10-Q 1 form10qdec2009.htm DECEMBER 31, 2009 10-Q form10qdec2009.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 December 31, 2009

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, 2009, Delta Natural Gas Company, Inc. had 3,327,573 shares of Common Stock outstanding.


 
 
 



DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

FINANCIAL INFORMATION
  
3
       
ITEM 1.
  
3
       
 
Consolidated Statements of Income (Unaudited) for the three, six and twelve month periods ended December 31, 2009 and 2008
  
3
       
 
Consolidated Balance Sheets (Unaudited) as of December 31, 2009, June 30, 2009 and December 31, 2008
  
4
       
 
Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the six  and twelve month periods ended December 31, 2009 and 2008
  
6
       
 
Consolidated Statements of Cash Flows (Unaudited) for the six and twelve month periods ended December 31, 2009 and 2008
  
7
       
   
8
       
ITEM 2.
  
14
       
ITEM 3.
  
19
       
ITEM 4.
  
19
       
OTHER INFORMATION
  
20
       
ITEM 1.
  
20
       
ITEM 1A.
  
20
       
ITEM 2.
  
20
       
ITEM 3.
  
20
       
ITEM 4.
  
20
       
ITEM 5.
  
21
       
ITEM 6.
  
21
       
   
22
       


 
 
 


 

DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
   
  
Three Months Ended
  
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
December 31,
  
   
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
                                       
OPERATING REVENUES
  
$
21,114,433
  
$
33,957,969
  
$
29,245,383
  
$
52,066,058
  
$
82,816,149
  
$
123,020,587
  
                                       
OPERATING EXPENSES
                                      
Purchased gas
  
$
12,298,555
  
$
24,081,852
  
$
15,782,724
  
$
36,404,948
  
$
51,455,406
  
$
86,042,694
  
Operation and maintenance
    
3,261,750
    
5,155,649
    
6,429,754
    
7,981,705
    
13,478,337
    
16,024,446
  
Depreciation and amortization
    
982,360
    
961,383
    
1,966,853
    
1,911,286
    
3,910,666
    
3,780,114
  
Taxes other than income taxes
    
485,758
    
445,575
    
939,502
    
884,275
    
1,935,834
    
1,812,515
  
                                       
Total operating expenses
  
$
17,028,423
  
$
30,644,459
  
$
25,118,833
  
$
47,182,214
  
$
70,780,243
  
$
107,659,769
  
                                       
OPERATING INCOME
  
$
4,086,010
  
$
3,313,510
  
$
4,126,550
  
$
4,883,844
  
$
12,035,906
  
$
15,360,818
  
                                       
OTHER INCOME AND DEDUCTIONS, NET
    
26,187
    
(78,620
)
  
81,489
    
(87,257
)
  
122,327
    
(23,136
)
                                       
INTEREST CHARGES
    
1,065,162
    
1,264,211
    
2,111,022
    
2,410,177
    
4,228,501
    
4,640,742
  
                                       
NET INCOME BEFORE INCOME TAXES
  
$
3,047,035
  
$
1,970,679
  
$
2,097,017
  
$
2,386,410
  
$
7,929,732
  
$
10,696,940
  
                                       
INCOME TAX EXPENSE
    
1,134,160
    
741,675
    
747,146
    
884,191
    
2,871,352
    
4,009,194
  
                                       
NET INCOME
  
$
1,912,875
  
$
1,229,004
  
$
1,349,871
  
$
1,502,219
  
$
5,058,380
  
$
6,687,746
  
                                       
BASIC AND DILUTED EARNINGS PER COMMON SHARE
  
$
.58
  
$
.37
  
$
.41
  
$
.46
  
$
1.53
  
$
2.03
  
                                       
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING (BASIC AND DILUTED)
    
3,324,637
    
3,303,313
    
3,322,169
    
3,300,403
    
3,316,931
    
3,295,341
  
                                       
DIVIDENDS DECLARED PER COMMON SHARE
  
$
.325
  
$
.32
  
$
.65
  
$
.64
  
$
1.29
  
$
1.26
  






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

 
 
 

DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
  
   
December 31,
  
June 30,
  
December 31,
  
   
2009
  
2009
  
2008
  
ASSETS
                    
                     
CURRENT ASSETS
                    
Cash and cash equivalents
  
$
138,146
  
$
122,589
  
$
324,863
  
Accounts receivable, less accumulated allowances for doubtful accounts of  $495,000, $819,000, and $852,000, respectively
    
12,653,512
    
4,085,867
    
18,602,820
  
Gas in storage, at average cost
    
10,978,247
    
9,746,768
    
21,183,038
  
Deferred gas costs
    
1,573,758
    
2,356,943
    
6,032,930
  
Materials and supplies, at average cost
    
525,775
    
662,805
    
588,409
  
Prepayments
    
5,374,954
    
2,415,527
    
4,178,350
  
Total current assets
  
$
31,244,392
  
$
19,390,499
  
$
50,910,410
  
                     
PROPERTY, PLANT AND EQUIPMENT
  
$
201,406,820
  
$
199,254,216
  
$
195,391,491
  
Less-Accumulated provision for depreciation
    
(72,174,115
)
  
(70,616,271
)
  
(69,259,827
)
Net property, plant and equipment
  
$
129,232,705
  
$
128,637,945
  
$
126,131,664
  
                     
OTHER ASSETS
                    
Cash surrender value of life insurance
  
$
440,746
  
$
412,661
  
$
384,940
  
Prepaid pension cost
    
—
    
—
    
1,677,932
  
Regulatory assets
    
11,400,086
    
11,394,844
    
7,648,521
  
Unamortized debt expense and other
    
2,667,245
    
2,669,346
    
2,758,250
  
Total other assets
  
$
14,508,077
  
$
14,476,851
  
$
12,469,643
  
                     
Total assets
  
$
174,985,174
  
$
162,505,295
  
$
189,511,717
  
                     

















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

 
 
 


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

     
December 31,
    
June 30,
    
December 31,
  
     
2009
    
2009
    
2008
  
                     
LIABILITIES AND SHAREHOLDERS’ EQUITY
                    
                     
CURRENT LIABILITIES
                    
Accounts payable
  
$
6,292,716
  
$
4,691,152
  
$
8,868,368
  
Notes payable
    
12,015,728
    
3,653,103
    
28,652,755
  
Current portion of long-term debt
    
1,200,000
    
1,200,000
    
1,200,000
  
Accrued taxes
    
1,475,910
    
983,376
    
1,388,248
  
Customers’ deposits
    
641,019
    
508,209
    
621,511
  
Accrued interest on debt
    
854,190
    
857,810
    
859,592
  
Accrued vacation
    
612,652
    
712,216
    
605,410
  
Deferred income taxes
    
270,866
    
814,549
    
1,628,814
  
Other
    
522,249
    
487,925
    
470,066
  
Total current liabilities
  
$
23,885,330
  
$
13,908,340
  
$
44,294,764
  
                     
LONG-TERM DEBT
  
$
57,259,000
  
$
57,599,000
  
$
58,063,000
  
                     
LONG-TERM LIABILITIES
                    
Deferred income taxes
  
$
31,058,562
  
$
27,537,908
  
$
25,695,748
  
Investment tax credits
    
129,200
    
144,500
    
161,150
  
Regulatory liabilities
    
1,419,468
    
1,710,099
    
1,872,704
  
Accrued pension
    
450,278
    
430,095
    
—
  
Asset retirement obligations and other
    
2,346,190
    
2,176,171
    
2,246,334
  
Total long-term liabilities
  
$
35,403,698
  
$
31,998,773
  
$
29,975,936
  
                     
COMMITMENTS AND CONTINGENCIES
(Note 8)
                    
Total liabilities
  
$
116,548,028
  
$
103,506,113
  
$
132,333,700
  
                     
SHAREHOLDERS’ EQUITY
                    
Common shares ($1.00 par value, 20,000,000 shares
                    
authorized; 3,327,573,  3,318,046, and
                    
3,307,446 shares outstanding at December 31,
                    
2009, June 30, 2009 and December 31, 2008,
                    
respectively)
  
$
3,327,573
  
$
3,318,046
  
$
3,307,446
  
Premium on common shares
    
44,703,270
    
44,465,601
    
44,244,428
  
Retained earnings
    
10,406,303
    
11,215,535
    
9,626,143
  
Total shareholders’ equity
  
$
58,437,146
  
$
58,999,182
  
$
57,178,017
  
                     
Total liabilities and shareholders’ equity
  
$
174,985,174
  
$
162,505,295
  
$
189,511,717
  











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

 
 
 

DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
 
   
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
   
2009
  
2008
  
2009
  
2008
  
                           
COMMON SHARES
                          
Balance, beginning of period
  
$
3,318,046
  
$
3,295,759
  
$
3,307,446
  
$
3,286,276
  
Issuance of common shares
    
9,527
    
11,687
    
20,127
    
21,170
  
                           
Balance, end of period
  
$
3,327,573
  
$
3,307,446
  
$
3,327,573
  
$
3,307,446
  
                           
PREMIUM ON COMMON SHARES
                          
Balance, beginning of period
  
$
44,465,601
  
$
43,967,481
  
$
44,244,428
  
$
43,729,714
  
Issuance of common shares
    
237,669
    
276,947
    
458,842
    
514,714
  
                           
Balance, end of period
  
$
44,703,270
  
$
44,244,428
  
$
44,703,270
  
$
44,244,428
  
                           
RETAINED EARNINGS
                          
Balance, beginning of period
  
$
11,215,535
  
$
10,330,345
  
$
9,626,143
  
$
7,184,458
  
Adoption of FASB Statement No. 158
                          
  (net of $57,699 of tax)
    
—
    
(94,300
)
  
—
    
(94,300
)
Balance, beginning of period, as adjusted
  
$
11,215,535
  
$
10,236,045
  
$
9,626,143
  
$
7,090,158
  
Net income
    
1,349,871
    
1,502,219
    
5,058,380
    
6,687,746
  
Dividends declared on common shares
(See Consolidated Statements of Income  for rates)
    
(2,159,103
)
  
(2,112,121
)
  
(4,278,220
)
  
(4,151,761
)
                           
Balance, end of period
  
$
10,406,303
  
$
9,626,143
  
$
10,406,303
  
$
9,626,143
  
                           
SHAREHOLDERS’ EQUITY
                          
Balance, beginning of period
  
$
58,999,182
  
$
57,593,585
  
$
57,178,017
  
$
54,200,448
  
Adoption of FASB Statement No. 158
                          
  (net of $57,699 of  tax)
    
—
    
(94,300
)
  
—
    
(94,300
)
Balance, beginning of period, as adjusted
  
$
58,999,182
  
$
57,499,285
  
$
57,178,017
  
$
54,106,148
  
Net income
    
1,349,871
    
1,502,219
    
5,058,380
    
6,687,746
  
Issuance of common shares
    
247,196
    
288,634
    
478,969
    
535,884
  
Dividends on common shares
    
(2,159,103
)
  
(2,112,121
)
  
(4,278,220
)
  
(4,151,761
)
                           
Balance, end of period
  
$
58,437,146
  
$
57,178,017
  
$
58,437,146
  
$
57,178,017
  













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

 
 
 

DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED) 
   
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
   
2009
  
2008
  
2009
  
2008
  
                   
CASH FLOWS FROM OPERATING ACTIVITIES
                          
Net income
  
$
1,349,871
  
$
1,502,219
  
$
5,058,380
  
$
6,687,746
  
Adjustments to reconcile net income to net cash flows from operating activities
                          
Depreciation and amortization
    
2,220,423
    
2,164,858
    
4,417,807
    
4,285,720
  
Deferred income taxes and investment tax credits
    
2,900,085
    
1,216,112
    
3,819,321
    
2,416,040
  
Gain on sale of property, plant and equipment
    
—
    
(156,023
)
  
—
    
(172,978
)
Provision for inventory adjustment
    
—
    
1,350,300
    
—
    
1,350,300
  
Other, net
    
(264,770
)
  
(317,632
)
  
(370,812
)
  
(440,646
)
Change in cash surrender value of life insurance
    
(28,085
)
  
(59,372
)
  
(55,806
)
  
40,669
  
Decrease (increase) in assets
    
(11,895,946
)
  
(18,702,712
)
  
21,099,404
    
(9,535,363
)
Increase (decrease) in liabilities
    
2,558,305
    
(3,248,258
)
  
(5,699,587
)
  
145,312
  
                           
Net cash provided by (used in) operating activities
  
$
(3,160,117
)
$
(16,250,508
)
$
28,268,707
  
$
4,776,800
  
                           
CASH FLOWS FROM INVESTING ACTIVITIES
                          
Capital expenditures
  
$
(2,969,045
)
$
(3,846,171
)
$
(7,349,706
)
$
(6,571,402
)
Proceeds from sale of property, plant and equipment
    
94,001
    
426,206
    
194,560
    
538,923
  
Other
    
(60,000
)
  
—
    
(60,000
)
  
—
  
Net cash used in investing activities
  
$
(2,935,044
)
$
(3,419,965
)
$
(7,215,146
)
$
(6,032,479
)
                           
CASH FLOWS FROM FINANCING ACTIVITIES
                          
Dividends on common shares
  
$
(2,159,103
)
$
(2,112,121
)
$
(4,278,220
)
$
(4,151,761
)
Issuance of common shares
    
247,196
    
288,634
    
478,969
    
535,884
  
Repayment of long-term debt
    
(340,000
)
  
(255,000
)
  
(804,000
)
  
(339,000
)
Borrowings on bank line of credit
    
21,694,291
    
53,515,222
    
42,286,126
    
76,271,635
  
Repayment of bank line of credit
    
(13,331,666
)
  
(31,691,258
)
  
(58,923,153
)
  
(71,417,027
)
                           
Net cash provided by (used in) financing activities
  
$
6,110,718
  
$
19,745,477
  
$
(21,240,278
)
$
899,731
  
                           
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS
  
$
15,557
  
$
75,004
  
$
(186,717
)
$
(355,948
)
                           
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
    
122,589
    
249,859
    
324,863
    
680,811
  
                           
CASH AND CASH EQUIVALENTS,
END OF PERIOD
  
$
138,146
  
$
324,863
  
$
138,146
  
$
324,863
  







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

 
 
 

DELTA NATURAL GAS COMPANY, INC.
 

(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. 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, six and twelve months ended December 31, 2009 and 2008 are included.  All such adjustments are accruals of a normal and recurring nature other than the inventory adjustment discussed in Note 11 to adjust our gas in storage during the quarter ended December 31, 2008.  In preparation of the consolidated financial statements, we evaluated subsequent events after the balance sheet date of December 31, 2009 through February 8, 2010, the filing date of this Form 10-Q.

The results of operations for the periods ended December 31, 2009 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, 2009.

 
Recently Adopted Accounting Standards

In June 2009, the Financial Accounting Standards Board issued Statement No. 168, entitled The FASB Accounting Standards Codification (“Codification”) and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”), which establishes the Codification as the single source of authoritative GAAP recognized by the Financial Accounting Standards Board.  Securities and Exchange Commission (“SEC”) rules and interpretive releases are also sources of authoritative generally accepted accounting principles for SEC registrants. Statement No. 168 was effective for periods ending after September 15, 2009.  Statement No. 168 did not change or alter existing GAAP, therefore it did not impact our results of operations, cash flows or financial position.  We have adjusted historical GAAP references in our SEC filings to reflect accounting guidance references included in the Codification.

Effective July 1, 2009, we adopted Codification Topic 820, entitled Fair Value Measurement and Disclosures, as it relates to nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis.  Our nonfinancial assets and liabilities measured at fair value on a nonrecurring basis consist of our asset retirement obligations, which are measured at fair value only upon initial recognition.  The adoption did not have a material impact on our results of operations or financial position.

In August 2009, the Financial Accounting Standards Board issued Accounting Standards Update No. 2009-05, entitled Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value. Update No. 2009-05 provides additional guidance in measuring the fair value of liabilities when a lack of observable market information exists to value the liability from an exit price perspective.  We adopted the provisions of Update No. 2009-05 effective for our quarter ended September 30, 2009 and the adoption did not impact our results of operations or financial position.

 
Recently Issued Accounting Standards

In December, 2008, the Financial Accounting Standards Board issued Financial Accounting Standards Board Staff Position No. FAS 132(R)-1, entitled Employer’s Disclosures about Postretirement Benefit Plan Assets.  Upon issuance of the Accounting Standards Codification, the provisions of Staff Position No. FAS 132(R)-1 were superseded and added as pending content to Codification Topic 715-20, entitled Defined Benefit Plans – General.  The pending content provides for additional disclosure to increase transparency surrounding the types of assets and risks associated with a defined benefit pension or other postretirement plan. Codification Topic 715-20, as amended, will require employers to provide additional disclosure surrounding investment strategies, major categories of plan assets, and valuation techniques used to measure the fair value of plan assets.  The pending content, which shall be effective for our fiscal year ending June 30, 2010, will not impact our results of operations or financial position.

In January, 2009, the Financial Accounting Standards Board issued Accounting Standards Update No. 2010-06, entitled Fair Value Measurements and Disclosures (Topic 820) – Improving Disclosures about Fair Value Measurements. Update No. 2010-06 requires entities with fair value measurements to disaggregate major categories of assets and liabilities within the disclosures, disclose transfers between levels within the fair value hierarchy and disclose inputs and valuation techniques for Level 2 and Level 3 fair value measurements. Update No. 2010-06 is effective for reporting periods beginning after December 15, 2009 and will not impact our results of operations or financial position.

(3)
Fair Value Measurements

Pursuant to Codification Topic 820, fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date.  The fair value definition focuses on an exit price, which is the price that would be received by us to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability.  Although additional fair value measurements are not required, the guidance in Codification Topic 820 applies to other accounting pronouncements that require or permit fair value measurements.

We determine the fair value of financial assets and liabilities based on the following fair value hierarchy, as prescribed by Codification Topic 820, which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

•
Level 1
– Observable inputs such as quoted prices in active markets for identical assets or liabilities;

•
Level 2
– Inputs, other than quoted prices in active markets, that are observable either directly or
indirectly; and

•
Level 3
– Unobservable inputs which require the reporting entity to develop its own assumptions.

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.  The offsetting liability is included in asset retirement obligations 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 liability is not considered a financial liability within the scope of Codification Topic 820.  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,
  
December 31,
  
 
($000)
2009
  
2009
  
2008
  
               
 
Trust assets
378
  
281
  
272
  

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.

   
December 31,
  
   
2009
  
   
Carrying
  
Fair
  
 
($000)
Amount
  
Value
  
           
 
7% Debentures
19,510
  
18,414
  
 
5.75% Insured Quarterly Notes
38,949
  
33,268
  

Our nonfinancial assets and nonfinancial liabilities that are measured at fair value on a nonrecurring basis consist of our asset retirement obligations.  Our asset retirement obligations are measured at fair value upon initial recognition based on the expected future cash flows of the obligation.  Additionally, certain future events may require us to evaluate long-lived assets for impairment to determine if their carrying value exceeds their fair value.

Entities are permitted to electively measure many financial instruments and certain other items at fair value. We do not currently have any financial assets or financial liabilities for which the fair value option has been elected.  However, in the future, we may elect to measure certain financial instruments at fair value in accordance with Codification Topic 820.

(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” under Codification Topic 815, entitled Derivatives and Hedging.

(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:

     
December 31,
  
June 30,
  
December 31,
  
 
(000)
  
2009
  
2009
  
2008
  
                 
 
Unbilled revenues ($)
  
6,410
  
1,386
  
9,591
  
 
Unbilled gas costs ($)
  
3,669
  
519
  
6,788
  
 
Unbilled volumes (Mcf)
  
550
  
55
  
517
  

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 December 31 include the following:
 
   
Three Months Ended
  
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
December 31,
  
($000)
  
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
                           
Service cost
  
182
  
169
  
364
  
339
  
702
  
713
  
Interest cost
  
214
  
203
  
427
  
405
  
833
  
778
  
Expected return on plan assets
  
(238
)
(253
)
(476
)
(505
)
(982
)
(999
)
Amortization of unrecognized net loss
  
124
  
55
  
248
  
108
  
357
  
233
  
Amortization of prior service cost
  
(22
)
(22
)
(43
)
(43
)
(86
)
(86
)
Net periodic benefit cost
  
260
  
152
  
520
  
304
  
824
  
639
  

 (7)
Notes Payable

The current available bank line of credit with Branch Banking and Trust Company, is $40,000,000, of which $12,016,000, $3,653,000 and $28,653,000 were borrowed having a weighted average interest rate of 1.7%, 1.8% and 2.7% as of December 31, 2009, June 30, 2009 and December 31, 2008, respectively.  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 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 $3.1 million would be paid in addition to continuation of specified benefits for up to five years.

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

We have entered into forward purchase agreements beginning in July, 2009 and expiring at various dates through October, 2010.  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 $411,000 and $143,000 for our fiscal years ended June 30, 2010 and 2011, 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.  The rates we currently charge our regulated customers were implemented in October, 2007.  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.

(10)
Operating Segments

Our Company has two segments:  (i) a regulated natural gas distribution, transmission and storage 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.

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, 2009.  Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services. Intersegment transportation revenues and expenses are recorded at our tariff rates.  Revenues and expenses for the storage of natural gas are recorded based on quantities stored.  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
  
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
December 31,
  
($000)
  
2009
  
2008
  
2009
  
2008
  
2009
  
2008
  
Operating Revenues
                          
Regulated
                          
External customers
  
13,807
  
22,177
  
19,072
  
28,826
  
54,724
  
65,354
  
Intersegment
  
866
  
971
  
1,419
  
1,733
  
3,113
  
3,970
  
Total regulated
  
14,673
  
23,148
  
20,491
  
30,559
  
57,837
  
69,324
  
                           
Non-regulated
                          
External customers
  
7,307
  
11,781
  
10,173
  
23,240
  
28,092
  
57,667
  
                           
Eliminations for intersegment
  
(866
)
(971
)
(1,419
)
(1,733
)
(3,113
)
(3,970
)
Total operating revenues
  
21,114
  
33,958
  
29,245
  
52,066
  
82,816
  
123,021
  
                           
Net Income
                          
Regulated
  
1,552
  
870
  
730
  
411
  
3,798
  
3,360
  
Non-regulated
  
361
  
359
  
620
  
1,091
  
1,260
  
3,328
  
Total net income
  
1,913
  
1,229
  
1,350
  
1,502
  
5,058
  
6,688
  


(11)
Gas In Storage Inventory Adjustment

We operate a natural gas underground storage field that we utilize to inject and store natural gas during the non-heating season, and we then withdraw natural gas during the heating season to meet our customers’ needs.  We periodically analyze the volumes, pressure and other data relating to the storage field in order to substantiate the gas inventory carried in our perpetual inventory records.

Fiscal 2009 storage field data suggested that an inventory adjustment was required related to a storage well that allowed natural gas to escape.  After analyzing the data, we estimated that the adjustment amount would be in the range of $1,350,000 to $1,750,000.  Based on the storage field data available at the time, we could not determine if any amount within the range was more likely than any other; therefore, we recorded a gas in storage inventory adjustment in the amount of $1,350,000.  The adjustment was included in operation and maintenance expense in the Consolidated Statements of Income for the three, six and twelve months ended December 31, 2008.

Fiscal 2010 storage field data has been inconclusive as to whether any additional inventory adjustment is required.  We will continue to evaluate storage field data and record inventory adjustments as required.  Potential future adjustments may be in amounts within or exceeding the range determined in 2009.

On March 23, 2009, we filed an insurance claim for $1,350,000 relating to the escaped gas.  On October 22, 2009, we received the preliminary findings from the external consultant engaged by the insurance company to review our claim.  The preliminary findings challenge our right to recover the full amount of the claim. We disagree with the consultant’s preliminary findings and have filed a rebuttal with the insurance company.  We cannot predict the amount of any insurance proceeds.

Depending on the outcome of our pursuit of insurance recovery, we will also evaluate whether any unreimbursed gas losses are eligible for regulatory recovery under our gas cost recovery rate mechanism or through other recovery methods.  We have not recorded any insurance recovery asset or regulatory asset in the accompanying consolidated financial statements; however, to the extent recovery becomes probable, we will evaluate recognition of an asset at that time.

(12)
Share-Based Compensation

In November, 2009, at the Annual Meeting of Shareholders of Delta Natural Gas Company, Inc., 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, subject to shareholder approval.  The Plan provides for incentive compensation payable in stock, restricted stock and stock bonus awards. 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.  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.  The Company must receive authorization to issue shares pursuant to the Plan from the Kentucky Public Service Commission before any shares can be awarded.  In December, 2009, we submitted a filing with the Kentucky Public Service Commission seeking such authorization.



YEAR TO DATE DECEMBER 31, 2009 OVERVIEW AND FUTURE OUTLOOK

For the six months ended December 31, 2009, consolidated net income per share of $.41 decreased $0.05 per share as compared to the $.46 net income per share for the six months ended December 31, 2008.  The decrease is primarily attributable to a 41% decline in our non-regulated segment's gross margins. However, the decline is partially offset by an inventory adjustment we recorded for our gas in storage during the six months ended December 31, 2008, which is further discussed in Note 11 of the Notes to Consolidated Financial Statements.

Our regulated segment's contribution to consolidated net income for the remainder of 2010 will be dependent upon the continuing impact the weakened economic environment has on our customers.  Our customers may choose to discontinue their natural gas service, be unable to pay for their natural gas service or decrease the volumes purchased from or transported by us on behalf of them.

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.  For the six months ended December 31, 2009, we experienced a decline in the volumes sold to our non-regulated customers due to a decrease in the non-regulated customers' gas requirements.  We anticipate our non-regulated segment will continue to contribute to our consolidated net income for the remainder of fiscal 2010, based on the contracts currently in place.  Additionally, if natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production activities.  However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities.

LIQUIDITY AND CAPITAL RESOURCES

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

Our ability to maintain liquidity depends on our bank line of credit, shown as notes payable on the accompanying Consolidated Balance Sheets. Notes payable increased to $12,016,000 at December 31, 2009 compared to $3,653,000 at June 30, 2009 due to gas purchased for storage and capital expenditures. Notes payable decreased to $12,016,000 at December 31, 2009 compared to $28,653,000 at December 31, 2008 due to a 63% decrease in the cost of gas purchased for storage during the current year storage injection season (April through November), as compared to the same period in the prior year.

Our liquidity is also impacted by the fact that we sometimes generate internally only a portion of the cash necessary for our capital expenditure requirements.  We made capital expenditures of $2,969,000 and $7,350,000 during the six and twelve months ended December 31, 2009, respectively.  In periods when cash provided by operating activities is not sufficient to meet our capital requirements, we finance the balance of our capital expenditures on an interim basis through our bank line of credit.

Long-term debt decreased to $57,259,000 at December 31, 2009, compared with $57,599,000 at June 30, 2009 and $58,063,000 at December 31, 2008.  The 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 $138,000 at December 31, 2009, as compared with $123,000 at June 30, 2009 and $325,000 at December 31, 2008.  The changes in cash and cash equivalents are summarized in the following table:
 
 
   
Six Months Ended
  
Twelve Months Ended
  
   
December 31,
  
December 31,
  
($000)
  
2009
  
2008
  
2009
  
2008
  
                   
Provided by (used in) operating activities
  
(3,160
)
(16,250
)
28,268
  
4,777
  
Used in investing activities
  
(2,935
)
(3,420
)
(7,215
)
(6,032
)
Provided by (used in) financing activities
  
6,111
  
19,745
  
(21,240
)
899
  
Increase (decrease) in cash and cash equivalents
  
16
  
75
  
(187
)
(356
)
                   
For the six months ended December 31, 2009, cash used in operating activities decreased $13,090,000 (81%).  Cash paid for natural gas decreased $33,326,000 due to decreases in both the cost of gas purchased and the quantities purchased. The decrease was partially offset by a $23,790,000 decrease in cash received from customers due to decreases in both sales prices and volumes sold.

For the twelve months ended December 31, 2009, cash provided by operating activities increased $23,491,000 (492%). Cash paid for natural gas decreased $56,103,000 due to decreases in both the cost of gas purchased and the quantities purchased. The decrease was partially offset by a $34,179,000 decrease in cash received from customers due to decreases in both sales prices and volumes sold.

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, 2009, cash provided by financing activities decreased $13,634,000 (69%) due to decreased net borrowings on the bank line of credit.

For the twelve months ended December 31, 2009, cash used in financing activities increased $22,139,000 (2,463%) due to increased net repayments on the bank line of credit.


 
 
 


Cash Requirements

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

Sufficiency of Future Cash Flows

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

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 line of credit with Branch Banking and Trust Company, shown as notes payable on the accompanying Consolidated Balance Sheets, is $40,000,000, of which $12,016,000 was borrowed at December 31, 2009. The current bank line of credit extends through June 30, 2011.

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

·  
Dividend payments cannot be made unless consolidated shareholders' equity of 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 2010.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices and we continuously monitor our need to file rate requests with the Kentucky Public Service Commission for general rate increase for our regulated services.  The rates we currently charge our regulated customers were implemented in October, 2007.


RESULTS OF OPERATIONS
 
Gross Margins

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

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, six and twelve months ended December 31, 2009 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.

   
2009 compared to 2008
  
   
Three Months
  
Six Months
  
Twelve Months
  
   
Ended
  
Ended
  
Ended
  
($000)
  
December 31
  
December 31
  
December 31
  
               
Increase (decrease) in gross margins:
Regulated segment
              
Gas sales
  
(293
)
(374
)
(675
)
On-system transportation
  
16
  
17
  
(335
)
Off-system transportation
  
(154
)
(370
)
(644
)
Other
  
(21
)
(30
)
(43
)
Intersegment elimination (a)
  
105
  
314
  
857
  
Total
  
(347
)
(443
)
(840
)
               
Non-regulated segment
Gas sales
  
(611
)
(1,395
)
(3,780
)
Other
  
2
  
(47
)
(140
)
Intersegment elimination (a)
  
(105
)
(314
)
(857
)
Total
  
(714
)
(1,756
)
(4,777
)
               
Decrease in consolidated gross margins
  
(1,061
)
(2,199
)
(5,617
)
 
Percentage increase (decrease) in volumes:
              
Regulated segment
              
Gas sales
  
(11
)
(9
)
(6
)
On-system transportation
  
1
  
(5
)
(15
)
Off-system transportation
  
(16
)
(20
)
(19
)
               
Non-regulated segment
              
Gas sales
  
(3
)
(23
)
(29
)
               
 
(a)
Intersegment eliminations represent the transportation fee charged by the regulated segment to the non-regulated segment.

Heating degree days were 104%, 103% and 100% of normal thirty year average temperatures for the three, six and twelve months ended December 31, 2009 as compared with 107%, 104% and 103% of normal temperatures in the 2008 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 December 31, 2009, consolidated gross margins decreased $1,061,000 (11%) due to decreased non-regulated and regulated gross margins of $714,000 (32%) and $347,000 (5%), respectively. Our non-regulated gross margins decreased due to a 29% decline in sales prices.  Our regulated gross margins decreased due to a 16% decrease in off-system volumes transported due to a decline in our off-system customers’ gas requirements. Additionally, we experienced an 11% decrease in regulated volumes sold due to customer conservation and warmer weather, which was partially offset by an increase in the rates billed through our weather normalization tariff.

For the six months ended December 31, 2009, consolidated gross margins decreased $2,199,000 (14%) due to decreased non-regulated and regulated gross margins of $1,756,000 (41%) and $443,000 (4%), respectively.  Our non-regulated gross margins decreased due to a 23% decrease in both volumes sold and sales prices.  Our regulated gross margins decreased due to a 20% decrease in off-system volumes transported due to a decline in our off-system customers’ gas requirements.  We primarily attribute the current economic conditions to both the declines in non-regulated volumes sold and regulated off-system volumes transported.  Additionally, we experienced a 9% decrease in regulated volumes sold due to customer conservation and warmer weather which was partially offset by an increase in the rates billed through our weather normalization tariff.

For the twelve months ended December 31, 2009, consolidated gross margins decreased $5,617,000 (15%) due to decreased non-regulated and regulated gross margins of $4,777,000 (43%) and $840,000 (3%), respectively. Our non-regulated gross margins decreased due to a 29% decrease in volumes sold and a 19% decline in sales prices. The non-regulated volume sold decreased due to a decrease in our non-regulated customers’ gas requirements, which we attribute primarily to current economic conditions.  Our regulated gross margins decreased due to a 6% decrease in regulated gas sales due to customer conservation and warmer weather which was partially offset by an increase in the rates billed through our weather normalization tariff.  Additionally, our regulated margins decreased due to a 19% decrease in off-system transportation volumes due to a decrease in our customers' gas requirements.

Operation and Maintenance

For the three months ended December 31, 2009, operation and maintenance expense decreased $1,894,000 (37%). The decrease was primarily due to an inventory adjustment for our gas in storage ($1,350,000, as further discussed in Note 11 of the Notes to Consolidated Financial Statements) recorded in the prior year and decreased uncollectible expense ($663,000).

For the six months ended December 31, 2009, operation and maintenance expense decreased $1,552,000 (19%). The decrease was primarily due to an inventory adjustment for our gas in storage ($1,350,000, as further discussed in Note 11 of the Notes to Consolidated Financial Statements) recorded in the prior year and decreased uncollectible expense ($743,000), partially offset by increased employee benefit expense ($208,000) and increased professional services expense ($210,000).

For the twelve months ended December 31, 2009, operation and maintenance expense decreased $2,546,000 (16%).  The decrease was primarily due to an inventory adjustment for our gas in storage ($1,350,000, as further discussed in Note 11 of the Notes to Consolidated Financial Statements) recorded in the prior year and decreased uncollectible expense ($998,000).

Other Income and Deductions, Net

For the three, six and twelve months ended December 31, 2009, other income and deductions, net increased $105,000 (133%), $168,000 (193%) and $145,000 (630%), respectively.  The increases were due to increases in the cash surrender value of officers’ life insurance as well as increases in the fair value of the supplemental retirement plan.  The increases in the fair value of the supplemental retirement plan were offset by increased operating expenses resulting from a corresponding increase in the liability of the plan.

Interest Charges

For the three, six and twelve months ended December 31, 2009, interest charges decreased $199,000 (16%), $299,000 (12%) and $412,000 (9%), respectively, due to decreased borrowings on our bank line of credit and decreases in the average interest rate on our bank line of credit.


Income Tax Expense

For the three months ended December 31, 2009, income tax expense increased $392,000 (53%). For the six and twelve months ended December 31, 2009, income tax expense decreased $137,000 (15%) and $1,138,000 (28%), respectively. These changes are a result of changes in net income before income taxes.


 
 
 


Basic and Diluted Earnings Per Common Share

For the three, six and twelve months ended December 31, 2009, 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.

We have no potentially dilutive securities. As a result, our basic earnings per common share and our diluted earnings per common share are the same.



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.

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 contracts meet the definition of a derivative, we have designated these contracts as “normal purchases” and “normal sales” under Accounting Standards Codification Topic 815, entitled Derivates and Hedging.

We are exposed to risk resulting from changes in interest rates on our variable rate bank line of credit.  The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate.  The balances on our bank line of credit were $12,016,000, $3,653,000 and $28,653,000 on December 31, 2009, June 30, 2009 and December 31, 2008, respectively.  The weighted average interest rates on our bank line of credit were 1.7%, 1.8%, and 2.7% on December 31, 2009, June 30, 2009 and December 31, 2008, respectively.  Based on the amounts of our outstanding bank line of credit on December 31, 2009, June 30, 2009 and December 31, 2008, a one percent (one hundred basis point) increase in our average interest rates would result in decreases in our annual pre-tax net income of $120,000, $37,000 and $287,000, respectively.  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%.

 

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, 2009, 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 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, 2009 and found no changes that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


 
 

ITEM 1.
   
 
We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial condition or results of operations.

ITEM 1A.
   
 
No material changes.


ITEM 4.
       
 
(a)
  
We held our Annual Meeting of Shareholders on November 19, 2009.
 
 
(b)
  
Michael J. Kistner and Michael R. Whitley were elected to our Board of Directors for three-year terms expiring in 2012.  Linda K. Breathitt, Lanny D. Greer and Billy Joe Hall will continue to serve on our Board of Directors until the election in 2010.  Glenn R. Jennings, Lewis N. Melton and Arthur E. Walker, Jr. will continue to serve on our Board of Directors until the election in 2011.
 
 
(c)
  
The total shares voted in the election of Directors were 3,029,977.  There were no broker non-votes.  The shares voted for each Nominee were:

 
Michael J. Kistner
For
2,921,041
Withheld
108,936
 
Michael R. Whitley
For
2,742,930
Withheld
287,047

 
(d)
  
Included in our proxy materials for our 2009 Annual Meeting of Shareholders was a proposal to approve our Incentive Compensation Plan, as adopted by our Board of Directors.  See Note 12 of the Notes to Consolidated Financial Statements.  Our shareholders approved the incentive compensation plan, and the vote tabulation was:

 
For
1,162,280
  
 
Against
533,653
  
 
Abstain
75,404
  


 
 
 



   
ITEM 5.
   
 
None.
   
ITEM 6.

 
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.


 
 
 


 
 
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 8, 2010
  
/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 and Principal Accounting Officer)