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EX-32.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INCexhibit321.htm
EX-31.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INCexhibit312.htm
EX-32.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INCexhibit322.htm
EX-31.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INCexhibit311.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, 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 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, 2011, Delta Natural Gas Company, Inc. had 3,392,433 shares of Common Stock outstanding.




 
1

 



DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

FINANCIAL INFORMATION
 
3
       
ITEM 1.
 
3
       
 
Condensed Consolidated Statements of Income (Unaudited) for the three and six month periods ended December 31, 2011 and 2010
 
3
       
 
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2011 and June 30, 2011
 
4
       
 
Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the six month periods ended December 31, 2011 and 2010
 
6
       
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six month periods ended December 31, 2011 and 2010
 
7
       
   
8
       
ITEM 2.
 
16
       
ITEM 3.
 
23
       
ITEM 4.
 
23
       
OTHER INFORMATION
 
24
       
ITEM 1.
 
24
       
ITEM 1A.
 
24
       
ITEM 2.
 
24
       
ITEM 3.
 
24
       
ITEM 4.
 
24
       
ITEM 5.
 
24
       
ITEM 6.
 
24
       
   
26
       


 
2

 

PART I – FINANCIAL INFORMATION

 
ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
 
   
 
Three Months Ended
 
Six Months Ended
     
   
December 31,
 
December 31,
     
   
2011
 
2010
 
2011
 
2010
         
                                       
OPERATING REVENUES
                                     
Regulated revenues
 
$
12,978,686
 
$
15,246,971
 
$
18,601,322
 
$
20,113,907
             
Non-regulated revenues
   
9,547,659
   
8,509,333
   
16,821,350
   
13,658,875
             
Total operating revenues
 
$
22,526,345
 
$
23,756,304
 
$
35,422,672
 
$
33,772,782
             
                                       
OPERATING EXPENSES
                                     
Purchased gas
 
$
12,266,587
 
$
13,316,740
 
$
19,473,136
 
$
18,371,084
             
Operation and maintenance
   
3,244,930
   
3,388,416
   
6,380,145
   
6,749,012
             
Depreciation and amortization
   
1,481,143
   
1,284,852
   
2,941,718
   
2,276,219
             
Taxes other than income taxes
   
549,391
   
484,124
   
1,077,278
   
859,847
             
                                       
Total operating expenses
 
$
17,542,051
 
$
18,474,132
 
$
29,872,277
 
$
28,256,162
             
                                       
OPERATING INCOME
 
$
4,984,294
 
$
5,282,172
 
$
5,550,395
 
$
5,516,620
             
                                       
OTHER INCOME (DEDUCTIONS), NET
   
52,485
   
55,027
   
(22,179
)
 
106,413
             
                                       
INTEREST CHARGES
   
1,023,650
   
1,035,964
   
2,780,782
   
2,051,996
             
                                       
NET INCOME BEFORE INCOME TAXES
 
$
4,013,129
 
$
4,301,235
 
$
2,747,434
 
$
3,571,037
             
                                       
INCOME TAX EXPENSE
   
1,500,891
   
1,607,211
   
1,032,322
   
1,293,190
             
                                       
NET INCOME
 
$
2,512,238
 
$
2,694,024
 
$
1,715,112
 
$
2,277,847
             
                                       
INCOME PER COMMON SHARE (Note 11)
Basic and diluted
 
$
.74
 
$
.80
 
$
.51
 
$
.68
             
                                       
DIVIDENDS DECLARED PER COMMON SHARE
 
$
.35
 
$
.34
 
$
.70
 
$
.68
             












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

 
3

 

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
  
     
December 31,
 
June 30,
     
     
2011
 
2011
     
ASSETS
                   
                       
 
CURRENT ASSETS
                   
 
Cash and cash equivalents
 
$
484,139
 
$
7,340,192
       
 
Accounts receivable, less accumulated allowances for doubtful accounts of $112,000 and $190,000, respectively
   
16,087,653
   
6,540,702
       
 
Gas in storage, at average cost
   
8,631,911
   
6,811,260
       
 
Deferred gas costs
   
5,690,666
   
3,378,711
       
 
Materials and supplies, at average cost
   
541,547
   
555,883
       
 
Prepayments
   
1,902,424
   
2,113,224
       
 
Total current assets
 
$
33,338,340
 
$
26,739,972
       
                       
 
PROPERTY, PLANT AND EQUIPMENT
 
$
213,906,055
 
$
211,409,336
       
 
Less-Accumulated provision for depreciation
   
(80,388,068
)
 
(78,232,077
)
     
 
Net property, plant and equipment
 
$
133,517,987
 
$
133,177,259
       
                       
 
OTHER ASSETS
                   
 
Cash surrender value of life insurance
 
$
495,913
 
$
508,808
       
 
Prepaid pension
   
3,400,665
   
3,141,116
       
 
Regulatory assets
   
10,977,240
   
8,823,310
       
 
Unamortized debt expense
   
107,904
   
1,994,788
       
 
Other non-current assets
   
556,119
   
510,986
       
 
Total other assets
 
$
15,537,841
 
$
14,979,008
       
                       
 
Total assets
 
$
182,394,168
 
$
174,896,239
       
                       

















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

 
4

 


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

       
December 31,
   
June 30,
       
       
2011
   
2011
       
                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                   
                       
 
CURRENT LIABILITIES
                   
 
Accounts payable
 
$
5,287,229
 
$
8,201,249
       
 
Notes payable
   
6,235,927
   
       
 
Current portion of long-term debt
   
1,500,000
   
1,200,000
       
 
Accrued taxes
   
4,222,207
   
1,447,094
       
 
Customers’ deposits
   
838,448
   
643,692
       
 
Accrued interest on debt
   
935,101
   
852,952
       
 
Accrued vacation
   
607,236
   
707,544
       
 
Deferred income taxes
   
1,847,257
   
1,092,255
       
 
Other current liabilities
   
407,054
   
317,867
       
 
Total current liabilities
 
$
21,880,459
 
$
14,462,653
       
                       
 
LONG-TERM DEBT
 
$
56,500,000
 
$
56,751,006
       
                       
 
LONG-TERM LIABILITIES
                   
 
Deferred income taxes
 
$
35,024,090
 
$
35,114,249
       
 
Investment tax credits
   
74,700
   
86,700
       
 
Regulatory liabilities
   
1,455,486
   
1,507,928
       
 
Asset retirement obligations
   
2,662,014
   
2,560,796
       
 
Other long-term liabilities
   
834,267
   
645,723
       
 
Total long-term liabilities
 
$
40,050,557
 
$
39,915,396
       
                       
 
COMMITMENTS AND CONTINGENCIES (Note 8)
                   
 
Total liabilities
 
$
118,431,016
 
$
111,129,055
       
                       
 
SHAREHOLDERS’ EQUITY
                   
 
Common shares ($1.00 par value, 20,000,000 shares
                   
 
authorized; 3,392,433 and 3,366,172 shares
                   
 
outstanding at December 31, 2011 and June 30,
                   
 
2011, respectively)
 
$
3,392,433
 
$
3,366,172
       
 
Premium on common shares
   
46,886,218
   
46,054,488
       
 
Retained earnings
   
13,684,501
   
14,346,524
       
 
Total shareholders’ equity
 
$
63,963,152
 
$
63,767,184
       
                       
 
Total liabilities and shareholders’ equity
 
$
182,394,168
 
$
174,896,239
       














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

 
5

 

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(UNAUDITED)
 
       
   
Six Months Ended December 31, 2011
 
   
Common Shares
 
Premium on Common Shares
 
Retained Earnings
 
Shareholders’ Equity
 
                           
Balance, beginning of period
 
$
3,366,172
 
$
46,054,488
 
$
14,346,524
 
$
63,767,184
 
Net income
   
   
   
1,715,112
   
1,715,112
 
Issuance of common shares
   
9,927
   
312,443
   
   
322,370
 
Issuance of common shares under the
                         
Incentive Compensation Plan
   
11,000
   
326,040
   
   
337,040
 
Share-based compensation expense
   
5,334
   
171,685
   
   
177,019
 
Tax benefit from share-based compensation
   
   
21,562
   
   
21,562
 
Dividends on common shares
   
   
   
(2,377,135
)
 
(2,377,135
)
                           
Balance, end of period
 
$
3,392,433
 
$
46,886,218
 
$
13,684,501
 
$
63,963,152
 



       
     
Six Months Ended December 31, 2010
 
     
Common Shares
   
Premium on Common Shares
   
Retained Earnings
   
Shareholders’ Equity
 
                           
Balance, beginning of period
 
$
3,334,856
 
$
44,881,401
 
$
12,543,913
 
$
60,760,170
 
Net income
   
   
   
2,277,847
   
2,277,847
 
Issuance of common shares
   
12,790
   
362,890
   
   
375,680
 
Issuance of common shares under the
                         
Incentive Compensation Plan
   
9,000
   
254,970
   
   
263,970
 
Share-based compensation expense
   
   
59,745
   
   
59,745
 
Dividends on common shares
   
   
   
(2,276,959
)
 
(2,276,959
)
                           
Balance, end of period
 
$
3,356,646
 
$
45,559,006
 
$
12,544,801
 
$
61,460,453
 













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

 
6

 

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED) 
 
   
Six Months Ended
     
   
December 31,
     
   
2011
 
2010
         
                   
CASH FLOWS FROM OPERATING ACTIVITIES
                         
Net income
 
$
1,715,112
 
$
2,277,847
             
Adjustments to reconcile net income to net cash from operating activities
                         
Depreciation and amortization
   
3,176,190
   
2,523,991
             
Deferred income taxes and investment tax credits
   
593,277
   
1,404,417
             
Change in cash surrender value of officer’s life insurance
   
12,895
   
(32,095
)
           
Share-based compensation
   
514,059
   
323,715
             
Increase in assets
   
(13,907,021
)
 
(12,719,426
)
           
Increase in liabilities
   
471,948
   
445,727
             
                           
Net cash used in operating activities
 
$
(7,423,540
)
$
(5,775,824
)
           
                           
CASH FLOWS FROM INVESTING ACTIVITIES
                         
Capital expenditures
 
$
(3,611,725
)
$
(4,169,186
)
           
Proceeds from sale of property, plant and equipment
   
95,398
   
92,426
             
Other
   
(60,000
)
 
431,897
             
Net cash used in investing activities
 
$
(3,576,327
)
$
(3,644,863
)
           
                           
CASH FLOWS FROM FINANCING ACTIVITIES
                         
Dividends on common shares
 
$
(2,377,135
)
$
(2,276,959
)
           
Issuance of common shares
   
322,370
   
375,680
             
Debt issuance costs
   
(107,904
)
 
             
Issuance of long-term debt
   
58,000,000
   
             
Excess tax benefit from share-based compensation
   
21,562
   
             
Repayment of long-term debt
   
(57,951,006
)
 
(150,994
)
           
Borrowing on bank line of credit
   
17,360,379
   
15,895,021
             
Repayment of bank line of credit
   
(11,124,452
)
 
(8,859,355
)
           
                           
Net cash provided by financing activities
 
$
4,143,814
 
$
4,983,393
             
                           
DECREASE IN CASH AND CASH EQUIVALENTS
 
$
(6,856,053
)
$
(4,437,294
)
           
                           
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
   
7,340,192
   
4,639,145
             
                           
CASH AND CASH EQUIVALENTS,
END OF PERIOD
 
$
484,139
 
$
201,851
             












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

 
7

 

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

(1)
Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 customers.  Our distribution and transmission systems are located in central and southeastern Kentucky, and we operate an underground storage field in southeastern Kentucky.  We transport natural gas to our industrial customers who purchase their 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 natural gas and resells it to industrial or other large use customers on Delta’s system. Delgasco, Inc. (“Delgasco”) buys gas and resells it to Delta Resources, Inc. and to customers not on Delta’s system.  Enpro, Inc. (“Enpro”) owns and operates production properties and undeveloped acreage.

All subsidiaries of Delta are included in the condensed consolidated financial statements. Intercompany balances and transactions have been eliminated.  All adjustments necessary for a fair presentation of the unaudited results of operations for the three and six months ended December 31, 2011 and 2010 are included.  All such adjustments are accruals of a normal and recurring nature other than the amounts accrued by Delta Resources related to an assessment of the Utility Gross Receipts License Tax discussed in Note 8 and the insurance proceeds discussed in Note 13.

The results of operations for the period ended December 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.

The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the financial statements, and the notes thereto, included in our Annual Report on Form 10-K for the year ended June 30, 2011.

(2)           New Accounting Pronouncements

In May, 2011, the Financial Accounting Standards Board issued guidance on fair value measurement and disclosure.  The guidance was issued as part of a joint effort between the Financial Accounting Standards Board and the International Accounting Standards Board to converge the two sets of standards into a single conceptual framework which would change how fair value measurement guidance is applied in future periods.  The guidance, which will be effective for our quarter ending March 31, 2012, is not expected to have a material impact on our results of operations, financial position or cash flows.


 
8

 


(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 other non-current assets on the Condensed Consolidated Balance Sheets.  Contributions to the trust are presented in other investing activities on the Condensed Consolidated Statements of Cash Flows.  The assets of the trust are recorded at fair value and consist of exchange traded mutual funds.  The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy.  The fair value of the trust assets are as follows:

   
December 31,
 
June 30,
     
 
($000)
2011
 
2011
     
               
 
Trust assets
           
 
Money market
2
 
5
     
 
U.S. equity securities
336
 
320
     
 
U.S. fixed income securities
218
 
186
     
   
556
 
511
     

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

Our Series A Notes, Debentures and Insured Quarterly Notes, presented as current portion of long-term debt and long-term debt on the Condensed Consolidated Balance Sheets, are stated at historical cost.  Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate.  The Insured Quarterly Notes contained insurance that provided for the continuing payment of principal and interest to the holders in the event we defaulted on the Insured Quarterly Notes.  Upon default, the insurer would have paid interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation would have transferred to the insurer.  Therefore, the insurance is not considered in the determination of the fair value of the Insured Quarterly Notes.

   
December 31,
 
June 30,
 
   
2011
 
2011
 
   
Carrying
 
Fair
 
Carrying
 
Fair
 
 
($000)
Amount
 
Value
 
Amount
 
Value
 
                   
 
4.26% Series A Notes
58,000
 
58,060
 
 
 
 
7% Debentures
 
 
19,410
 
18,988
 
 
5.75% Insured Quarterly Notes
 
 
38,541
 
34,400
 

(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 commodity price risk with our 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.



 
9

 


Unbilled revenues and gas costs include the following:

     
December 31,
 
June 30,
     
 
(000)
 
2011
 
2011
     
                 
 
Unbilled revenues ($)
 
4,689
 
1,437
     
 
Unbilled gas costs ($)
 
2,174
 
410
     
 
Unbilled volumes (Mcf)
 
366
 
58
     

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

(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
     
   
December 31,
 
December 31,
     
($000)    
 
2011
 
2010
 
2011
 
2010
         
                           
Service cost
 
231
 
235
 
462
 
469
         
Interest cost
 
230
 
213
 
460
 
427
         
Expected return on plan assets
 
(369
)
(269
)
(738
)
(539
)
       
Amortization of unrecognized net loss
 
50
 
125
 
100
 
250
         
Amortization of prior service cost
 
(22
)
(22
)
(44
)
(43
)
       
Net periodic benefit cost
 
120
 
282
 
240
 
564
         

(7)
Debt Instruments

Notes Payable

The current bank line of credit with Branch Banking and Trust Company, shown as notes payable on the Condensed Consolidated Balance Sheet, permits borrowings up to $40,000,000, of which $6,236,000 was borrowed as of December 31, 2011 having a weighted average interest rate of 1.42%.  As of June 30, 2011, all of the bank line of credit was available.  The bank line of credit extends through June 30, 2013.  The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.15%.  The annual cost of the unused bank line of credit is .125%.

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

Long-Term Debt

In December, 2011, we refinanced our 5.75% Insured Quarterly Notes ($38,450,000) and 7% Debentures ($19,410,000) from the proceeds of a private debt financing. Under the Note Purchase and Private Shelf Agreement (the “Agreement”), we issued $58,000,000 of Series A Notes, for which the purchasers paid 100% of the face principal amount.

Unamortized debt expense of $1,896,000 related to the 5.75% Insured Quarterly Notes and 7% Debentures was reclassified from unamortized debt expense to regulatory assets on the accompanying Condensed Consolidated Balance Sheet. The $1,896,000 regulatory asset representing the loss on extinguishment of the 5.75% Insured Quarterly Notes and 7% Debentures combined with $1,872,000 of unamortized loss on extinguishment of debt recognized from prior refinancings will be amortized over the life of the 4.26% Series A Notes, as approved by the Kentucky Public Service Commission.

 
10

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

($000)
 
   
2012
 
2013
 
1,500
2014
 
1,500
2015
 
1,500
2016
 
1,500
Thereafter
 
52,000
    Total long-term debt
 
58,000
     
Any additional prepayment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with a maturity equal to the remaining average life of the Series A Notes.

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

(8)
Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in control agreements with our other four officers.  The agreements expire or may be terminated at various times.  The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company.  In the event all of these agreements were exercised in the form of lump sum payments, approximately $3.7 million would be paid in addition to continuation of specified benefits for up to five years.  Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, would immediately vest.

The Kentucky Department of Revenue has assessed Delta Resources $5,565,000, which includes $3,013,000 in taxes, $1,963,000 in penalties and $589,000 in interest, for failure to collect and remit a 3% Utility Gross Receipts License Tax for the period July, 2005 through June, 2011.  The tax is a 3% license tax levied on the gross receipts derived from furnishing utility services and is passed through to customers.  The Kentucky Department of Revenue has not asserted a claim for the tax periods after June, 2011 or interest accrued subsequent to the initial assessments.  Regarding the penalties, Kentucky law provides for the assessment of penalties for failure to pay a tax, unless it is shown to the satisfaction of the Kentucky Department of Revenue that the failure to pay is due to reasonable cause.  Applicable regulatory authority provides that reasonable cause exists when the tax position is based on advice by a tax advisor on whom the taxpayer had a reasonable right to rely or substantial legal authority, as we have done in this matter.  Therefore, as of December 31, 2011, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,841,000, which includes $3,055,000 in taxes and $786,000 in interest.

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

 
11

 
However, on October 7, 2011, the Kentucky Court of Appeals reversed the May, 2010 Fayette Circuit Court opinion, which had held that the Utility Gross Receipts License Tax did not apply to sales of gas by Constellation, a gas marketer, because it is not a utility.  The opinion of the Kentucky Court of Appeals held that “because Constellation furnishes natural gas to Saint Joseph, Constellation is subject to imposition of the utility [gross receipts license] tax.” Saint Joseph Health System, Inc. filed a petition for rehearing on October 27, 2011 on the grounds that the court’s opinion was in direct conflict with the Kentucky Department of Revenue’s long-standing statutory interpretation.  The Kentucky Court of Appeals decided on January 30, 2012 to deny the petition. Discretionary review of this opinion by the Kentucky Supreme Court is possible, and we can neither predict whether such review will be sought nor what the outcome of any such review may be.  Therefore, we cannot predict the final judicial outcome of this case.

As a result of the uncertainty created by the October 7, 2011 opinion issued by the Kentucky Court of Appeals, we accrued the total liability of $3,841,000 and began billing the Utility Gross Receipts License Tax to Delta Resources’ customers prospectively with our October, 2011 billings.  Since October, 2011, Delta Resources has billed its customers $60,000 for Utility Gross Receipts License Tax, of which substantially all has been collected.  In the event we are unsuccessful in resolving our protest with the Kentucky Department of Revenue, of the $3,841,000 total liability, Delta Resources would have the right to seek reimbursement from its customers for the $3,055,000 of taxes, leaving Delta Resources liable for $786,000 of interest in addition to any uncollectible amounts. We estimate that Delta Resources’ potential liability for interest and taxes deemed uncollectible from Delta Resources’ customers to be in the range of $793,000 to $3,841,000.  This estimate is based on the assumption that we will not be held liable for any penalties.

As of December 31, 2011, we recorded the total liability of $3,841,000, a receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $793,000 of expense related to interest and uncollectibles. Included in the receivable is $196,000 due from a Delta Resources customer which is wholly owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the December 31, 2011 Condensed Consolidated Balance Sheet, the liability for taxes is included in accrued taxes, the receivable from Delta Resources’ customers is included in accounts receivable, less accumulated allowances for doubtful accounts, and the liability for interest is included in other current liabilities.  In the December 31, 2011 Condensed Consolidated Statement of Income, interest accrued is included in interest charges and uncollectible amounts are included in operation and maintenance.

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

We have entered into forward purchase agreements beginning in October, 2011 and expiring at various dates through December, 2012.  These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements.  These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements.  These agreements have aggregate remaining minimum purchase obligations of $479,000 and $294,000 for our fiscal years ending June 30, 2012 and June 30, 2013, 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.

In April, 2010, we filed a request for increased base 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.  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%.

 
12

 
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 is less dependent on customer usage and occurs 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, the Kentucky Public Service Commission approved our initial pipe replacement filing, effective May, 2011, which provides us $139,000 in additional annual revenues.  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, production and sales of natural gas liquids.  The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky.  Virtually all of the revenues recorded under both segments come from the sale 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 changes in the market price of gas and uncommitted gas volumes of our non-regulated companies.

The segments follow the accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Condensed Consolidated Financial Statements which are included in our Annual Report on Form 10-K for the year ended June 30, 2011.  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.  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
     
   
December 31,
 
December 31,
     
($000)
 
2011
 
2010
 
2011
 
2010
         
Operating Revenues
                         
Regulated
                         
External customers
 
12,978
 
15,247
 
18,602
 
20,114
         
Intersegment
 
1,064
 
1,028
 
1,828
 
1,695
         
Total regulated
 
14,042
 
16,275
 
20,430
 
21,809
         
Non-regulated
                         
External customers
 
9,548
 
8,509
 
16,821
 
13,659
         
Eliminations for intersegment
 
(1,064
)
(1,028
)
(1,828
)
(1,695
)
       
Total operating revenues
 
22,526
 
23,756
 
35,423
 
33,773
         

 
13

 
   
Three Months Ended
 
Six Months Ended
     
   
December 31,
 
December 31,
     
($000)
 
2011
 
2010
 
2011
 
2010
         
Net Income
                         
Regulated
 
1,992
 
2,132
 
1,643
 
1,572
         
Non-regulated
 
520
 
562
 
72
 
706
         
Total net income
 
2,512
 
2,694
 
1,715
 
2,278
         

(11)           Earnings per Common Share

Certain awards under our incentive compensation plan, as further discussed in Note 12 of Notes to Condensed Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares.  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive.  There were 11,000 unvested participating shares outstanding as of December 31, 2011.  There were no unvested participating shares outstanding as of December 31, 2010.

As of December 31, 2011 and 2010, there were 18,000 and 16,000 unvested non-participating performance shares outstanding, respectively.  As of December 31, 2011 and 2010, these unvested non-participating performance shares are not dilutive as the underlying performance condition has not yet been satisfied.

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

   
Three Months Ended
 
Six Months Ended
   
   
December 31,
 
December 31,
   
   
2011
 
2010
   
2011
 
2010
       
Numerator – Basic and Diluted
                         
Net Income ($000)
 
2,512
 
2,694
   
1,715
 
2,278
       
Less:  dividends paid ($000)
 
(1,189
)
(1,139
)
 
(2,377
)
(2,277
)
     
                           
Undistributed earnings ($000)
 
1,323
 
1,555
   
(662
)
1
       
Percentage allocated to common shares (a)
 
99.7
%
100.0
%
 
99.7
%
100.0
%
     
                           
Undistributed earnings allocated to common shares ($000)
 
1,318
 
1,555
   
(660
)
1
       
Add:  dividends declared allocated to common shares ($000)
 
1,186
 
1,139
   
2,370
 
2,277
       
                           
Net income available to common shares ($000)
 
2,504
 
2,694
   
1,710
 
2,278
       
                           
Denominator  –  Basic and Diluted
Weighted-average
                         
Common shares
 
3,388,243
 
3,351,890
   
3,381,144
 
3,346,584
       
                           
Per common share net income ($)
                         
Basic
 
.74
 
.80
   
.51
 
.68
       
Diluted
 
.74
 
.80
   
.51
 
.68
       
 
 
14

 
                           
   
Three Months Ended
 
Six Months Ended
   
   
December 31,
 
December 31,
   
   
2011
 
2010
   
2011
 
2010
       
(a) Percentage allocated to common shares – weighted average
                         
Common shares outstanding
 
3,388
 
3,352
   
3,381
 
3,347
       
Unvested participating shares
 
11
 
   
11
 
       
Total
 
3,399
 
3,352
   
3,392
 
3,347
       
Percentage allocated to common shares
 
99.7
%
100.0
%
 
99.7
%
100.0
%
     

(12)
Share-Based Compensation

We have a shareholder approved incentive compensation plan (the “Plan”), which provides for incentive compensation payable in shares of our common stock.  The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining 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 December 31, 2011, 464,000 shares of common stock were available for issuance under the Plan.  Shares of common stock may be available from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market.

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

   
Three Months Ended
 
Six Months Ended
     
   
December 31,
 
December 31,
     
 
($000)
2011
 
2010
 
2011
 
2010
         
                           
 
Share-based compensation expense
99
 
36
 
514
 
324
         
                           

For the three and six months ended December 31, 2011, approximately a $22,000 tax benefit was recognized as a premium on common shares on our Condensed Consolidated Balance Sheet, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation.  This excess tax benefit can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods.  An immaterial tax deficiency was recognized in income tax expense for the three and six months ended December 31, 2010.

Stock Awards

For the six months ended December 31, 2011 and 2010, common stock was awarded to virtually all Delta employees and directors having grant date fair values of $337,000 (11,000 shares) and $264,000 (9,000 shares), respectively.  The recipients vested in the award shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.


 
15

 


 
Performance Shares

For the six months ended December 31, 2011 and 2010, performance shares were awarded to the Company’s executive officers having grant date fair values of $552,000 (18,000 shares) and $469,000 (16,000 shares), respectively. The performance share awards vest only if the performance objectives of the awards are met, which is based on the Company’s earnings per common share, before any cash bonuses or share-based compensation, for the fiscal year in which the performance shares are awarded. Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest equally over a three-year period beginning the August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period.  The recipients of the awards also become vested as a result of certain events such as death or disability of the holders. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards.  Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.

If the performance objectives for the 2012 performance shares are met, up to 18,000 unvested shares could be issued to the recipients. The performance objectives for the 2011 performance shares were met and 16,000 unvested shares were issued on August 31, 2011, of which 11,000 shares remain unvested as of December 31, 2011.

For the three and six months ended December 31, 2011 compensation expense related to the performance shares was $99,000 and $177,000, respectively.  For the three and six months ended December 31, 2010 compensation expense related to the performance shares was $36,000 and $60,000, respectively.

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

(13)           Insurance Proceeds

During September, 2011, we received $300,000 of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company’s underground storage field.  These proceeds are included in operation and maintenance in the Condensed Consolidated Statement of Income for the six months ended December 31, 2011.


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

YEAR TO DATE DECEMBER 31, 2011 OVERVIEW AND FUTURE OUTLOOK

For the six months ended December 31, 2011, basic and diluted net income per common share of $.51 decreased $.17 per common share as compared to the $.68 basic and diluted net income per common share for the six months ended December 31, 2010.  During the six months ended December 31, 2011, we accrued $793,000 ($492,000 net of income tax benefit) of expense relating to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 8 of the Notes to Condensed Consolidated Financial Statements).  The assessment is currently under protest by us with the Kentucky Department of Revenue.  The impact of the tax assessment was partially offset by the sale of natural gas liquids as we completed installation during fiscal 2012 of a facility that is designed to extract liquids from the natural gas in our system in order to improve the operations of our distribution, transmission and storage systems.

The results of operations for the period ended December 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 our operating revenues during the warmer months when our sales volumes decrease considerably.  Our fiscal 2012 results are dependent on the winter weather and the extent to which our customers choose to conserve their natural gas usage or discontinue their natural gas service.  We expect the remainder of 2012 to be impacted by a reduction in interest charges resulting from the refinancing of our 7% Debentures and 5.75% Insured Quarterly Notes (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements).  The regulated segment’s largest expense purchased is gas, which we are permitted to pass through to our customers.  We control remaining expenses through budgeting, approval and review.

 
16

 
Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other 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 net income in fiscal 2012.  If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated segment margins related to our natural gas production and marketing activities.  However, if natural gas prices decrease, we would expect a decrease in our non-regulated margins related to our natural gas production and marketing activities.  We anticipate selling additional natural gas liquids during 2012; however, the profitability of such sales is dependent on the amount of liquids extracted and the pricing for any such liquids as determined by a national unregulated market.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of our net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital.  Our sales and cash requirements are seasonal.  The largest portion of our sales occurs during the heating months, whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months.  Therefore, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit.  The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, of which $6,236,000 was borrowed as of December 31, 2011.  There were no borrowings outstanding on the bank line of credit as of June 30, 2011.  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 $56,500,000 at December 31, 2011, compared with $56,751,000 at June 30, 2011.  The decrease resulted from the refinancing of our 5.75% Insured Quarterly Notes and 7% Debentures, as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements.

Cash and cash equivalents were $484,000 at December 31, 2011, as compared with $7,340,000 at June 30, 2011.  The changes in cash and cash equivalents are summarized in the following table:

   
Six Months Ended
     
   
December 31,
     
($000)
 
2011
 
2010
         
                   
Used in operating activities
 
(7,424
)
(5,776
)
       
Used in investing activities
 
(3,576
)
(3,645
)
       
Provided by financing activities
 
4,144
 
4,984
         
Decrease in cash and cash equivalents
 
(6,856
)
(4,437
)
       
                   
For the six months ended December 31, 2011, cash used in operating activities increased $1,648,000 (29%). Cash paid for natural gas increased $5,430,000 due to an increase in quantities of natural gas purchased. The increase was partially offset by a $2,767,000 increase in cash received from customers resulting from increased regulated sales prices and a $1,272,000 decrease in income tax refunds due to a refund received during the prior year resulting from a method change that reduced our capitalization of expenses for income tax purposes.

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, 2011, cash provided by financing activities decreased $840,000 (17%) due to decreased net borrowings on the bank line of credit.


 
17

 


Cash Requirements

Our capital expenditures result in a continued need for capital. These capital expenditures are made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities.  We expect our capital expenditures for fiscal 2012 to be approximately $6.5 million.

The following table summarizes our contractual cash obligations for the remainder of fiscal 2012, and fiscal years thereafter:
   
Payments Due by Fiscal Year
   
2012
 
2013-2014
 
2015-2016
 
After 2016
 
Total
                             
Interest payments
$$$
1,357
 
$
4,897
 
$$$
4,555
 
$$$
26,606
 
$
37,415
Long-term debt (a)
 
   
3,000
   
3,000
   
52,000
   
58,000
Pension contributions
 
   
1,000
   
1,000
   
4,500
   
6,500
Gas purchases
 
479
   
294
   
   
   
773
Total contractual obligations
$$$
1,836
 
$
9,191
 
$$$
8,555
 
$$$
83,106
 
$
102,688

(a)  
See Note 7 of Notes to Condensed Consolidated Financial Statements for a description of this debt.

See Note 8 of Notes to Condensed Consolidated Financial Statements for other commitments and contingencies. See Item 7. Management’s Discussion and Analysis included in our Annual Report on Form 10-K for the year ended June 30, 2011 for additional information related to our contractual cash obligations.

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 permits borrowings up to $40,000,000, of which $6,236,000 was borrowed at December 31, 2011.

In December, 2011, we refinanced our 5.75% Insured Quarterly Notes and 7% Debentures from the proceeds of a private debt financing. Under the Note Purchase and Private Shelf Agreement (the “Agreement”), we issued $58,000,000 of Series A Notes, for which the purchasers paid 100% of the face principal amount. The proceeds from the sale of the Series A Notes were used to fund the redemption of our 5.75% Insured Quarterly Notes Due April 1, 2021, which had an outstanding principal balance of $38,450,000, and our 7% Debentures Due February 1, 2023, which had an outstanding principal balance of $19,410,000.

Our Series A Notes are unsecured, bearing interest at a rate of 4.26% per annum and maturing on December 20, 2031.  Interest on the Series A Notes is payable quarterly beginning in March, 2012.  Beginning in December, 2012, we are required to make an annual $1,500,000 principal payment on the Series A Notes. 

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

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


 
18

 


With our bank line of credit and Series A Notes, we have agreed to certain financial covenants.  Noncompliance with these covenants can make the obligation immediately due and payable. We have agreed to the following financial covenants:

·  
The Company must at all times maintain a tangible net worth of at least $25,800,000.
 

·  
The Company must at the end of each fiscal quarter maintain a total debt to capitalization ratio of no more than 70%.  The total debt to capitalization ratio is calculated as the ratio of (i) the Company’s total debt to (ii) the sum of the Company’s shareholders’ equity plus total debt.  
 

·  
The Company must maintain a fixed charge coverage ratio for the twelve months ending each quarter of not less than 1.20x.  The fixed charge coverage ratio is calculated as the ratio of (i) the Company’s earnings  adjusted for certain unusual or non-recurring items, before interest, taxes, depreciation and amortization plus rental expense to (ii) the Company’s interest and rental expense.   

·  
The Company may not pay aggregate dividends on its capital stock (plus amounts paid in redemption of its capital stock) in excess of the sum of $15,000,000 and the Company’s cumulative earnings adjusted for certain unusual or non-recurring items, after September 30, 2011.

The following table shows the required and actual financial covenants under our Series A Notes as of December 31, 2011:

   
Requirement
 
Actual
         
Tangible net worth
 
no less than $25,800,000
 
$63,192,000
 
Debt to capitalization ratio
 
no more than 70%
 
50%
 
Fixed charge coverage ratio
 
no less than 1.20x
 
5.52x
 
Dividends paid
 
no more than $17,536,000
 
$1,189,000
 

Additionally, the bank line of credit and the Series A Notes contain affirmative and negative covenants.  The most restrictive, subject to certain exclusions, limit our ability to:

·  
permit or grant liens or security interests;
 
·  
sell subsidiaries or transfer assets outside of the normal course of business;
 
·  
incur secured debt in an amount that exceeds 10% of tangible net worth;
 
·  
merge with another company;
 
·  
change the general nature of our business;
 
·  
issue any stock to the public or in an exempt transaction whereby such issuances in the aggregate exceed thirty-five percent (35%) of the currently authorized and outstanding shares of common stock; or
 
·  
permit any person or group of related persons to hold more than twenty percent (20%) of the Company’s outstanding shares of common stock.
 

The Series A Notes are subject to customary events of default, including failure to make payments of principal or interest when due, breaches of other material obligations of the Company and breaches of the Agreement, including breaches of the financial and other covenants set forth above.  Upon an event of default, the holders of the Series A Notes may exercise customary remedies, including accelerating the indebtedness due under the Series A Notes, and the Company would be prohibited from paying any dividends. 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 the Series A Notes. We were not in default on our bank line of credit or Series A Notes during any period presented in the Condensed Consolidated Financial Statements.

Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated base rates and transportation rates we charge our customers.  The Kentucky Public Service Commission sets these prices and we monitor our need to file rate requests with the Kentucky Public Service Commission for a general rate increase for our regulated services.  Our regulated base rates and transportation rates were adjusted in our 2010 rate case and were implemented in October, 2010.


 
19

 


RESULTS OF OPERATIONS

Gross Margins

Our operating revenues are derived primarily from the sale of natural gas and the provision of natural gas transportation services.  We define “gross margin” as gas sales less the corresponding purchased gas expenses, plus transportation and other revenues.  We view gross margins as an important performance measure of the core profitability of our operations and believe that investors benefit from having access to the same financial measures that our management uses.  Gross margin can be derived directly from our Condensed Consolidated Statements of Income as follows:
 
 
Three Months Ended
 
Six Months Ended
 
($000)
2011
 
2010
 
2011
 
2010
 
                 
Operating revenues (a)
22,526
 
23,756
 
35,423
 
33,773
 
Less – Purchased gas (a)
(12,267
)
(13,317
)
(19,473
)
(18,371
)
                 
Gross margin
10,259
 
10,439
 
15,950
 
15,402
 

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

Operating Income, as presented in the Condensed Consolidated Statements of Income, is the most directly comparable financial measure to gross margin calculated and presented in accordance with accounting principles generally accepted in the United States ("GAAP").  Gross margin is a “non-GAAP financial measure”, as defined in accordance with SEC rules.

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

In the following table we set forth variations in our gross margins for the three and six months ended December 31, 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 Condensed Consolidated Statements of Income.

   
2011 compared to 2010
 
   
Three Months
 
Six Months
 
   
Ended
 
Ended
 
($000)
 
December 31
 
December 31
 
           
Increase (decrease) in regulated gross margins:
Regulated segment
         
Natural gas sales
 
(360
)
323
 
On-system transportation
 
(34
)
37
 
Off-system transportation
 
39
 
119
 
Other
 
20
 
40
 
Intersegment elimination (a)
 
(36
)
(133
)
Total
 
(371
)
386
 
           
Non-regulated segment
Natural gas sales
 
(242
)
(420
)
Natural gas liquids
 
410
 
451
 
Other
 
(13
)
(2
)
Intersegment elimination (a)
 
36
 
133
 
Total
 
191
 
162
 
           
Increase (decrease) in consolidated gross margins
 
(180
)
548
 


 
20

 


   
2011 compared to 2010
 
   
Three Months
 
Six Months
 
   
Ended
 
Ended
 
($000)
 
December 31
 
December 31
 
           
Percentage increase (decrease) in volumes:
         
Regulated segment
         
Natural gas sales
 
(24
)
(21
)
On-system transportation
 
(5
)
(3
)
Off-system transportation
 
5
 
6
 
           
Non-regulated segment
         
Natural gas sales
 
26
 
40
 

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

Heating degree days were 89% and 91% of normal thirty year average temperatures for the three and six months ended December 31, 2011, respectively, as compared with 111% and 109% 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 December 31, 2011, consolidated gross margins decreased $180,000 (2%) due to decreased regulated gross margins of $371,000 (4%), which were partially offset by a $191,000 (9%) increase in non-regulated gross margins. Regulated gross margins decreased due to decreased volumes sold as a result of warmer weather, as compared to the same period in the prior year. Partially offsetting this decrease are increased rates billed through our weather normalization tariff and increased base rates which became effective October 22, 2010.  Non-regulated gross margins increased due to the sale of natural gas liquids, partially offset by a decline in the gross margins for non-regulated natural gas sales. The gross margin for non-regulated natural gas sales decreased due to a decline in sales prices, of which the impact was lessened by a 26% increase in volumes sold due to an increase in our non-regulated customers’ gas requirements.

For the six months ended December 31, 2011, consolidated gross margins increased $548,000 (4%) due to increased regulated and non-regulated gross margins of $386,000 (3%) and $162,000 (5%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010. The increased base rates allocated a majority of the rate increase to the monthly customer charge, partially decoupling revenues from volumes sold and thus reducing the impact of the warmer weather this year. Non-regulated gross margins increased due to the sale of natural gas liquids, partially offset by a decline in the gross margins for non-regulated natural gas sales. The gross margin for non-regulated natural gas sales decreased due to a decline in sales prices, but the impact was lessened by a 40% increase in volumes sold due to an increase in our non-regulated customers’ gas requirements.

Operation and Maintenance

For the three months ended December 31, 2011, there were no significant changes in operation and maintenance as compared to the three months ended December 31, 2010.

For the six months ended December 31, 2011, operation and maintenance decreased $369,000 (5%) due to the receipt of $300,000 of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company’s underground storage field.

Depreciation and Amortization

For the three and six months ended December 31, 2011, depreciation and amortization increased $196,000 (15%) and $666,000 (29%), respectively, due to increased depreciation rates allowed in our 2010 rate case.

Taxes Other Than Income Taxes

For the three months ended December 31, 2011, there were no significant changes in taxes other than income taxes as compared to the three months ended December 31, 2010.

 
21

 
For the six months ended December 31, 2011, taxes other than income taxes increased $217,000 (25%) due to increased property tax expense resulting from both higher assessed values and rates assessed by the taxing jurisdictions.

Other Income and Deductions, Net

For the three months ended December 31, 2011, there were no significant changes in other income and deductions, net as compared to the three months ended December 31, 2010.

For the six months ended December 31, 2011, other income and deductions, net decreased $128,000 (121%) due to changes in the cash surrender value of life insurance as well as changes in the fair value of the supplemental retirement trust.  Changes in the fair value of the supplemental retirement trust are offset by a change in operating expense resulting from a corresponding change in the liability of the plan.

Interest Charges

For the three months ended December 31, 2011, there were no significant changes in interest charges as compared to the three months ended December 31, 2010.

For the six months ended December 31, 2011, interest charges increased $729,000 (36%) primarily due to $786,000 of interest accrued for a tax assessment issued by the Kentucky Department of Revenue (as further discussed in Note 8 of the Notes to Condensed Consolidated Financial Statements). The assessment is currently under protest by us with the Kentucky Department of Revenue.

Income Tax Expense

For the three months ended December 31, 2011, there were no significant changes in income tax expense as compared to the three months ended December 31, 2010.

For the six months ended December 31, 2011, income tax expense decreased $261,000 (20%) due to a decrease in our net income before income taxes. There were no significant changes to our effective tax rate for the six months ended December 31, 2011 as compared to the six months ended December 31, 2010.

Basic and Diluted Earnings Per Common Share

For the three and six months ended December 31, 2011, our basic earnings per common share changed as a result of a change 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 shares awarded through our incentive compensation plan.

Certain awards under our shareholder approved incentive compensation plan provide the recipients of the awards all the rights of a shareholder of Delta Natural Gas Company, Inc. including a right to dividends declared on common shares.  Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive.  As of December 31, 2011, there were 11,000 participating unvested shares outstanding.  As of December 31, 2010, there were no participating unvested shares outstanding.

As of December 31, 2011 and 2010, there were 18,000 and 16,000 non-participating unvested performance shares outstanding, respectively.  As of December 31, 2011 and 2010, the unvested performance shares are not dilutive as the underlying performance conditions have not yet been satisfied.



 
22

 


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 our 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 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 interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate.  The balance on our bank line of credit was $6,236,000 at December 31, 2011.  There were no borrowings outstanding on our bank line of credit as of June 30, 2011.  The weighted average interest rate on our bank line of credit was 1.42% on December 31, 2011.  Based on average borrowings on our bank line of credit, a 1% (one hundred basis points) increase in our average interest rate would decrease our annual pre-tax net income by $62,000.

 
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 December 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 December 31, 2011 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 
23

 


 
PART II – OTHER INFORMATION
 

ITEM 1.
LEGAL PROCEEDINGS
   
 
We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.
 
See Note 8 of the Notes to Condensed Consolidated Financial Statements for a discussion of a tax assessment issued to Delta Resources by the Kentucky Department of Revenue.  The assessment is currently being protested by us with the Kentucky Department of Revenue.
 

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
       

ITEM 5.
OTHER INFORMATION
   
 
None.
   
ITEM 6.
EXHIBITS

 
31.1
 
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2
 
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
32.1
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
32.2
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
101.INS
 
XBRL Instance Document
 
101.SCH
 
XBRL Taxonomy Extension Schema
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
 
XBRL Taxonomy Extension Definition Database
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase
 
 
24

 
       
 
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL):
 
 
(i)
 
Document and Entity Information
 
(ii)
 
Condensed Consolidated Statements of Income (Unaudited) for the three and six month periods ended December 31, 2011 and 2010;
 
(iii)
 
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six month periods ended December 31, 2011 and 2010; and
 
(iv)
 
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2011 and June 30, 2011
 
(v)
 
Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the six month periods ended December 31, 2011 and 2010;
 
(vi)
 
Notes to Condensed Consolidated Financial Statements (Unaudited).
 
 
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or port of a registration statement or prospects for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.  We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.




 
25

 


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


DATE:  February 7, 2012
 
/s/Glenn R. Jennings
   
Glenn R. Jennings
Chairman of the Board, President and Chief Executive Officer
(Duly Authorized Officer)
     
     
   
/s/John B. Brown
   
John B. Brown
Chief Financial Officer, Treasurer and Secretary
(Principal Financial Officer)