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EX-31.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INCexhibit311.htm
EX-32.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INCexhibit322.htm
EX-32.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INCexhibit321.htm
EX-31.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INCexhibit312.htm





 

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 March 31, 2011
 
 
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 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 March 31, 2011, Delta Natural Gas Company, Inc. had 3,361,849 shares of Common Stock outstanding.
 



 
1

 
DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

FINANCIAL INFORMATION
 
3
       
ITEM 1.
 
3
       
 
Consolidated Statements of Income (Unaudited) for the three, nine and twelve month periods ended March 31, 2011 and 2010
 
3
       
 
Consolidated Balance Sheets (Unaudited) as of March 31, 2011, June 30, 2010 and March 31, 2010
 
4
       
 
Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the nine  and twelve month periods ended March 31, 2011 and 2010
 
6
       
 
Consolidated Statements of Cash Flows (Unaudited) for the nine and twelve month periods ended March 31, 2011 and 2010
 
7
       
   
8
       
ITEM 2.
 
14
       
ITEM 3.
 
18
       
ITEM 4.
 
19
       
OTHER INFORMATION
 
20
       
ITEM 1.
 
20
       
ITEM 1A.
 
20
       
ITEM 2.
 
20
       
ITEM 3.
 
20
       
ITEM 4.
 
20
       
ITEM 5.
 
20
       
ITEM 6.
 
20
       
   
21


 
2

 

PART I - FINANCIAL INFORMATION
 
ITEM 1. FINANCIAL STATEMENTS
 

DELTA NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
   
 
Three Months Ended
 
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
March 31,
 
   
2011
 
2010
 
2011
 
2010
 
2011
 
2010
 
                                       
OPERATING REVENUES
 
$
35,355,010
 
$
36,090,839
 
$
69,127,792
 
$
65,336,222
 
$
80,213,638
 
$
75,746,272
 
                                       
OPERATING EXPENSES
                                     
Purchased gas
 
$
22,021,018
 
$
22,984,832
 
$
40,392,102
 
$
38,767,555
 
$
45,724,875
 
$
43,989,428
 
Operation and maintenance
   
3,527,287
   
3,757,526
   
10,276,297
   
10,187,280
   
13,545,465
   
13,902,074
 
Depreciation and amortization
   
1,436,872
   
985,130
   
3,713,091
   
2,951,983
   
4,702,461
   
3,929,996
 
Taxes other than income taxes
   
423,954
   
584,184
   
1,283,802
   
1,523,686
   
1,779,559
   
2,029,188
 
                                       
Total operating expenses
 
$
27,409,131
 
$
28,311,672
 
$
55,665,292
 
$
53,430,504
 
$
65,752,360
 
$
63,850,686
 
                                       
OPERATING INCOME
 
$
7,945,879
 
$
7,779,167
 
$
13,462,500
 
$
11,905,718
 
$
14,461,278
 
$
11,895,586
 
                                       
OTHER INCOME AND DEDUCTIONS, NET
   
31,583
   
38,551
   
137,995
   
120,040
   
126,755
   
174,107
 
                                       
INTEREST CHARGES
   
1,023,743
   
1,039,901
   
3,075,738
   
3,150,923
   
4,094,008
   
4,185,142
 
                                       
NET INCOME BEFORE INCOME TAXES
 
$
6,953,719
 
$
6,777,817
 
$
10,524,757
 
$
8,874,835
 
$
10,494,025
 
$
7,884,551
 
                                       
INCOME TAX EXPENSE
   
2,622,629
   
2,445,739
   
3,915,819
   
3,192,885
   
3,915,219
   
2,753,966
 
                                       
NET INCOME
 
$
4,331,090
 
$
4,332,078
 
$
6,608,938
 
$
5,681,950
 
$
6,578,806
 
$
5,130,585
 
                                       
EARNINGS PER COMMON SHARE  (Note 11)
                                     
Basic
 
$
1.29
 
$
1.30
 
$
1.97
 
$
1.71
 
$
1.97
 
$
1.54
 
Diluted
 
$
1.29
 
$
1.30
 
$
1.97
 
$
1.71
 
$
1.96
 
$
1.54
 
                                       
DIVIDENDS DECLARED PER COMMON SHARE
 
$
.340
 
$
.325
 
$
1.020
 
$
.975
 
$
1.345
 
$
1.295
 







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

 
3

 

DELTA NATURAL GAS COMPANY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
  
     
March 31,
 
June 30,
 
March 31,
 
     
2011
 
2010
 
2010
 
ASSETS
                   
                       
 
CURRENT ASSETS
                   
 
Cash and cash equivalents
 
$
10,937,108
 
$
4,639,145
 
$
6,229,319
 
 
Accounts receivable, less accumulated allowances for doubtful accounts of $227,000, $273,000 and $593,000, respectively
   
12,488,778
   
4,727,631
   
12,642,587
 
 
Gas in storage, at average cost
   
582,758
   
6,205,731
   
1,999,378
 
 
Deferred gas costs
   
1,760,876
   
3,296,912
   
1,640,256
 
 
Materials and supplies, at average cost
   
624,541
   
536,416
   
522,531
 
 
Prepayments
   
1,142,790
   
3,640,979
   
1,092,532
 
 
Total current assets
 
$
27,536,851
 
$
23,046,814
 
$
24,126,603
 
                       
 
PROPERTY, PLANT AND EQUIPMENT
 
$
209,241,816
 
$
204,248,520
 
$
202,308,352
 
 
Less-Accumulated provision for depreciation
   
(76,945,428
)
 
(73,792,601
)
 
(73,082,758
)
 
Net property, plant and equipment
 
$
132,296,388
 
$
130,455,919
 
$
129,225,594
 
                       
 
OTHER ASSETS
                   
 
Cash surrender value of life insurance
 
$
490,055
 
$
450,064
 
$
446,935
 
 
Regulatory assets
   
12,463,294
   
12,115,436
   
11,342,643
 
 
Unamortized debt expense and other
   
2,553,642
   
2,564,187
   
2,634,695
 
 
Total other assets
 
$
15,506,991
 
$
15,129,687
 
$
14,424,273
 
                       
 
Total assets
 
$
175,340,230
 
$
168,632,420
 
$
167,776,470
 
                       



















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

 
4

 

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

       
March 31,
   
June 30,
   
March 31,
 
       
2011
   
2010
   
2010
 
                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                   
                       
 
CURRENT LIABILITIES
                   
 
Accounts payable
 
$
5,411,332
 
$
6,460,620
 
$
6,479,304
 
 
Current portion of long-term debt
   
1,200,000
   
1,200,000
   
1,200,000
 
 
Accrued taxes
   
4,272,569
   
1,263,755
   
1,877,997
 
 
Customers’ deposits
   
722,657
   
535,516
   
656,752
 
 
Accrued interest on debt
   
857,103
   
854,109
   
856,239
 
 
Accrued vacation
   
695,982
   
731,869
   
693,173
 
 
Deferred income taxes
   
1,138,654
   
1,059,912
   
172,339
 
 
Other
   
412,250
   
417,694
   
573,319
 
 
Total current liabilities
 
$
14,710,547
 
$
12,523,475
 
$
12,509,123
 
                       
 
LONG-TERM DEBT
 
$
56,871,006
 
$
57,112,000
 
$
57,179,000
 
                       
 
LONG-TERM LIABILITIES
                   
 
Deferred income taxes
 
$
34,132,229
 
$
32,462,067
 
$
31,715,077
 
 
Investment tax credits
   
93,500
   
113,900
   
121,550
 
 
Regulatory liabilities
   
1,548,477
   
1,664,139
   
1,382,676
 
 
Accrued pension
   
64,917
   
1,218,441
   
710,369
 
 
Asset retirement obligations and other
   
2,973,717
   
2,778,228
   
2,389,825
 
 
Total long-term liabilities
 
$
38,812,840
 
$
38,236,775
 
$
36,319,497
 
                       
 
COMMITMENTS AND CONTINGENCIES (Note 8)
                   
 
Total liabilities
 
$
110,394,393
 
$
107,872,250
 
$
106,007,620
 
                       
 
SHAREHOLDERS’ EQUITY
                   
 
Common shares ($1.00 par value), 20,000,000
                   
 
  shares authorized; 3,361,849,   3,334,856
                   
 
  and 3,331,269 shares outstanding at March 31,
                   
 
  2011, June 30, 2010 and March 31, 2010, respectively
 
$
3,361,849
 
$
3,334,856
 
$
3,331,269
 
 
Premium on common shares
   
45,850,032
   
44,881,401
   
44,780,788
 
 
Retained earnings
   
15,733,956
   
12,543,913
   
13,656,793
 
 
Total shareholders’ equity
 
$
64,945,837
 
$
60,760,170
 
$
61,768,850
 
                       
 
Total liabilities and shareholders’ equity
 
$
175,340,230
 
$
168,632,420
 
$
167,776,470
 









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

 
5

 

DELTA NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(UNAUDITED)
 
   
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
   
2011
 
2010
 
2011
 
2010
 
                           
COMMON SHARES
                         
Balance, beginning of period
 
$
3,334,856
 
$
3,318,046
 
$
3,331,269
 
$
3,313,275
 
Issuance of common shares
   
17,993
   
13,223
   
21,580
   
17,994
 
Issuance of common shares under the incentive compensation plan
   
9,000
   
   
9,000
   
 
                           
Balance, end of period
 
$
3,361,849
 
$
3,331,269
 
$
3,361,849
 
$
3,331,269
 
                           
PREMIUM ON COMMON SHARES
                         
Balance, beginning of period
 
$
44,881,401
 
$
44,465,601
 
$
44,780,788
 
$
44,359,433
 
Issuance of common shares
   
522,469
   
315,187
   
623,082
   
421,355
 
Issuance of common shares under the incentive compensation plan
   
254,970
   
   
254,970
   
 
Share-based compensation
   
191,192
   
   
191,192
   
 
                           
Balance, end of period
 
$
45,850,032
 
$
44,780,788
 
$
45,850,032
 
$
44,780,788
 
                           
RETAINED EARNINGS
                         
Balance, beginning of period
 
$
12,543,913
 
$
11,215,535
 
$
13,656,793
 
$
12,827,315
 
Net income
   
6,608,938
   
5,681,950
   
6,578,806
   
5,130,585
 
Dividends on common shares
 (See Consolidated Statements of
 Income for rates)
   
(3,418,895
)
 
(3,240,692
)
 
(4,501,643
)
 
(4,301,107
)
                           
Balance, end of period
 
$
15,733,956
 
$
13,656,793
 
$
15,733,956
 
$
13,656,793
 
                           
SHAREHOLDERS’ EQUITY
                         
Balance, beginning of period
 
$
60,760,170
 
$
58,999,182
 
$
61,768,850
 
$
60,500,023
 
Net income
   
6,608,938
   
5,681,950
   
6,578,806
   
5,130,585
 
Issuance of common shares
   
540,462
   
328,410
   
644,662
   
439,349
 
Issuance of common shares under the incentive compensation plan
   
263,970
   
   
263,970
   
 
Share-based compensation
   
191,192
   
   
191,192
   
 
Dividends on common shares
   
(3,418,895
)
 
(3,240,692
)
 
(4,501,643
)
 
(4,301,107
)
                           
Balance, end of period
 
$
64,945,837
 
$
61,768,850
 
$
64,945,837
 
$
61,768,850
 




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

 
6

 

DELTA NATURAL GAS COMPANY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED) 
   
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
   
2011
 
2010
 
2011
 
2010
 
                   
CASH FLOWS FROM OPERATING ACTIVITIES
                         
Net income
 
$
6,608,938
 
$
5,681,950
 
$
6,578,806
 
$
5,130,585
 
Adjustments to reconcile net income to net cash flows from operating activities
                         
   Depreciation and amortization
   
4,078,948
   
3,332,341
   
5,195,103
   
4,437,137
 
   Deferred income taxes and investment tax credits
   
1,637,686
   
3,419,631
   
3,233,805
   
4,340,929
 
   Other, net
   
(502,012
)
 
(290,443
)
 
(594,019
)
 
(386,974
)
   Change in cash surrender value of officer’s life insurance
   
(39,991
)
 
(34,274
)
 
(34,546
)
 
(68,888
)
   Share-based compensation
   
455,162
   
   
455,162
   
 
   Decrease (increase) in assets
   
1,807,849
   
1,092,241
   
951,256
   
12,992,784
 
   Increase (decrease) in liabilities
   
884,036
   
3,483,561
   
87,853
   
(1,165,585
)
                           
Net cash provided by operating activities
 
$
14,930,616
 
$
16,685,007
 
$
15,873,420
 
$
25,279,988
 
                           
CASH FLOWS FROM INVESTING ACTIVITIES
                         
Capital expenditures
 
$
(6,085,663
)
$
(3,671,123
)
$
(7,588,236
)
$
(5,021,857
)
Proceeds from sale of property, plant and equipment
   
140,540
   
138,231
   
164,257
   
207,407
 
Other
   
431,897
   
(60,000
)
 
423,323
   
(60,000
)
Net cash used in investing activities
 
$
(5,513,226
)
$
(3,592,892
)
$
(7,000,656
)
$
(4,874,450
)
                           
CASH FLOWS FROM FINANCING ACTIVITIES
                         
Dividends on common shares
 
$
(3,418,895
)
$
(3,240,692
)
$
(4,501,643
)
$
(4,301,107
)
Issuance of common shares
   
540,462
   
328,410
   
644,662
   
439,349
 
Repayment of long-term debt
   
(240,994
)
 
(420,000
)
 
(307,994
)
 
(530,000
)
Borrowings on bank line of credit
   
17,824,196
   
25,205,557
   
17,824,196
   
32,835,706
 
Repayment of bank line of credit
   
(17,824,196
)
 
(28,858,660
)
 
(17,824,196
)
 
(43,493,839
)
                           
Net cash used in financing activities
 
$
(3,119,427
)
$
(6,985,385
)
$
(4,164,975
)
$
(15,049,891
)
                           
NET INCREASE IN CASH AND CASH EQUIVALENTS
 
$
6,297,963
 
$
6,106,730
 
$
4,707,789
 
$
5,355,647
 
                           
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
   
4,639,145
   
122,589
   
6,229,319
   
873,672
 
                           
CASH AND CASH EQUIVALENTS, END OF PERIOD
 
$
10,937,108
 
$
6,229,319
 
$
10,937,108
 
$
6,229,319
 







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

 
7

 

DELTA NATURAL GAS COMPANY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)


(1)
Nature of Operations

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 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 gas in the open market.  We also transport natural gas on behalf of local producers and customers not on our distribution system.  We have three wholly-owned subsidiaries.  Delta Resources, Inc. (“Delta Resources”) buys gas and resells it to industrial or other large use customers on Delta’s system. Delgasco, Inc. buys gas and resells it to Delta Resources, Inc. and to customers not on Delta’s system.  Enpro, Inc. owns and operates production properties and undeveloped acreage.

(2)
Basis of Presentation

All subsidiaries of Delta are included in the 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, nine and twelve months ended March 31, 2011 and 2010 are included.  All such adjustments are accruals of a normal and recurring nature.

The results of operations for the periods ended March 31, 2011 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.  Twelve month ended financial information is provided for additional information only.

The accompanying 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, 2010.

(3)
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 unamortized debt expense and other on the Consolidated Balance Sheets.  Contributions to the trust are presented in other investing activities on the Consolidated Statement 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:

   
March 31,
 
June 30,
 
March 31,
 
 
($000)
2011
 
2010
 
2010
 
               
 
Trust assets
510
 
373
 
394
 

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

Our Debentures and Insured Quarterly Notes, presented as current portion of long-term debt and long-term debt on the 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 Insured Quarterly Notes contain insurance that provides for the continuing payment of principal and interest to the holders in the event we default on the Insured Quarterly Notes.  Upon default, the insurer would pay interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation transfers to the insurer.  Therefore, the insurance is not considered in the determination of the fair value of the Insured Quarterly Notes.
 
 
8

 
               
   
March 31, 2011
 
June 30, 2010
 
March 31, 2010
 
($000)
 
 
Carrying
Amount
 
 
Fair
Value
 
 
Carrying
Amount
 
 
Fair
Value
 
 
Carrying
Amount
 
 
Fair
Value
 
                           
7% Debentures
 
19,420
 
19,098
 
19,460
 
18,839
 
19,470
 
19,272
 
5.75% Insured Quarterly Notes
 
38,651
 
34,425
 
38,852
 
34,128
 
38,909
 
34,647
 

(4)
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 gas purchases and forward gas purchases.  We mitigate price risk by efforts to balance supply and demand.  None of our gas contracts are accounted for using the fair value method of accounting.  While some of our gas purchase contracts and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

(5)
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:

     
March 31,
 
June 30,
 
March 31,
 
 
(000)
 
2011
 
2010
 
2010
 
                 
 
Unbilled revenues ($)
 
4,823
 
1,120
 
4,527
 
 
Unbilled gas costs ($)
 
2,434
 
333
 
2,274
 
 
Unbilled volumes (Mcf)
 
356
 
53
 
377
 

Unbilled revenues are included in accounts receivable and unbilled gas costs are included in deferred gas costs on the accompanying Consolidated Balance Sheets.

(6)
Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, noncontributory defined benefit pension plan for the periods ended March 31 include the following:
 
   
Three Months Ended
 
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
March 31,
 
($000)
 
2011
 
2010
 
2011
 
2010
 
2011
 
2010
 
                           
Service cost
 
235
 
182
 
704
 
546
 
886
 
715
 
Interest cost
 
213
 
214
 
640
 
641
 
854
 
843
 
Expected return on plan assets
 
(269
)
(238
)
(809
)
(715
)
(1,047
)
(967
)
Amortization of unrecognized net loss
 
125
 
124
 
376
 
373
 
500
 
427
 
Amortization of prior service cost
 
(22
)
(22
)
(65
)
(65
)
(86
)
(86
)
Net periodic benefit cost
 
282
 
260
 
846
 
780
 
1,107
 
932
 

 
During fiscal 2011, we made $2,000,000 of discretionary contributions to our defined benefit plan.  No additional contributions are expected for fiscal 2011.

 
9

 
 (7)
Notes Payable

The current bank line of credit with Branch Banking and Trust Company is $40,000,000, all of which was available at March 31, 2011, June 30, 2010 and March 31, 2010.  Our bank line of credit extends through June 30, 2011.  The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.5%, and the annual cost of the unused bank line of credit is .125%.

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

 
·
Dividend payments cannot be made unless consolidated shareholders’ equity of the Company exceeds $25,800,000 (thus no retained earnings were restricted); and
 
 
·
we may not assume any additional mortgage indebtedness in excess of $5,000,000 without effectively securing all Debentures and Insured Quarterly Notes equally to such additional indebtedness.

Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes.  We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during any period presented.

(8)
Commitments and Contingencies

We have entered into individual employment agreements with our five 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 $3.5 million would be paid in addition to continuation of specified benefits for up to five years.

The Kentucky Department of Revenue has assessed our subsidiary company, Delta Resources, $5,193,000, which includes $2,759,000 in taxes, $1,852,000 in penalties and $582,000 in interest for failure to collect and remit a 3% Utility Gross Receipts License tax for the period July, 2005 through July, 2010.  The tax is a 3% license tax levied on the gross billings by a utility and is passed through to its customers.  Delta Resources is a natural gas marketer and not a utility regulated by the Kentucky Public Service Commission.  Since case law in the state of Kentucky and opinions issued by the Kentucky Attorney General support that the Utility Gross Receipts License Tax is applicable only to regulated utilities, we believe Delta Resources is exempt from the tax.  We have protested the assessment, but cannot currently predict the outcome of the protest.  As of March 31, 2011, we have not accrued any amounts related to this assessment.

Although the Kentucky Department of Revenue has not asserted a claim for the tax periods after July, 2010 or interest accrued subsequent to August, 2010, we have calculated that unasserted liabilities approximate $307,000.

In the event we are unsuccessful in defending our position, Delta Resources would have the right to seek reimbursement from its customers for amounts paid to the Department of Revenue relating to this assessment, leaving Delta Resources potentially liable for the interest component of the assessment and any uncollectible amounts.  However, we would not be liable for penalties as Kentucky law provides a waiver of penalties when, as we have done, the tax position taken is done so in good faith upon the analysis and recommendation of legal counsel.

In January, 2011, we filed a lawsuit in the Clark County Kentucky Circuit Court against Chartis Insurance (“Chartis”) seeking recovery of an insurance claim filed by us with Chartis in March, 2009.  The claim sought reimbursement of $1,350,000 related to gas that escaped from our underground storage field during 2007.  During such time we had a policy with Chartis to insure the natural gas which is stored in the underground storage field, and we believe the policy was designed to cover such a loss.  Chartis has not reimbursed us for our loss, as the external consultant engaged by Chartis has challenged our right to recover under the policy.  In February, 2011, upon the request of Chartis, the case was removed to the United States District Court.  In April, 2011, Delta and Chartis filed motions on the issue of which party has the burden of proof with respect to the cause of the gas loss.  We are unable to predict the outcome of this legal proceeding.

 
10

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

We have entered into forward purchase agreements beginning in November, 2010 and expiring at various dates through December, 2011.  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.  The remaining aggregate minimum purchase obligations for these agreements are $24,000 and $45,000 for our fiscal years ended June 30, 2011 and 2012, respectively.

(9)
Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services.  The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services.  The Kentucky Public Service Commission has 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.

On April 23, 2010, we filed a request for increased rates with the Kentucky Public Service Commission.  This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000, an increase of 11.5%.  The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12.0%.

The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense.  A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues will be less dependent on customer usage and should occur more evenly throughout the year. The increased base rates were effective for service rendered on and after October 22, 2010.

In addition to the increased base rates, our pipe replacement program and a change to our gas cost recovery clause were approved.  Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities.  The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.  In February, 2011, we submitted our 2010 pipe replacement program filing to the Kentucky Public Service Commission, and they approved rates to provide us $139,000 in additional annual revenues beginning in May, 2011.  The change to our gas cost recovery clause, which became effective with billings on and after January 24, 2011, provides recovery of the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.

(10)
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 and production.  The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky.  Virtually all of the revenue recorded under both segments comes from the distribution or transportation of natural gas. 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 gas and uncommitted gas volumes of our non-regulated companies.

 
11

 
The 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 which are included in our Annual Report on Form 10-K for the year ended June 30, 2010.  Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation services.  Appropriate related operating expenses, taxes and interest are allocated to the non-regulated segment.
 
Segment information is shown below for the periods:

   
Three Months Ended
 
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
March 31,
 
($000)
 
2011
 
2010
 
2011
 
2010
 
2011
 
2010
 
Operating Revenues
                         
Regulated
                         
External customers
 
21,103
 
20,766
 
41,217
 
39,838
 
47,054
 
47,288
 
Intersegment
 
1,360
 
1,338
 
3,054
 
2,757
 
3,738
 
3,326
 
  Total regulated
 
22,463
 
22,104
 
44,271
 
42,595
 
50,792
 
50,614
 
                           
Non-regulated
                         
External customers
 
14,252
 
15,325
 
27,911
 
25,498
 
33,160
 
28,458
 
                           
Eliminations for intersegment
 
(1,360
)
(1,338
)
(3,054
)
(2,757
)
(3,738
)
(3,326
)
Total operating revenues
 
35,355
 
36,091
 
69,128
 
65,336
 
80,214
 
75,746
 
                           
Net Income
                         
Regulated
 
3,588
 
3,309
 
5,160
 
4,038
 
4,839
 
3,892
 
Non-regulated
 
743
 
1,023
 
1,449
 
1,644
 
1,740
 
1,239
 
Total net income
 
4,331
 
4,332
 
6,609
 
5,682
 
6,579
 
5,131
 

(11)
Earnings per Share

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

   
Three Months Ended
 
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
March 31,
 
   
2011
 
2010
 
2011
 
2010
 
2011
 
2010
 
Numerator – Basic and Diluted
                         
Net Income ($000)
 
4,331
 
4,332
 
6,609
 
5,682
 
6,579
 
5,131
 
                           
Denominator  –  Basic
Weighted-average common shares
 
3,358,914
 
3,328,667
 
3,350,510
 
3,324,228
 
3,346,100
 
3,321,764
 
Incremental unvested shares
 
11,162
 
 
3,721
 
 
2,790
 
 
                           
Denominator  –  Diluted
Adjusted weighted-average common and dilutive shares
 
3,370,076
 
3,328,667
 
3,354,231
 
3,324,228
 
3,348,890
 
3,321,764
 
                           
Earnings per Common Share ($)
                         
Basic
 
1.29
 
        1.30
 
        1.97
 
         1.71
 
        1.97
 
         1.54
 
Diluted
 
        1.29
 
        1.30
 
        1.97
 
         1.71
 
        1.96
 
         1.54
 


 
12

 
Certain awards under our shareholder approved incentive compensation plan have all the rights of a shareholder of Delta Natural Gas Company, Inc. which includes a right to dividends declared on common shares.  Therefore, 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.  There were no such shares outstanding for any of the periods presented in the accompanying consolidated financial statements.

As of March 31, 2011, 16,000 non-participating unvested performance shares were outstanding.  Non-participating unvested performance shares are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  For the three, nine and twelve months ended March 31, 2011 there were no antidilutive shares.

(12)
Share-Based Compensation

In November, 2009, our shareholders adopted and approved the Delta Natural Gas Company, Inc. Incentive Compensation Plan (the “Plan”), which was previously approved by our Board of Directors in August, 2009.  The Plan provides for incentive compensation payable in shares of our common stock.  The Plan, which became effective on January 1, 2010, is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining our employees, officers and outside directors who 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.

The number of shares of our common stock which may be issued pursuant to the Plan may not exceed in the aggregate 500,000 shares.  As of March 31, 2011, 491,000 shares of common stock are 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 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 the 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 the later of the board approval date or the date 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.

   
Three Months Ended
 
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
March 31,
 
 
($000)
2011
 
2010
 
2011
 
2010
 
2011
 
2010
 
                           
 
Share-based compensation expense
131
 
 
455
 
 
455
 
 
                           

The cumulative compensation expense recognized for share-based compensation exceeds the tax deductions allowed on our income tax returns.  An immaterial tax deficiency was recognized in income tax expense for the nine and twelve months ended March 31, 2011, which increased our taxes payable.

In August, 2010, shares of common stock were awarded to virtually all of Delta’s employees and directors in accordance with the Plan.  The 9,000 shares awarded had a grant date fair value of $264,000 or $29.33 per share.  The recipients vested in the award shortly after the award was granted, but during the time between the vesting date and the grant date the shares awarded were not transferable by the holders.  Once the shares were vested, the shares were immediately transferable.

In August, 2010, performance shares were awarded to the Company's executive officers in accordance with the Plan.  The performance share awards will vest only if the performance objective of the awards is met, which is based on the Company's fiscal 2011 audited earnings per share, before any cash bonuses or stock awards.  Subject to further limitations described in the Incentive Compensation Plan and the Notice of Performance Shares Award, all Performance Shares paid shall be in the form of unvested shares, which contain a service condition where a recipient of the award shall vest in one-third increments each year beginning on August 31, 2011, and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period.  The maximum which would be issued under the performance awards is 16,000 shares, which have a grant date fair value of $469,000 ($29.33 per share).  Compensation expense of $131,000, $191,000 and $191,000 has been recognized for the awards for the three, nine and twelve months ended March 31, 2011, respectively.

 
13

 
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 award based on the probable outcome of meeting the performance objective.  The probable outcome of the performance objective is evaluated at each balance sheet date and this evaluation can result in upward or downward revisions of amounts previously recognized until the actual outcome of the performance objective is known for the June 30, 2011 balance sheet date.

To the extent the performance condition is satisfied during the first year of the vesting period, the holder of performance shares will have both dividend participation rights and voting rights during the remaining term of the awards.  The holder becomes vested as a result of certain events such as death or disability of the holder.  Subject to the satisfaction of the performance condition, the weighted average expected remaining vesting period at March 31, 2011 is 2.4 years.  Holders of performance shares may not sell, transfer, or pledge their shares until the shares vest.

The following summarizes the activity for performance shares:

     
Performance shares
     
     
 
Number of shares
 
Weighted-average grant date fair value
         
                     
 
Unvested awards at June 30, 2010
 
 
$               —
         
 
Granted
 
16,000
(1)
$          29.33
         
 
Vested
 
 
         
 
Forfeited
 
 
         
 
Unvested awards at March 31, 2011
 
16,000
 
$          29.33
         
                     
(1)  
Represents the maximum number of shares which could be issued based on achieving the performance criteria.


ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
YEAR TO DATE MARCH 31, 2011 OVERVIEW AND FUTURE OUTLOOK

For the nine months ended March 31, 2011, consolidated earnings per common share of $1.97 increased $.26 per share as compared to the $1.71 consolidated earnings per common share for the nine months ended March 31, 2010.  The increase is attributable to increases in both our regulated segment’s and non-regulated segment’s gross margins.

The results for the year ended June 30, 2011 of the regulated segment have been and will continue to be impacted by the new base rates approved by the Kentucky Public Service Commission (as further discussed in Note 9 of the Notes to Consolidated Financial Statements).  The new base rates were effective October 22, 2010, and are designed to annually generate an additional $3,513,000 of revenues.  The regulated segment’s largest expense is gas supply, which we are permitted to pass through to our customers.  We control remaining expenses through budgeting, approval and review.

Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large use customers and the market prices of natural gas, all of which are out of our control.  We anticipate our non-regulated segment to continue to contribute to our consolidated net income for the remainder of fiscal 2011.
 
 
14

 
LIQUIDITY AND CAPITAL RESOURCES
 
Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital.  Our sales and cash requirements are seasonal.  The largest portion of our sales occurs during the heating months, 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, our ability to maintain liquidity depends on our bank line of credit when cash provided by operating activities is not sufficient to meet our capital requirements.  There were no borrowings outstanding on the bank line of credit as of March 31, 2011, June 30, 2010 and March 31, 2010.  When we have no borrowings outstanding on our bank line of credit, excess cash is invested in overnight repurchase agreements.  Through Branch Banking & Trust Company, we purchase U.S. Treasury or Federal Agency Securities with a contractual agreement to sell back the securities the next day.
 
Long-term debt decreased to $56,871,000 at March 31, 2011, compared with $57,112,000 at June 30, 2010 and $57,179,000 at March 31, 2010.  These decreases resulted from the limited redemptions made by certain holders or their beneficiaries as allowed by the Debentures and Insured Quarterly Notes.
 
Cash and cash equivalents were $10,937,000 at March 31, 2011, as compared with $4,639,000 at June 30, 2010 and $6,229,000 at March 31, 2010. These changes in cash and cash equivalents are summarized in the following table:
 
   
Nine Months Ended
 
Twelve Months Ended
 
   
March 31,
 
March 31,
 
($000)
 
2011
 
2010
 
2011
 
2010
 
                   
Provided by operating activities
 
14,930
 
16,685
 
15,873
 
25,280
 
Used in investing activities
 
(5,513
)
(3,593
)
(7,001
)
(4,874
)
Used in financing activities
 
(3,119
)
(6,985
)
(4,164
)
(15,050
)
Increase in cash and cash equivalents
 
6,298
 
6,107
 
4,708
 
5,356
 
                   

For the nine months ended March 31, 2011, cash provided by operating activities decreased $1,755,000 (11%) due to a $1,500,000 increase in cash contributed to our defined benefit plan, as we made additional discretionary contributions.

For the twelve months ended March 31, 2011, cash provided operating by activities decreased $9,407,000 (37%) due to increased cash paid for increased quantities of natural gas purchased of $10,824,000 and a $1,500,000 increase in discretionary cash contributions to our defined benefit plan.

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

For the nine and twelve months ended March 31, 2011, cash used in financing activities decreased $3,866,000 (55%) and $10,886,000 (72%), respectively due to decreased net repayments on our bank line of credit.
 
Cash Requirements
 
Our capital expenditures result in a continued need for capital. These capital expenditures are being made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2011 to be approximately $7.7 million.

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

 
15

 
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 is $40,000,000.  There were no borrowings outstanding on the bank line of credit as of March 31, 2011. The current bank line of credit extends through June 30, 2011.

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

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

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

Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes.  We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during any period presented.  We are not aware of any events that would cause us to be in default in fiscal 2011.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices and we monitor our need to file rate requests with the Kentucky Public Service Commission for general rate increases for our regulated services.
 
On April 23, 2010, we filed a request for increased rates with the Kentucky Public Service Commission.  This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000, an increase of 11.5%.  The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12.0%.

The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense.  A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues will be less dependent on customer usage and should occur more evenly throughout the year.  The increased rates were effective for service rendered on and after October 22, 2010.

In addition to the increased base rates, our pipe replacement program and a change to our gas cost recovery clause were approved.  Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities.  The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.  In February, 2011, we submitted our 2010 pipe replacement program filing to the Kentucky Public Service Commission, and they approved rates to provide us $139,000 in additional annual revenues beginning in May, 2011.  The change to our gas cost recovery clause, which became effective with billings on and after January 24, 2011, provides recovery of the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.

RESULTS OF OPERATIONS
 
Gross Margins
 
Throughout the following Results of Operations we refer to “gross margin”.  Our operating revenues, with the exception of transportation revenues, have offsetting gas expenses.  Gross margin, therefore, refers to operating revenues less purchased gas expense, which can be derived directly from our Consolidated Statements of Income. Operating Income as presented on the Consolidated Statements of Income is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (“GAAP). “Gross margin” is a “non-GAAP financial measure”, as defined in accordance with SEC rules. We view gross margin as an important performance measure of the core profitability of our business segments.  The measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses.
 
 
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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, nine and twelve months ended March 31, 2011 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 Consolidated Statements of Income.


   
2011 compared to 2010
 
   
Three Months
 
Nine Months
 
Twelve Months
 
   
Ended
 
Ended
 
Ended
 
($000)
 
March 31,
 
March 31,
 
March 31,
 
               
Increase (decrease) in gross margins:
  Regulated segment
Gas sales
 
365
 
1,339
 
1,276
 
On-system transportation
 
92
 
299
 
399
 
Off-system transportation
 
53
 
166
 
288
 
Other
 
10
 
2
 
(4
)
Intersegment elimination (a)
 
(22
)
(297
)
(412
)
Total
 
498
 
1,509
 
1,547
 
               
  Non-regulated segment
Gas sales
 
(290
)
345
 
718
 
Other
 
(2
)
17
 
56
 
Intersegment elimination (a)
 
22
 
297
 
412
 
Total
 
(270
)
659
 
1,186
 
               
Increase in consolidated gross margins
 
228
 
2,168
 
2,733
 
 
Percentage increase (decrease) in volumes
  Regulated segment
             
Gas sales
 
(13
)
(3
)
(5
)
On-system transportation
 
4
 
8
 
12
 
Off-system transportation
 
5
 
5
 
5
 
               
  Non-regulated segment
             
Gas sales
 
11
 
24
 
32
 
               
 
(a) Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment.

Heating degree days were 102%, 105% and 101% of normal thirty year average temperatures for the three, nine and twelve months ended March 31, 2011, respectively, as compared with 112%, 109% and 107% of normal temperatures in the 2010 periods.  A “heating degree day” results from a day during which the average of the high and low temperature is at least one degree less than 65 degrees Fahrenheit.

For the three months ended March 31, 2011, consolidated gross margins increased $228,000 (2%) due to increased regulated gross margins of $498,000 (5%) which were partially offset by decreased non-regulated gross margins of $270,000 (9%). Regulated gross margins increased due to both increased base rates which became effective October 22, 2010 and increased rates billed through our weather normalization tariff as a result of warmer weather as compared to the same period in the prior year. The increases were partially offset by a 13% decrease in volumes sold as a result of warmer weather as compared to the same period in the prior year. Non-regulated gross margins decreased due to a decline in sales prices partially offset by a decline in the cost of gas and increased volumes sold.

 
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For the nine months ended March 31, 2011, consolidated gross margins increased $2,168,000 (8%) due to increased regulated and non-regulated gross margins of $1,509,000 (7%) and $659,000 (12%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010. Non-regulated gross margins increased due to a 24% increase in volumes sold due to an increase in our non-regulated customers’ gas requirements.

For the twelve months ended March 31, 2011, consolidated gross margins increased $2,733,000 (9%) due to increased regulated and non-regulated gross margins of $1,547,000 (6%) and $1,186,000 (18%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010. The increase was partially offset by a 5% decrease in volumes sold as a result of warmer weather as compared to the same period in the prior year. Non-regulated gross margins increased due to a 32% increase in volumes sold due to an increase in our non-regulated customers’ gas requirements. During the twelve months ended March 31, 2010, we experienced a reduction in our non-regulated customers’ gas requirements, which we attributed to the economic conditions during that period of time.

Depreciation and Amortization

For the three, nine and twelve months ended March 31, 2011, depreciation and amortization increased $452,000 (46%), $761,000 (26%) and $772,000 (20%), respectively, due to increased depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case.

Taxes Other Than Income Taxes

For the three, nine and twelve months ended March 31, 2011, taxes other than income taxes decreased $160,000 (27%), $240,000 (16%) and $249,000 (12%) due to a decrease in property tax expense.

Income Tax Expense

For the nine and twelve months ended March 31, 2011, income tax expense increased $723,000 (23%) and $1,161,000 (42%), respectively, as a result in increases in net income before taxes.

Basic and Diluted Earnings Per Common Share
 
For the three, nine and twelve months ended March 31, 2011 and 2010, our basic earnings per common share changed as a result of changes in 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 awarded through our incentive compensation plan.

Certain awards under our shareholder approved incentive compensation plan have all the rights of a shareholder of Delta Natural Gas Company, Inc. which includes a right to dividends declared on common shares. Therefore, 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.  There were no such shares outstanding for any of the periods presented in the accompanying consolidated financial statements.  As of March 31, 2011, 16,000 non-participating unvested performance shares were outstanding.  Non-participating unvested performance shares are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  For the three, nine and twelve months ended March 31, 2011 there were no antidilutive shares.


ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We purchase our gas supply through a combination of spot market gas purchases and forward gas 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 gas.  Additionally, we inject some of our gas purchases into gas storage facilities in the non-heating months and withdraw this gas from storage for delivery to customers during the heating season.  For our regulated business, 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 the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.
 
 
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Price risk for the non-regulated business 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 price risk resulting from changes in the market price of gas on uncommitted gas volumes of our non-regulated companies.
 
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.

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 current bank line of credit with Branch Banking and Trust Company is $40,000,000.  There were no borrowings outstanding on the bank line of credit as of March 31, 2011, June 30, 2010 and March 31, 2010.  The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.5%.

 
ITEM 4. 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 March 31, 2011, 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.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any change 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 March 31, 2011 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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PART II - OTHER INFORMATION
 

 
ITEM 1.      LEGAL PROCEEDINGS

In January, 2011 we filed a lawsuit in the Clark County, Kentucky Circuit Court against Chartis Insurance (“Chartis”) seeking recovery of an insurance claim filed by us with Chartis in March, 2009. The claim sought reimbursement of $1,350,000 related to gas that escaped from our underground storage field during 2007. During such time we had a policy with Chartis to insure the natural gas which is stored in the underground storage field, and we believe the policy was designed to cover such a loss.  Chartis has not reimbursed us for our loss, as the external consultant engaged by Chartis has challenged our right to recover under the policy.  In February, 2011, upon the request of Chartis, the case was removed to the United States District Court.  In April, 2011, Delta and Chartis filed motions on the issue of which party has the burden of proof with respect to the cause of the gas loss.
 
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.      REMOVED AND RESERVED
 
              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.

 
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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:  May 5, 2011
 
/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)

 
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