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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549
______________

FORM 10-Q

______________
(Mark one)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2012

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to ________

Commission File No. 0-8788
______________

DELTA NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
______________

Kentucky
61-0458329
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

3617 Lexington Road, Winchester, Kentucky
40391
(Address of principal executive offices)
(Zip code)

859-744-6171
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or Section 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x    No  £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).          Yes x     No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer     £
Accelerated filer     x
Non-accelerated filer   £ (Do not check if a smaller reporting company)
Smaller reporting company     £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes £   No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
As of December 31, 2012, Delta Natural Gas Company, Inc. had 6,849,709 shares of Common Stock outstanding.

1



DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

PART I -
FINANCIAL INFORMATION
 
3
 
 
 
 
ITEM 1.
Financial Statements
 
3
 
 
 
 
 
Condensed Consolidated Statements of Income (Unaudited) for the three and six month periods ended December 31, 2012 and 2011
 
3
 
 
 
 
 
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2012 and June 30, 2012
 
4
 
 
 
 
 
Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the six month periods ended December 31, 2012 and 2011
 
6
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six month periods ended December 31, 2012 and 2011
 
7
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements (Unaudited)
 
8
 
 
 
 
ITEM 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
16
 
 
 
 
ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
 
21
 
 
 
 
ITEM 4.
Controls and Procedures
 
21
 
 
 
 
PART II -
OTHER INFORMATION
 
22
 
 
 
 
ITEM 1.
Legal Proceedings
 
22
 
 
 
 
ITEM 1A.
Risk Factors
 
22
 
 
 
 
ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
22
 
 
 
 
ITEM 3.
Defaults Upon Senior Securities
 
22
 
 
 
 
ITEM 4.
Mine Safety Disclosures
 
22
 
 
 
 
ITEM 5.
Other Information
 
22
 
 
 
 
ITEM 6.
Exhibits
 
22
 
 
 
 
 
Signatures
 
24
 
 
 
 

2

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
   
 
Three Months Ended
   
Six Months Ended
 
 
 
December 31,
   
December 31,
 
 
 
2012
   
2011
   
2012
   
2011
 
 
 
   
   
   
 
OPERATING REVENUES
 
   
   
   
 
Regulated revenues
 
$
13,299,004
   
$
12,978,686
   
$
19,040,475
   
$
18,601,322
 
Non-regulated revenues
   
8,807,687
     
9,547,659
     
14,518,530
     
16,821,350
 
Total operating revenues
 
$
22,106,691
   
$
22,526,345
   
$
33,559,005
   
$
35,422,672
 
 
                               
OPERATING EXPENSES
                               
Regulated purchased gas
 
$
5,056,894
   
$
5,084,667
   
$
6,382,896
   
$
6,286,064
 
Non-regulated purchased gas
   
6,666,379
     
7,181,920
     
10,811,536
     
13,187,072
 
Operation and maintenance
   
3,360,561
     
3,244,930
     
6,827,984
     
6,380,145
 
Depreciation and amortization
   
1,520,682
     
1,481,143
     
3,028,559
     
2,941,718
 
Taxes other than income taxes
   
534,320
     
549,391
     
1,124,228
     
1,077,278
 
 
                               
Total operating expenses
 
$
17,138,836
   
$
17,542,051
   
$
28,175,203
   
$
29,872,277
 
 
                               
OPERATING INCOME
 
$
4,967,855
   
$
4,984,294
   
$
5,383,802
   
$
5,550,395
 
 
                               
OTHER INCOME (DEDUCTIONS), NET
   
8,632
     
52,485
     
57,639
     
(22,179
)
 
                               
INTEREST (INCOME) EXPENSE
   
(228,933
)
   
1,023,650
     
515,890
     
2,780,782
 
 
                               
NET INCOME BEFORE INCOME TAXES
 
$
5,205,420
   
$
4,013,129
   
$
4,925,551
   
$
2,747,434
 
 
                               
INCOME TAX EXPENSE
   
1,956,044
     
1,500,891
     
1,835,077
     
1,032,322
 
 
                               
NET INCOME
 
$
3,249,376
   
$
2,512,238
   
$
3,090,474
   
$
1,715,112
 
 
                               
INCOME PER COMMON SHARE (Notes 10 and 12)
Basic
 
$
.47
   
$
.37
   
$
.45
   
$
.25
 
Diluted
 
$
.47
   
$
.37
   
$
.45
   
$
.25
 
 
                               
DIVIDENDS DECLARED PER COMMON SHARE (Note 12)
 
$
.18
   
$
.175
   
$
.36
   
$
.35
 










The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.
3

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
  
 
 
December 31,
   
June 30,
 
 
 
2012
   
2012
 
ASSETS
 
   
 
 
 
   
 
CURRENT ASSETS
 
   
 
Cash and cash equivalents
 
$
1,860,336
   
$
9,740,502
 
Accounts receivable, less accumulated allowances for doubtful accounts of $97,000 and $157,000, respectively
   
14,895,006
     
8,028,937
 
Gas in storage, at average cost
   
6,252,461
     
6,932,807
 
Deferred gas costs
   
3,777,669
     
3,386,292
 
Materials and supplies, at average cost
   
546,303
     
557,118
 
Prepayments
   
1,862,419
     
2,393,674
 
Total current assets
 
$
29,194,194
   
$
31,039,330
 
 
               
PROPERTY, PLANT AND EQUIPMENT
 
$
220,391,491
   
$
217,172,542
 
Less-Accumulated provision for depreciation
   
(85,757,970
)
   
(82,835,542
)
Net property, plant and equipment
 
$
134,633,521
   
$
134,337,000
 
 
               
OTHER ASSETS
               
Cash surrender value of life insurance
 
$
317,498
   
$
307,125
 
Regulatory assets
   
17,102,444
     
16,517,812
 
Unamortized debt expense
   
100,504
     
104,104
 
Other non-current assets
   
681,285
     
589,992
 
Total other assets
 
$
18,201,731
   
$
17,519,033
 
 
               
Total assets
 
$
182,029,446
   
$
182,895,363
 
 
               


















The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.
4


DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (continued)
(UNAUDITED)

 
 
December 31,
   
June 30,
 
 
 
2012
   
2012
 
 
 
   
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
   
 
 
 
   
 
CURRENT LIABILITIES
 
   
 
Accounts payable
 
$
5,032,366
   
$
4,325,653
 
Current portion of long-term debt
   
1,500,000
     
1,500,000
 
Accrued taxes
   
3,567,706
     
4,154,064
 
Customers' deposits
   
876,911
     
853,061
 
Accrued interest on debt
   
140,793
     
1,026,387
 
Accrued vacation
   
624,142
     
736,856
 
Deferred income taxes
   
1,345,546
     
1,130,581
 
Other current liabilities
   
440,986
     
436,281
 
Total current liabilities
 
$
13,528,450
   
$
14,162,883
 
 
               
LONG-TERM DEBT
 
$
55,000,000
   
$
56,500,000
 
 
               
LONG-TERM LIABILITIES
               
Deferred income taxes
 
$
39,172,303
   
$
37,732,457
 
Investment tax credits
   
51,650
     
62,700
 
Regulatory liabilities
   
1,300,064
     
1,380,838
 
Accrued pension
   
497,465
     
2,307,260
 
Asset retirement obligations
   
3,954,845
     
3,823,724
 
Other long-term liabilities
   
812,203
     
705,094
 
Total long-term liabilities
 
$
45,788,530
   
$
46,012,073
 
 
               
COMMITMENTS AND CONTINGENCIES (Note 7)
               
Total liabilities
 
$
114,316,980
   
$
116,674,956
 
 
               
SHAREHOLDERS' EQUITY
               
Common shares ($1.00 par value), 20,000,000 shares
               
authorized, 6,849,709 and 6,803,941 shares
               
outstanding at December 31, 2012 and June 30,
               
2012, respectively
 
$
6,849,709
   
$
6,803,941
 
Premium on common shares
   
44,876,999
     
44,048,201
 
Retained earnings
   
15,985,758
     
15,368,265
 
Total shareholders' equity
 
$
67,712,466
   
$
66,220,407
 
 
               
Total liabilities and shareholders' equity
 
$
182,029,446
   
$
182,895,363
 














The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.
5

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(UNAUDITED)
 
 
 
 
 
 
Six Months Ended December 31, 2012
 
 
 
Common Shares
   
Premium on Common Shares
   
Retained Earnings
   
Shareholders' Equity
 
 
 
   
   
   
 
Balance, beginning of period
 
$
6,803,941
   
$
44,048,201
   
$
15,368,265
   
$
66,220,407
 
Net income
   
     
     
3,090,474
     
3,090,474
 
Issuance of common shares
   
13,892
     
263,085
     
     
276,977
 
Issuance of common shares under the
                               
incentive compensation plan
   
31,876
     
232,226
     
     
264,102
 
Share-based compensation expense
   
     
307,321
     
     
307,321
 
Excess tax benefit from share-based compensation
   
     
26,166
     
     
26,166
 
Dividends on common shares
   
     
     
(2,472,981
)
   
(2,472,981
)
 
                               
Balance, end of period
 
$
6,849,709
   
$
44,876,999
   
$
15,985,758
   
$
67,712,466
 



 
 
 
 
 
Six Months Ended December 31, 2011
 
 
 
Common Shares
   
Premium on Common Shares
   
Retained Earnings
   
Shareholders' Equity
 
 
 
   
   
   
 
Balance, beginning of period
 
$
6,732,344
   
$
42,688,316
   
$
14,346,524
   
$
63,767,184
 
Net income
   
     
     
1,715,112
     
1,715,112
 
Issuance of common shares
   
19,854
     
302,516
     
     
322,370
 
Issuance of common shares under the
                               
incentive compensation plan
   
22,000
     
315,040
     
     
337,040
 
Share-based compensation expense
   
10,668
     
166,351
     
     
177,019
 
Excess tax benefit from share-based compensation
   
     
21,562
     
     
21,562
 
Dividends on common shares
   
     
     
(2,377,135
)
   
(2,377,135
)
 
                               
Balance, end of period
 
$
6,784,866
   
$
43,493,785
   
$
13,684,501
   
$
63,963,152
 










The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.
6

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED) 
 
 
Six Months Ended
 
 
 
December 31,
 
 
 
2012
   
2011
 
 
 
   
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
   
 
Net income
 
$
3,090,474
   
$
1,715,112
 
Adjustments to reconcile net income to net cash used in operating activities
               
Depreciation and amortization
   
3,198,159
     
3,176,190
 
Deferred income taxes and investment tax credits
   
1,584,780
     
593,277
 
Change in cash surrender value of officer's life insurance
   
(10,373
)
   
12,895
 
Share-based compensation
   
571,423
     
514,059
 
Excess tax deficiency from share-based compensation
   
(8,946
)
   
 
Increase in assets
   
(6,181,084
)
   
(13,907,021
)
Increase (decrease) in liabilities
   
(2,827,989
)
   
471,948
 
 
               
Net cash used in operating activities
 
$
(583,556
)
 
$
(7,423,540
)
 
               
CASH FLOWS FROM INVESTING ACTIVITIES
               
Capital expenditures
 
$
(3,607,119
)
 
$
(3,611,725
)
Proceeds from sale of property, plant and equipment
   
31,401
     
95,398
 
Other
   
(60,000
)
   
(60,000
)
Net cash used in investing activities
 
$
(3,635,718
)
 
$
(3,576,327
)
 
               
CASH FLOWS FROM FINANCING ACTIVITIES
               
Dividends on common shares
 
$
(2,472,981
)
 
$
(2,377,135
)
Issuance of common shares
   
276,977
     
322,370
 
Debt issuance costs
   
     
(107,904
)
Issuance of long-term debt
   
     
58,000,000
 
Excess tax benefit from share-based compensation
   
35,112
     
21,562
 
Repayment of long-term debt
   
(1,500,000
)
   
(57,951,006
)
Borrowing on bank line of credit
   
     
17,360,379
 
Repayment of bank line of credit
   
     
(11,124,452
)
 
               
Net cash (used in) provided by financing activities
 
$
(3,660,892
)
 
$
4,143,814
 
 
               
DECREASE IN CASH AND CASH EQUIVALENTS
 
$
(7,880,166
)
 
$
(6,856,053
)
 
               
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
   
9,740,502
     
7,340,192
 
 
               
CASH AND CASH EQUIVALENTS,
END OF PERIOD
 
$
1,860,336
   
$
484,139
 










The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.
7

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 pipeline systems are located in central and southeastern Kentucky, and we 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.  We also transport natural gas on behalf of local producers and customers not on our distribution system and sell liquids extracted from natural gas in our storage field and on our pipeline systems.  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 and six months ended December 31, 2012 and 2011 are included.  All such adjustments are accruals of a normal and recurring nature other than the amounts disclosed in Note 7 related to the Utility Gross Receipts License Tax assessment.

The results of operations for the period ended December 31, 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:

 
 
December 31,
 
June 30,
 
 
 
 
($000)
2012
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
Trust assets
 
 
 
 
 
 
 
Money market
5
 
6
 
 
 
 
U.S. equity securities
426
 
364
 
 
 
 
U.S. fixed income securities
250
 
220
 
 
 
 
 
681
 
590
 
 
 

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.
8


December 31,
June 30,
2012
2012
 
 
Carrying
 
Fair
 
Carrying
 
Fair
 
 
($000)
Amount
 
Value
 
Amount
 
Value
 
 
 
 
 
 
 
 
 
 
 
 
4.26% Series A Notes
56,500
 
59,890
 
58,000
 
59,027
 


(3) Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk.  We purchase our 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 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:

 
 
December 31,
 
June 30,
 
 
 
(000)
 
2012
 
2012
 
 
 
 
 
 
 
 
 
 
 
Unbilled revenues ($)
 
4,989
 
1,358
 
 
 
Unbilled gas costs ($)
 
2,174
 
392
 
 
 
Unbilled volumes (Mcf)
 
410
 
46
 
 
 

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 Income.

9


(5) Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, noncontributory defined benefit pension plan for the periods ended December 31 include the following:
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
 
December 31,
 
December 31,
 
 
 
($000)
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
 
279
 
231
 
558
 
462
 
 
 
 
 
Interest cost
 
228
 
230
 
456
 
460
 
 
 
 
 
Expected return on plan assets
 
(394
)
(369
)
(789
)
(738
)
 
 
 
 
Amortization of unrecognized net loss
 
154
 
50
 
308
 
100
 
 
 
 
 
Amortization of prior service cost
 
(22
)
(22
)
(43
)
(44
)
 
 
 
 
Net periodic benefit cost
 
245
 
120
 
490
 
240
 
 
 
 
 

In August, 2012, we made a $2,300,000 discretionary contribution to the defined benefit pension plan.

(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 December 31, 2012 and June 30, 2012.  The bank line of credit extends through June 30, 2013.  We anticipate renewal of this line by 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, bearing interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031.  Each December, we are required to make an annual $1,500,000 principal payment on the Series A Notes. The following table summarizes the remaining contractual maturities of our Series A Notes by fiscal year:

($000)
 
 
 
2013
 
2014
 
1,500
2015
 
1,500
2016
 
1,500
2017
 
1,500
Thereafter
 
50,500
    Total Series A Notes
 
56,500
 
 
 
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.

10


(7) Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in 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 $3.9 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 assessed Delta Resources $5,565,000, which included $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 did not initially assert claims for the tax periods after June, 2011 or interest accrued subsequent to the initial assessments. Additionally, the Kentucky Department of Revenue had the regulatory authority to waive the penalties as our tax position was based on the advice of a tax advisor and substantial legal authority. Therefore, we estimated the total liability as of September 30, 2012, including the original assessment, plus unasserted claims for taxes and interest and excluding penalties, to be $3,978,000, which included $3,055,000 in taxes and $923,000 in interest.

We protested the assessment with the Kentucky Department of Revenue based on the position that the Utility Gross Receipts License Tax applied 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 contended was exempt from the tax. The position was based on 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, which found that the Utility Gross Receipts License Tax did not apply to sales of gas by a gas marketer, because it is not a utility.

In October, 2011, the Kentucky Court of Appeals reversed the May, 2010 Fayette Circuit Court opinion, and found that sales of natural gas by a gas marketer were subject to the tax.  As a result of the uncertainty created by the October, 2011 Kentucky Court of Appeals opinion, in September, 2011 we accrued $3,803,000 of taxes and interest and continued accruing interest quarterly on the assessment. Delta Resources began billing customers the Utility Gross Receipts License Tax prospectively with its October, 2011 billings and since that time has billed its customers $241,000, substantially all of which has been collected. Since Delta Resources has a contractual right to seek reimbursement from its customers, a receivable was recorded for the $3,055,000 of taxes leaving Delta Resources potentially liable for $923,000 of interest and any uncollectible amounts.

Discretionary review of the Kentucky Court of Appeals opinion by the Kentucky Supreme Court was denied in October, 2012 and the decision became final in January, 2013. In January, 2013, Delta Resources entered a definitive agreement with the Kentucky Department of Revenue to resolve the tax liability from July, 2005 through September, 2011, for an immediate tax payment to the Department of Revenue of $2,546,000.  Since Delta Resources began collecting and remitting the tax in October, 2011, this agreement is intended to fully resolve the matter.  Therefore, as of December 31, 2012, we reduced the previously accrued liability to $2,546,000 and reduced the receivable to $2,539,000, which is net of a $7,000 allowance for uncollectible amounts.  The previously accrued interest of $923,000 was reversed.

In February, 2013, Delta Resources billed its forty-two affected customers their allocated share of the tax payment which resulted in the customers being billed 2.673% of their taxable purchases from Delta Resources during the period July, 2005 through September, 2011.  The total taxable purchases from Delta Resources during this period were $95,251,000.  The customers' taxable purchases were determined by adjusting Delta Resources' gross receipts ($101,800,000) for nontaxable purchases by those direct pay customers exempt from the Utility Gross Receipts License Tax ($6,549,000).  We will monitor the adequacy of the allowance for doubtful accounts as we pursue collection of the taxes from these customers.

11

Included in the receivable are amounts due from three customers that have a relationship with certain Directors of Delta Natural Gas Company, Inc; $174,000 is due from a Delta Resources' customer that is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family; $175,000 is due from a Delta Resources' customer for whom our Chairman of the Board, CEO and President serves on its Board of Trustees; and $45,000 is due from a Delta Resources' customer for whom a Director of Delta Natural Gas Company, Inc. serves as its President.

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 was included in accrued interest on debt.  In the Condensed Consolidated Statements of Income, the change in the interest accrued is included in interest (income) expense and uncollectible amounts are included in operations and maintenance.

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

We have entered into forward purchase agreements beginning in January, 2013 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 $340,000 and $211,000 for our fiscal years 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 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 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 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.

12


Segment information is shown in the following table:

 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
 
December 31,
 
December 31,
 
 
 
($000)
 
2012
 
2011
 
2012
 
2011
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
External customers
 
13,299
 
12,978
 
19,040
 
18,602
 
 
 
 
 
Intersegment
 
1,082
 
1,064
 
1,876
 
1,828
 
 
 
 
 
Total regulated
 
14,381
 
14,042
 
20,916
 
20,430
 
 
 
 
 
Non-regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
External customers
 
8,808
 
9,548
 
14,519
 
16,821
 
 
 
 
 
Eliminations for intersegment
 
(1,082
)
(1,064
)
(1,876
)
(1,828
)
 
 
 
 
Consolidated operating revenues
 
22,107
 
22,526
 
33,559
 
35,423
 
 
 
 
 

Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated
 
2,311
 
1,992
 
2,065
 
1,643
 
 
 
 
 
Non-regulated
 
938
 
520
 
1,025
 
72
 
 
 
 
 
Consolidated net income
 
3,249
 
2,512
 
3,090
 
1,715
 
 
 
 
 


(10)            Earnings per Common Share

The following table sets forth the computation of basic and diluted earnings per share:

 
 
Three Months Ended
 
Six Months Ended
 
 
 
December 31,
 
December 31,
 
 
 
2012
 
2011
 
 
2012
 
2011
 
 
 
Numerator – Basic and Diluted
 
 
 
 
 
 
 
 
 
 
 
 
Net income ($000)
 
3,249
 
2,512
 
 
3,090
 
1,715
 
 
 
Dividends paid ($000)
 
(1,237
)
(1,189
)
 
(2,473
)
(2,377
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undistributed earnings ($000)
 
2,012
 
1,323
 
 
617
 
(662
)
 
 
Percentage allocated to common shares (a)
 
99.6
%
99.7
%
 
99.6
%
99.7
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Undistributed earnings allocated to common shares ($000)
 
2,004
 
1,318
 
 
615
 
(660
)
 
 
Dividends declared allocated to common shares ($000)
 
1,232
 
1,186
 
 
2,463
 
2,370
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income available to common shares ($000)
 
3,236
 
2,504
 
 
3,078
 
1,710
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Denominator  –  Basic and Diluted (b)(c)
Weighted-average
 
 
 
 
 
 
 
 
 
 
 
 
common shares
 
6,845,078
 
6,776,486
 
 
6,832,344
 
6,762,288
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Per Common Share Net Income ($) (b)
 
 
 
 
 
 
 
 
 
 
 
 
Basic
 
.47
 
.37
 
 
.45
 
.25
 
 
 
Diluted
 
.47
 
.37
 
 
.45
 
.25
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 




13


 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
December 31,
 
December 31,
 
 
 
 
2012
 
2011
 
2012
 
2011
 
 
 
(a)    Percentage allocated to common shares – weighted average
 
 
 
 
 
 
 
 
 
 
 
Common shares outstanding (b)
 
6,845,078
 
6,776,486
 
6,832,344
 
6,762,288
 
 
 
Unvested participating
shares (b) (d)
 
28,667
 
21,332
 
28,667
 
21,332
 
 
 
Total
 
6,873,745
 
6,797,818
 
6,861,011
 
6,783,620
 
 
 
Percentage allocated to common shares
 
99.6
%
99.7
%
99.6
%
99.7
%
 
 

 
(b) All 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.

(c) 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, as further discussed in (d).  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 December 31, 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.

(d) Certain awards under our incentive compensation plan provide recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares, as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements.  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 December 31, 2012 and 2011 there were 29,000 and 21,000 unvested participating shares outstanding, respectively.


(11) Share-Based Compensation

We have a shareholder approved incentive compensation plan (the "Plan"), which provides for incentive compensation 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.

The number of shares of our common stock that may be issued pursuant to the Plan may not exceed 1,000,000 shares in the aggregate.   As of December 31, 2012, 889,000 shares of common stock were available for issuance under the Plan.  Shares of common stock may be available 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 the non-regulated segment and included in operation and maintenance expense in the Condensed Consolidated Statements of Income 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.

14

 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
 
December 31,
 
December 31,
 
 
 
 
($000)
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-based compensation expense
204
 
99
 
571
 
514
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

For the six months ended December 31, 2012 and 2011, an excess tax benefit of $26,000 and $22,000, 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 six months ended December 31, 2012 and 2011, common stock was awarded 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 awards were immediately transferable.

Performance Shares

For the six months ended December 31, 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 the 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 and six months ended December 31, 2012, compensation expense related to the performance shares was $204,000 and $307,000, respectively.  For the three and six months ended December 31, 2011, compensation expense related to the performance shares was $99,000 and $177,000, respectively.  As of December 31, 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.

(12)            Two-for-One Stock Split

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, earnings per share and dividends per share have been retroactively re-stated, where appropriate, in the condensed consolidated financial statements and notes thereto.

15


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

YEAR TO DATE DECEMBER 31, 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 six months ended December 31, 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 and 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 matching supply with estimated demand while providing an acceptable gross margin.  The non-regulated segment also produces natural gas and sells liquids extracted from natural gas.

Our consolidated net income per common share for the six months ended December 31, 2012, increased $.20 per share, as compared to the same period in the prior year. The increase is primarily due to decreased interest expense resulting from the resolution of 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 decreased 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.

             The results of operations for the period ended December 31, 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 our operating revenues during the warmer months when our sales volumes decrease considerably.

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.

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 continued extraction and sales of natural gas liquids in fiscal 2013.  The profitability of such sales is dependent on the quantity 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 income 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, in periods 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 December 31, 2012 or June 30, 2012.
16


Cash and cash equivalents were $1,860,000 at December 31, 2012, as compared with $9,741,000 at June 30, 2012.  The changes in cash and cash equivalents are summarized in the following table:

 
 
Six Months Ended
 
 
 
 
 
December 31,
 
 
 
($000)
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Used in operating activities
 
(583
)
(7,424
)
 
 
 
 
Used in investing activities
 
(3,636
)
(3,576
)
 
 
 
 
(Used in) provided by financing activities
 
(3,661
)
4,144
 
 
 
 
 
Decrease in cash and cash equivalents
 
(7,880
)
(6,856
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
For the six months ended December 31, 2012, cash used in operating activities decreased $6,841,000 (92%).  Cash paid for natural gas decreased $11,242,000 as a result of decreases in natural gas purchased for storage and the market price of natural gas purchased. The decrease was partially offset by a $2,893,000 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 six months ended December 31, 2012, cash used in financing activities increased $7,805,000 (188%) due to decreased net borrowings on the bank line of credit as internally generated cash was sufficient to meet our operating and capital expenditure requirements and a $1,500,000 repayment on our 4.26% Series A Notes.

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.

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 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 extends through June 30, 2013 and permits borrowings up to $40,000,000.  We intend to renew our bank line of credit prior to June 30, 2013.

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 30, 2013.  We are required to make an annual $1,500,000 principal payment on the Series A Notes each December. 

17

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 margin" 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 believe that 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 Income as follows:

 
Three Months Ended
 
Six Months Ended
 
 
December 31,
 
December 31,
 
($000)
2012
 
2011
 
2012
 
2011
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
22,107
 
22,526
 
33,559
 
35,423
 
Regulated purchased gas (a)
(5,057
)
(5,085
)
(6,383
)
(6,286
)
Non-regulated purchased gas (a)
(6,666
)
(7,182
)
(10,812
)
(13,187
)
 
 
 
 
 
 
 
 
 
Consolidated gross margin
10,384
 
10,259
 
16,364
 
15,950
 


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

Operating Income, as presented in the Condensed Consolidated Statements of Income, is the most directly comparable financial measure to gross margin 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 and six months ended December 31, 2012 compared with the same periods 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 Income.
18

 
 
2012 compared to 2011
 
 
Three Months
 
Six Months
 
 
 
Ended
 
Ended
 
($000)
 
December 31
 
December 31
 
 
 
 
 
 
 
Increase (decrease) in regulated gross margins:
Regulated segment
 
 
 
 
 
Gas sales
 
315
 
305
 
On-system transportation
 
67
 
126
 
Off-system transportation
 
(16
)
(38
)
Other
 
1
 
(4
)
Intersegment elimination (a)
 
(18
)
(48
)
Total
 
349
 
341
 
 
 
 
 
 
 
Non-regulated segment
Natural gas sales
 
(186
)
(281
)
Natural gas liquids
 
(30
)
349
 
Other
 
(26
)
(43
)
Intersegment elimination (a)
 
18
 
48
 
Total
 
(224
)
73
 
 
 
 
 
 
 
Increase in consolidated gross margins
 
125
 
414
 

Percentage increase (decrease) in volumes:
 
 
 
 
 
Regulated segment
 
 
 
 
 
Natural gas sales (Mcf)
 
12
 
9
 
On-system transportation (Mcf)
 
4
 
5
 
Off-system transportation (Mcf)
 
(1
)
(2
)
 
 
 
 
 
 
Non-regulated segment
 
 
 
 
 
Natural gas sales (Mcf)
 
5
 
5
 
Natural gas liquids (gallons)
 
38
 
173
 

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

Heating degree days were 100% and 101% of normal thirty year average temperatures for the three and six months ended December 31, 2012, respectively, as compared with 89% and 91% of normal temperatures in the 2011 periods.  A heating degree day is the equivalent for each degree that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location.  Heating degree days are used in the natural gas industry to measure the relative coldness of weather and estimate the demand for natural gas.  Normal degree days are based on the historical 30-year average National Weather Service data for the same geographic location.

For the three months ended December 31, 2012, consolidated gross margins increased $125,000 (1%), as compared to the same period in the prior year, due to increased regulated gross margins of $349,000 partially offset by a decrease in non-regulated gross margins of $224,000.  Regulated gross margins increased due to a 12% increase in volumes sold to our regulated customers as a result of colder weather, as compared to the same period in the prior year. Partially offsetting this increase are decreased rates billed through our weather normalization tariff. Our non-regulated gross margins decreased as a result of a decline in sales prices for our non-regulated gas sales.

For the six months ended December 31, 2012, consolidated gross margins increased $414,000 (3%), as compared to the same period in the prior year, due to increased regulated and non-regulated gross margins of $341,000 and $73,000, respectively.  Regulated gross margins increased due to a 9% increase in volumes sold to our regulated customers as a result of colder weather, as compared to the same period in the prior year. Partially offsetting this increase are decreased rates billed through our weather normalization tariff.  Our non-regulated gross margins increased due to the sale of liquids extracted from the natural gas in our system.  The increase was partially offset by a decline in sales prices for our non-regulated gas sales.
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Operation and Maintenance

For the three and six month periods ended December 31, 2012, there were no significant changes in operation and maintenance, as compared to the same periods in the prior year.

Depreciation and Amortization

For the three and six month periods ended December 31, 2012, there were no significant changes in depreciation and amortization, as compared to the same periods in the prior year.

Taxes Other than Income Taxes

For the three and six month periods ended December 31, 2012, there were no significant changes in taxes other than income taxes, as compared to the same periods in the prior year.

Other Income (Deductions), Net

For the three and six month periods ended December 31, 2012, there were no significant changes in other income (deductions), net, as compared to the same periods in the prior year.

Interest (Income) Expense

For the three months ended December 31, 2012, interest (income) expense decreased $1,253,000 (122%) due to a $962,000 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). Additionally, interest (income) expense decreased $272,000 as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures in December, 2011.

For the six months ended December 31, 2012, interest (income) expense decreased $2,265,000 (81%) due to a $1,663,000 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). Additionally, interest (income) expense decreased $579,000 as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures in December, 2011.

Income Tax Expense

For the three and six month periods ended December 31, 2012, income tax expense increased $455,000 (30%) and $803,000 (78%), respectively, as compared to the same periods in the prior year. The increase is due to an increase in our net income before income taxes.  There were no significant changes to our effective tax rate for the three and six months periods ended December 31, 2012, as compared to the same periods in the prior year.

Basic and Diluted Earnings Per Common Share

For the three and six months ended December 31, 2012, our basic and diluted earnings per common share changed as a result of a change in our net income 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 December 31, 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 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 (as further discussed in Note 11 of the Notes to Condensed Consolidated Financial Statements).  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per common share using the two-class method unless the effect of including such shares would be antidilutive.  As of December 31, 2012 and 2011, there were 29,000 and 21,000 participating unvested shares outstanding, respectively.

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 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 gas purchase contracts, however, is fixed prior to the delivery of the natural gas.  Additionally, we inject some of our 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 segment, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through our gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for our non-regulated gas sales is mitigated by efforts to balance supply and demand.  However, there are greater risks because of the practical limitations on the ability to perfectly predict demand.  We are exposed to changes in the market price of gas on uncommitted gas inventory of our non-regulated segment.  The natural gas liquids sold by our non-regulated segment is priced based upon the pricing determined in the national unregulated market.

None of our gas contracts are accounted for using the fair value method of accounting.  While some of our gas purchase and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.  As of December 31, 2012, we had forward purchase contracts totaling $551,000 that have various terms with the last contract expiring 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 December 31, 2012 or June 30, 2012.
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 December 31, 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.

21

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 December 31, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS
 
 
 
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
 
31.1
 
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2
 
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
32.1
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
32.2
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
101.INS
 
XBRL Instance Document
 
101.SCH
 
XBRL Taxonomy Extension Schema
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
 
XBRL Taxonomy Extension Definition Database
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase

22

 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase
 
 
 
 
 
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL):
 
(i)
 
Document and Entity Information
 
(ii)
 
Condensed Consolidated Statements of Income (Unaudited) for the three and six month periods ended December 31, 2012 and 2011;
 
(iii)
 
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six month periods ended December 31, 2012 and 2011; and
 
(iv)
 
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2012 and June 30, 2012
 
(v)
 
Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the six month periods ended December 31, 2012 and 2011;
 
(vi)
 
Notes to Condensed Consolidated Financial Statements (Unaudited).
 
 
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or port of a registration statement or prospects for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.  We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.

23


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


DATE:  February 5, 2013
 
/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)

24