stock, par value $1.00 per share.  The stock split was distributed May 1, 2012 to all shareholders of record on April 17, 2012.  As a result of the stock split, all amounts related to shares, share prices and earnings per share have been retroactively restated, where appropriate, in the condensed consolidated financial statements and notes thereto.

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

YEAR TO DATE SEPTEMBER 30, 2012 OVERVIEW AND FUTURE OUTLOOK

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 the three months ended September 30, 2012. Our Company has two segments:  (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing, natural gas production and the sale of liquids extracted from natural gas.

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 by 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 to match estimated demand with supply and provide an acceptable margin.  The non-regulated segment also produces natural gas and sells liquids extracted from natural gas.

Our consolidated net loss per common share for the three months ended September 30, 2012, decreased $.10 as compared to the same period in the prior year.  This decrease is primarily due to a decrease in interest expense resulting from the prior year accrual of interest on a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements) and a reduction in interest expense on our long-term debt due to the refinancing of our 7% Debentures and 5.75% Insured Quarterly Notes in December, 2011 by the issuance of our 4.26% Series A Notes.

Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers.  The Kentucky Public Service Commission sets these rates, and we monitor our need to file rate cases with the Kentucky Public Service Commission for a general rate increase for our regulated services.  The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers.  We manage remaining expenses through budgeting, approval and review.

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Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large use customers and the market prices of natural gas and natural gas liquids, all of which are beyond our control.  We anticipate our non-regulated segment to continue to contribute to our consolidated net income in fiscal 2013.  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 and marketing 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.  We anticipate selling additional natural gas liquids in 2013.  The profitability of such sales is dependent on the amount of liquids extracted and the pricing for any such liquids as determined in the national unregulated market.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of our net loss adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital.  Our sales and cash requirements are seasonal.  The largest portion of our sales occurs during the heating months (December through April), whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months.  Therefore, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit.  The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000.  There were no borrowings outstanding on the bank line of credit as of September 30, 2012 or June 30, 2012.

Cash and cash equivalents were $4,247,000 at September 30, 2012, as compared with $9,741,000 at June 30, 2012.  The changes in cash and cash equivalents are summarized in the following table:

For the three months ended September 30, 2012, cash used in operating activities decreased $3,994,000 (60%) as compared to the same period in the prior year.  Cash paid for natural gas decreased $8,244,000 as a result of a decrease in volumes of natural gas purchased for storage as we did not need to refill all of our storage inventory due to volumes remaining in storage from the previous year as a result of warmer than normal weather, and due to a decrease in the market price of natural gas purchased.  This decrease was partially offset by a $2,228,000 decrease in cash received from customers due to a decrease in sales prices and a $2,300,000 elective contribution made in August, 2012 to our defined benefit pension plan to maintain the fully-funded status of the plan.

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

For the three months ended September 30, 2012, cash provided by financing activities decreased $2,620,000 (167%) as a result of not borrowing on our bank line of credit since we had sufficient cash to meet our operating and capital expenditure requirements.

Cash Requirements

Our capital expenditures result in a continued need for capital. These capital expenditures are 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 2013 to be approximately $7.5 million.

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Sufficiency of Future Cash Flows

Our ability to maintain liquidity, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated base rates we charge our customers.  The Kentucky Public Service Commission sets these rates and we monitor our need to file for rate increases for our regulated segment.  Our regulated rates were most recently adjusted in our 2010 rate case and became effective October, 2010.  We expect that cash provided by operations, coupled with short-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the remainder of fiscal 2013.

To the extent that internally generated cash is not sufficient to satisfy seasonal 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 permits borrowings up to $40,000,000.  There were no borrowings outstanding on the bank line of credit as of September 30, 2012.

In December, 2011, we issued $58,000,000 of Series A Notes that are unsecured, bear interest at a fixed rate of 4.26% per annum that is payable quarterly, and which mature on December 20, 2031.  Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. 

Any additional prepayment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with maturities equal to the remaining average life of the Series A Notes.

 The Agreement for the Series A Notes contains a private shelf facility that extends through December, 2013.  We may, with mutual agreement between us and the purchasers or their affiliates, issue them additional long-term unsecured promissory notes of the Company in an aggregate principal amount of $17,000,000.

With our bank line of credit and Series A Notes, we have agreed to certain financial, affirmative and negative covenants.  Noncompliance with these covenants can make the obligation immediately due and payable, as further discussed in our Annual Report on Form 10-K for the year ended June 30, 2012.  A default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with our bank line of credit and the Series A Notes. We were not in default on our bank line of credit or Series A Notes during any period presented in the Condensed Consolidated Financial Statements.

RESULTS OF OPERATIONS

Gross Margins

Our operating revenues are derived primarily from the sale of natural gas and natural gas liquids and the provision of natural gas transportation services.  We define "gross margins" as gas sales less the corresponding purchased gas expenses, plus transportation, natural gas liquids and other revenues. We view gross margins as an important performance measure of the core profitability of our operations, and we believe investors benefit from having access to the same financial measures that our management uses.  Gross margin can be derived directly from our Condensed Consolidated Statements of Loss as follows:

(a)	Amounts derived from the Condensed Consolidated Statements of Loss included in Item 1.  Financial Statements.

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Operating Income, as presented in the Condensed Consolidated Statements of Loss, 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.

Natural gas prices are determined by an unregulated national market.  Therefore, the price that we pay for natural gas fluctuates with national supply and demand. See Item 3 for the impact of forward contracts.

In the following table we set forth variations in our gross margins for the three months ended September 30, 2012 compared with the same period in the preceding year.  The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions.  These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Loss.

(a)	Intersegment eliminations represent the transportation fee charged by the regulated segment to the non-regulated segment.

For the three months ended September 30, 2012, consolidated gross margins increased $292,000 (5%), as compared to the same period in the prior year, due to increased non-regulated gross margins of $299,000.  Our non-regulated gross margins increased primarily due to the sale of liquids extracted from natural gas.  In September, 2011, we completed the installation of a facility to extract liquids from the natural gas in our system in order to improve the operations of our distribution, transmission and storage systems.

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Operation and Maintenance

For the three months ended September 30, 2012, operation and maintenance expenses increased $332,000 (11%), as compared to the same period in the prior year, primarily due to receipt of $300,000 in the prior year of insurance proceeds which offset operation and maintenance expense relating to a gas inventory adjustment recorded in fiscal 2009 for the Company's underground storage field.

Depreciation and Amortization

For the three months ended September 30, 2012, depreciation and amortization increased $47,000 (3%), as compared to the same period in the prior year, primarily due to a corresponding increase in our net property, plant and equipment.

Taxes Other Than Income Taxes

For the three months ended September 30, 2012, taxes other than income taxes increased $62,000 (12%), as compared to the same period in the prior year, due to increased property tax expense resulting from both higher assessed values and rates assessed by taxing jurisdictions.

Other Income and Deductions, Net

For the three months ended September 30, 2012, other income and deductions, net increased $124,000 (165%), as compared to the same period in the prior year, due to an increase in the fair value of the supplemental retirement trust and an increase in the cash surrender value of life insurance.  The increase in the fair value of the supplemental retirement trust was offset by an increase in operating expense resulting from a corresponding increase in the liability of the trust.

Interest Charges

For the three months ended September 30, 2012, interest charges decreased $1,012,000 (58%), as compared to the same period in the prior year, due to a $701,000 decrease in interest accrued for a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements) and a $275,000 decrease in interest on long-term debt as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures with 4.26% Series A Notes.

Income Tax Benefit

For the three months ended September 30, 2012, the income tax benefit decreased $348,000 (74%) due to a decrease in our net loss before income taxes, as compared to the same period in the prior year. There were no significant changes to our effective tax rate for the three months ended September 30, 2012.

Basic and Diluted Loss Per Common Share

For the three months ended September 30, 2012, our basic and diluted loss per common share changed as a result of a change in our net loss and an increase in the number of our common shares outstanding.  We increased our number of common shares outstanding as a result of shares issued through our Dividend Reinvestment and Stock Purchase Plan as well as those shares awarded through our incentive compensation plan.

Under our incentive compensation plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements.  Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met.  If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end.  The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  As of September 30, 2012 and 2011, there were 39,000 and 36,000 unvested non-participating shares outstanding, respectively, which are not dilutive as the underlying performance condition has not yet been met.

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Certain unvested awards under our shareholder approved incentive compensation plan, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta Natural Gas Company, Inc. including a right to dividends declared on common shares.  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive.  As of September 30, 2012 and 2011, there were 29,000 and 21,000 unvested participating shares outstanding, respectively.  The unvested participating shares are excluded from the computation of diluted weighted average common shares outstanding as of September 30, 2012 and 2011, as the shares would have an antidilutive effect on the net loss per common share.

In accordance with the provisions of our incentive compensation plan, all unvested shares have been adjusted for the two-for-one stock split distributed in May, 2012, as further discussed in Note 12 of the Notes to Consolidated Financial Statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We purchase our natural gas supply through a combination of spot market and forward purchases.  The price of spot market natural gas is based on the market price at the time of delivery.  The price we pay for our natural gas supply acquired under our forward natural gas purchase contracts, however, is fixed prior to the delivery of the natural gas.  Additionally, we inject some of our natural gas purchases into a gas storage facility in the non-heating months and withdraw this natural gas from storage for delivery to customers during the heating months.  For our regulated business, we have minimal price risk resulting from these forward natural gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand.  However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand.  In addition, we are exposed to changes in the market price of natural gas on uncommitted gas inventory of our non-regulated companies.

None of our natural gas contracts are accounted for using the fair value method of accounting.  While some of our natural gas purchase and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.  As of September 30, 2012, we had forward purchase contracts totaling $825,000 that have various terms with the last contract expiring in December, 2013.  These forward purchase contracts are at a fixed price and not impacted by changes in the market price of natural gas.

When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates.  The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate.  There were no borrowings outstanding on our bank line of credit as of September 30, 2012 or 2011.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized, and reported within the time periods specified by the Securities and Exchange Commission's rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of September 30, 2012, and, based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended September 30, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 1.	LEGAL PROCEEDINGS
	The Kentucky Department of Revenue has assessed Delta Resources for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011.  We are currently protesting the assessment with the Kentucky Department of Revenue and the outcome is uncertain; therefore we are unable to predict whether the issue will ultimately have a materially adverse impact on our liquidity, financial position or results of operations.  A discussion of the assessment and protest is provided in Note 7 of the Notes to Condensed Consolidated Financial Statements. Other than the protest of the assessment for the 3% Utility Gross Receipts License Tax, we are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.

ITEM 1A.	RISK FACTORS
	No material changes.

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
	None.
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES
	None.
ITEM 4.	MINE SAFETY DISCLOSURES
	None.
ITEM 5.	OTHER INFORMATION
	None.
ITEM 6.	EXHIBITS

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23

DATE:  November 6, 2012		/s/Glenn R. Jennings
		Glenn R. Jennings Chairman of the Board, President and Chief Executive Officer (Duly Authorized Officer)
		/s/John B. Brown
		John B. Brown Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer)