XNAS:DGAS Delta Natural Gas Co Quarterly Report 10-Q Filing - 5/8/2012

Effective Date 5/8/2012

XNAS:DGAS Fair Value Estimate
Premium
XNAS:DGAS Consider Buying
Premium
XNAS:DGAS Consider Selling
Premium
XNAS:DGAS Fair Value Uncertainty
Premium
XNAS:DGAS Economic Moat
Premium
XNAS:DGAS Stewardship
Premium
 





 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 
Washington, DC  20549
______________

FORM 10-Q

______________

(Mark one)
 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2012
 
 
or
 
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______ to ________
 
Commission File No. 0-8788
______________
 
DELTA NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
______________

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

3617 Lexington Road, Winchester, Kentucky
40391
(Address of principal executive offices)
(Zip code)
 
859-744-6171
 
(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer  ¨                                                                                                                                      Accelerated filer  x
Non-accelerated filer  ¨  (Do not check if a smaller reporting company)                                                                                                                                Smaller reporting company  ¨
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes ¨     No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of March 31, 2012, Delta Natural Gas Company, Inc. had 6,793,768 shares of Common Stock outstanding.
 

 


 
 

 
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 nine month periods ended March 31, 2012 and 2011
 
3
       
 
Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and  June 30, 2011
 
4
       
 
Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the nine month periods ended March 31, 2012 and 2011
 
6
       
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2012 and 2011
 
7
       
   
8
       
ITEM 2.
 
17
       
ITEM 3.
 
24
       
ITEM 4.
 
24
       
OTHER INFORMATION
 
25
       
ITEM 1.
 
25
       
ITEM 1A.
 
25
       
ITEM 2.
 
25
       
ITEM 3.
 
25
       
ITEM 4.
 
25
       
ITEM 5.
 
25
       
ITEM 6.
 
25
       
   
27


 
2

 

PART I - FINANCIAL INFORMATION
 
ITEM 1. FINANCIAL STATEMENTS
 

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

   
 
Three Months Ended
 
Nine Months Ended
     
   
March 31,
 
March 31,
     
   
2012
 
2011
 
2012
 
2011
         
                                       
OPERATING REVENUES
                                     
Regulated revenues
 
$
16,927,971
 
$
21,102,579
 
$
35,529,294
 
$
41,216,486
             
Non-regulated revenues
   
9,788,099
   
14,252,431
   
26,609,449
   
27,911,306
             
Total operating revenues
 
$
26,716,070
 
$
35,355,010
 
$
62,138,743
 
$
69,127,792
             
                                       
OPERATING EXPENSES
                                     
Regulated purchased gas
 
$
7,205,406
 
$
10,673,944
 
$
13,491,470
 
$
18,858,802
             
Non-regulated purchased gas
   
7,065,624
   
11,347,074
   
20,252,696
   
21,533,300
             
Operation and maintenance
   
3,426,405
   
3,527,287
   
9,806,549
   
10,276,297
             
Depreciation and amortization
   
1,488,472
   
1,436,872
   
4,430,190
   
3,713,091
             
Taxes other than income taxes
   
558,192
   
423,954
   
1,635,471
   
1,283,802
             
                                       
Total operating expenses
 
$
19,744,099
 
$
27,409,131
 
$
49,616,376
 
$
55,665,292
             
                                       
OPERATING INCOME
 
$
6,971,971
 
$
7,945,879
 
$
12,522,367
 
$
13,462,500
             
                                       
OTHER INCOME (DEDUCTIONS), NET
   
69,694
   
31,583
   
47,514
   
137,995
             
                                       
INTEREST CHARGES
   
760,206
   
1,023,743
   
3,540,988
   
3,075,738
             
                                       
NET INCOME BEFORE INCOME TAXES
 
$
6,281,459
 
$
6,953,719
 
$
9,028,893
 
$
10,524,757
             
                                       
INCOME TAX EXPENSE
   
2,356,164
   
2,622,629
   
3,388,485
   
3,915,819
             
                                       
NET INCOME
 
$
3,925,295
 
$
4,331,090
 
$
5,640,408
 
$
6,608,938
             
                                       
EARNINGS PER COMMON SHARE  (Note 11)
                                     
Basic and diluted
 
$
.58
 
$
.65
 
$
.83
 
$
.99
             
                                       
DIVIDENDS DECLARED PER COMMON SHARE
 
$
.175
 
$
.17
 
$
.525
 
$
.51
             




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)
  
     
March 31,
 
June 30,
     
     
2012
 
2011
     
ASSETS
                   
                       
 
CURRENT ASSETS
                   
 
Cash and cash equivalents
 
$
7,800,045
 
$
7,340,192
       
 
Accounts receivable, less accumulated allowances for doubtful accounts of $209,000 and $190,000, respectively
   
11,793,545
   
6,540,702
       
 
Gas in storage, at average cost
   
5,186,312
   
6,811,260
       
 
Deferred gas costs
   
3,641,372
   
3,378,711
       
 
Materials and supplies, at average cost
   
544,736
   
555,883
       
 
Prepayments
   
1,171,905
   
2,113,224
       
 
Total current assets
 
$
30,137,915
 
$
26,739,972
       
                       
 
PROPERTY, PLANT AND EQUIPMENT
 
$
214,721,608
 
$
211,409,336
       
 
Less-Accumulated provision for depreciation
   
(81,465,627
)
 
(78,232,077
)
     
 
Net property, plant and equipment
 
$
133,255,981
 
$
133,177,259
       
                       
 
OTHER ASSETS
                   
 
Cash surrender value of life insurance
 
$
516,271
 
$
508,808
       
 
Prepaid pension
   
3,280,440
   
3,141,116
       
 
Regulatory assets
   
10,950,195
   
8,823,310
       
 
Unamortized debt expense
   
105,904
   
1,994,788
       
 
Other non-current assets
   
601,256
   
510,986
       
 
Total other assets
 
$
15,454,066
 
$
14,979,008
       
                       
 
Total assets
 
$
178,847,962
 
$
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
(UNAUDITED)

       
March 31,
   
June 30,
       
       
2012
   
2011
       
                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                   
                       
 
CURRENT LIABILITIES
                   
 
Accounts payable
 
$
3,537,024
 
$
8,201,249
       
 
Current portion of long-term debt
   
1,500,000
   
1,200,000
       
 
Accrued taxes
   
5,522,270
   
1,447,094
       
 
Customers’ deposits
   
946,087
   
643,692
       
 
Accrued interest on debt
   
981,696
   
852,952
       
 
Accrued vacation
   
693,573
   
707,544
       
 
Deferred income taxes
   
1,187,675
   
1,092,255
       
 
Other current liabilities
   
413,717
   
317,867
       
 
Total current liabilities
 
$
14,782,042
 
$
14,462,653
       
                       
 
LONG-TERM DEBT
 
$
56,500,000
 
$
56,751,006
       
                       
 
LONG-TERM LIABILITIES
                   
 
Deferred income taxes
 
$
35,515,629
 
$
35,114,249
       
 
Investment tax credits
   
68,700
   
86,700
       
 
Regulatory liabilities
   
1,442,831
   
1,507,928
       
 
Asset retirement obligations
   
2,715,646
   
2,560,796
       
 
Other long-term liabilities
   
862,220
   
645,723
       
 
Total long-term liabilities
 
$
40,605,026
 
$
39,915,396
       
                       
 
COMMITMENTS AND CONTINGENCIES (Note 8)
                   
 
Total liabilities
 
$
111,887,068
 
$
111,129,055
       
                       
 
SHAREHOLDERS’ EQUITY (Note 14)
                   
 
Common shares ($1.00 par value, 20,000,000
                   
 
  shares authorized; 6,793,768 and 6,732,344
                   
 
  shares outstanding at March 31, 2012 and June 30,
                   
 
  2011, respectively)
 
$
6,793,768
 
$
6,732,344
       
 
Premium on common shares
   
43,748,886
   
42,688,316
       
 
Retained earnings
   
16,418,240
   
14,346,524
       
 
Total shareholders’ equity
 
$
66,960,894
 
$
63,767,184
       
                       
 
Total liabilities and shareholders’ equity
 
$
178,847,962
 
$
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)
 
       
   
Nine Months Ended March 31, 2012
 
   
Common Shares
 
Premium on Common Shares
 
Retained Earnings
 
Shareholders’ Equity
 
                           
Balance, beginning of period (Note 14)
 
$
6,732,344
 
$
42,688,316
 
$
14,346,524
 
$
63,767,184
 
Net income
   
   
   
5,640,408
   
5,640,408
 
Issuance of common shares
   
28,756
   
458,574
   
   
487,330
 
Issuance of common shares under the
                         
incentive compensation plan
   
22,000
   
315,040
   
   
337,040
 
Share-based compensation expense
   
10,668
   
308,518
   
   
319,186
 
Tax benefit from share-based compensation
   
   
(21,562
)
 
   
(21,562
)
Dividends on common shares
   
   
   
(3,568,692
)
 
(3,568,692
)
                           
Balance, end of period
 
$
6,793,768
 
$
43,748,886
 
$
16,418,240
 
$
66,960,894
 


       
     
Nine Months Ended March 31, 2011
 
     
Common Shares
   
Premium on Common Shares
   
Retained Earnings
   
Shareholders’ Equity
 
                           
Balance, beginning of period (Note 14)
 
$
6,669,712
 
$
41,546,545
 
$
12,543,913
 
$
60,760,170
 
Net income
   
   
   
6,608,938
   
6,608,938
 
Issuance of common shares
   
35,986
   
504,476
   
   
540,462
 
Issuance of common shares under the
                         
incentive compensation plan
   
18,000
   
245,970
   
   
263,970
 
Share-based compensation expense
   
   
191,192
   
   
191,192
 
Dividends on common shares
   
   
   
(3,418,895
)
 
(3,418,895
)
                           
Balance, end of period
 
$
6,723,698
 
$
42,488,183
 
$
15,733,956
 
$
64,945,837
 












 
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) 
   
Nine Months Ended
     
   
March 31,
     
   
2012
 
2011
         
                   
CASH FLOWS FROM OPERATING ACTIVITIES
                         
Net income
 
$
5,640,408
 
$
6,608,938
             
Adjustments to reconcile net income to net cash flows from operating activities
                         
   Depreciation and amortization
   
4,756,462
   
4,078,948
             
   Deferred income taxes and investment tax credits
   
389,450
   
1,637,686
             
   Change in cash surrender value of officer’s life insurance
   
(7,463
)
 
(39,991
)
           
   Share-based compensation
   
613,102
   
455,162
             
Decrease (increase) in assets
   
(3,292,076
)
 
1,305,837
             
Increase in liabilities
   
300,130
   
884,036
             
                           
Net cash provided by operating activities
 
$
8,400,013
 
$
14,930,616
             
                           
CASH FLOWS FROM INVESTING ACTIVITIES
                         
Capital expenditures
 
$
(4,913,175
)
$
(6,085,663
)
           
Proceeds from sale of property, plant and equipment
   
151,725
   
140,540
             
Other
   
(60,000
)
 
431,897
             
Net cash used in investing activities
 
$
(4,821,450
)
$
(5,513,226
)
           
                           
CASH FLOWS FROM FINANCING ACTIVITIES
                         
Dividends on common shares
 
$
(3,568,692
)
$
(3,418,895
)
           
Issuance of common shares
   
487,330
   
540,462
             
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
)
 
(240,994
)
           
Borrowings on bank line of credit
   
17,697,829
   
17,824,196
             
Repayment of bank line of credit
   
(17,697,829
)
 
(17,824,196
)
           
                           
Net cash used in financing activities
 
$
(3,118,710
)
$
(3,119,427
)
           
                           
NET INCREASE IN CASH AND CASH EQUIVALENTS
 
$
459,853
 
$
6,297,963
             
                           
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
   
7,340,192
   
4,639,145
             
                           
CASH AND CASH EQUIVALENTS, END OF PERIOD
 
$
7,800,045
 
$
10,937,108
             





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

 
7

 

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

(1)
Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 36,000 customers.  Our distribution and transmission systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky.  We transport natural gas to our industrial customers who purchase their natural gas in the open market.  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 natural 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 nine months ended March 31, 2012 and 2011 are included.  All such adjustments are accruals of a normal and recurring nature other than the amounts accrued by Delta Resources related to an assessment of the Utility Gross Receipts License Tax discussed in Note 8 and the insurance proceeds discussed in Note 13.

The results of operations for the periods ended March 31, 2012 are not necessarily indicative of the results of operations to be expected for the full fiscal year.  Because of the seasonal nature of our sales, we generate a significant proportion of cash from operations during the heating months (November – April), when sales volumes increase considerably.  Most construction activity and gas storage injections take place during non-winter 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 was adopted as of March 31, 2012, did not have a material impact on our results of operations, financial position or cash flows.

(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:

   
March 31,
 
June 30,
     
 
($000)
2012
 
2011
     
               
 
Trust assets
           
 
Money market
5
 
5
     
 
U.S. equity securities
377
 
320
     
 
U.S. fixed income securities
219
 
186
     
   
601
 
511
     

 
8

 
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 credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date.  The credit adjusted risk-free rate for our 7% Debentures and 5.75% Insured Quarterly Notes was based on trades of our 7% Debentures at the measurement date.  The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy.  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 was not considered in the determination of the fair value of the Insured Quarterly Notes.
               
   
March 31, 2012
 
June 30, 2011
     
 
 
($000)
 
 
Carrying
Amount
 
 
Fair
Value
 
 
Carrying
Amount
 
 
Fair
Value
         
                           
4.26% Series A Notes
 
58,000
 
58,118
 
 
         
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.

Unbilled revenues and gas costs include the following:

     
March 31,
 
June 30,
     
 
(000)
 
2012
 
2011
     
                 
 
Unbilled revenues ($)
 
2,569
 
1,437
     
 
Unbilled gas costs ($)
 
826
 
410
     
 
Unbilled volumes (Mcf)
 
133
 
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 regulated purchased gas on the accompanying Condensed Consolidated Statements of Income.


 
9

 


(6)
Defined Benefit Retirement Plan

Net periodic benefit cost for our trusteed, non-contributory defined benefit pension plan for the periods ended March 31 include the following:
 
   
Three Months Ended
 
Nine Months Ended
     
   
March 31,
 
March 31,
     
($000)
 
2012
 
2011
 
2012
 
2011
         
                           
Service cost
 
228
 
235
 
690
 
704
         
Interest cost
 
231
 
213
 
691
 
640
         
Expected return on plan assets
 
(367
)
(269
)
(1,105
)
(809
)
       
Amortization of unrecognized net loss
 
50
 
125
 
150
 
376
         
Amortization of prior service cost
 
(21
)
(22
)
(65
)
(65
)
       
Net periodic benefit cost
 
121
 
282
 
361
 
846
         

 (7)
Debt Instruments

 
Notes Payable

The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available at March 31, 2012 and June 30, 2011.  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 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 consistent with treatment approved by the Kentucky Public Service Commission.

 
10

 


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

($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 $3.6 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 for 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 March 31, 2012, we estimate the total liability, including the original assessment, plus unasserted claims for taxes and interest to date and excluding penalties, to be $3,887,000, which includes $3,055,000 in taxes and $832,000 in interest.

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

 
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.  Saint Joseph Health System, Inc. filed a motion for discretionary review of this opinion by the Kentucky Supreme Court.  We can neither predict whether such review will be granted nor, if review is granted, 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 have accrued the total liability of $3,887,000 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 $120,000 for Utility Gross Receipts License Tax, substantially all of which has been collected.  In the event we are unsuccessful in resolving our protest with the Kentucky Department of Revenue, of the $3,887,000 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 $832,000 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 $839,000 to $3,887,000.  This estimate is based on the assumption that we will not be held liable for any penalties.

As of March 31, 2012, we recorded the total liability of $3,887,000, a receivable, net of an allowance for uncollectible amounts, of $3,048,000 and $839,000 of expense related to interest and uncollectibles. Included in the receivable is $196,000 due from a Delta Resources customer that is wholly-owned by a Director of Delta Natural Gas Company, Inc. and his immediate family.

On the March 31, 2012 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 March 31, 2012 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 $205,000 and $391,000 for our fiscal years ended 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.  Their regulation of our business includes approving the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services.  They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.

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, a change to our gas cost recovery clause and our pipe replacement program were approved.  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.  Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year that are associated with the replacement of pipe and related facilities.  Currently, the pipe replacement program, which became effective on May 1, 2011, is designed to additionally recover $139,000 annually.  On February 29, 2012, we submitted our annual pipe replacement program filing to adjust rates to recover an additional $181,000 annually through rates beginning May 1, 2012. On April 17, 2012, the Kentucky Public Service Commission suspended the increased rates for a period of five months to determine the reasonableness of the rate increase. We cannot predict the outcome of such review.

(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 revenue recorded under both segments comes 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 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 Condensed Consolidated Financial Statements that 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.

 
13

 



 
Segment information is shown below for the periods:

   
Three Months Ended
 
Nine Months Ended
     
   
March 31,
 
March 31,
     
($000)
 
2012
 
2011
 
2012
 
2011
         
Operating Revenues
                         
Regulated
                         
External customers
 
16,928
 
21,103
 
35,530
 
41,217
         
Intersegment
 
1,090
 
1,360
 
2,918
 
3,054
         
  Total regulated
 
18,018
 
22,463
 
38,448
 
44,271
         
                           
Non-regulated
                         
External customers
 
9,788
 
14,252
 
26,609
 
27,911
         
Eliminations for intersegment
 
(1,090
)
(1,360
)
(2,918
)
(3,054
)
       
Total operating revenues
 
26,716
 
35,355
 
62,139
 
69,128
         
                           
Net Income
                         
Regulated
 
3,125
 
3,588
 
4,768
 
5,160
         
Non-regulated
 
800
 
743
 
872
 
1,449
         
Total net income
 
3,925
 
4,331
 
5,640
 
6,609
         


(11)
Earnings per Common Share


Certain unvested 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.  In accordance with the provisions of our incentive compensation plan, all unvested shares have been adjusted for the two-for-one stock split having a May 1, 2012 distribution date, as further discussed in Note 14 of Notes to Condensed Consolidated Financial Statements.  There were 21,000 unvested participating shares outstanding as of March 31, 2012.  There were no unvested participating shares outstanding as of March 31, 2011.

As of March 31, 2012 and 2011, there were 36,000 and 32,000 unvested non-participating performance shares outstanding, respectively.  As of March 31, 2012, the unvested performance shares were not dilutive as the underlying performance conditions have not yet been satisfied.  Upon satisfaction of the performance conditions, unvested non-participating performance shares are included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  For the three and nine months ended March 31, 2012 and 2011 there were no antidilutive shares.

 
14

 



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

   
Three Months Ended
 
Nine Months Ended
   
   
March 31,
 
March 31,
   
   
2012
 
2011
   
2012
 
2011
       
Numerator – Basic and Diluted
                         
Net Income ($000)
 
3,925
 
4,331
   
5,640
 
6,609
       
Less:  dividends paid ($000)
 
(1,192
)
(1,142
)
 
(3,569
)
(3,419
)
     
                           
Undistributed earnings ($000)
 
2,733
 
3,189
   
2,071
 
3,190
       
Percentage allocated to common shares (a)
 
99.7
 
100.0
   
99.7
 
100.0
       
                           
Undistributed earnings allocated to common shares ($000)
 
2,725
 
3,189
   
2,065
 
3,190
       
Add:  dividends declared allocated to common shares ($000)
 
1,188
 
1,142
   
3,558
 
3,419
       
                           
Earnings available to common shares ($000)
 
3,913
 
4,331
   
5,623
 
6,609
       
                           
Denominator – Basic (Note 14)
                         
Weighted-average common shares
 
6,788,307
 
6,717,828
   
6,770,438
 
6,701,019
       
Add:  Incremental unvested non-participating shares
 
 
22,324
   
 
7,442
       
Denominator - Diluted
 
6,788,307
 
6,740,152
   
6,770,438
 
6,708,461
       
                           
Earnings per common share ($) (Note 14)
                         
Basic
 
.58
 
.65
   
.83
 
.99
       
Diluted
 
.58
 
.65
   
.83
 
.99
       
                           
                           
(a) Percentage allocated to common shares – weighted average
                         
Common shares outstanding
 
6,788,307
 
6,717,828
   
6,770,438
 
6,701,019
       
Unvested participating shares
 
21,332
 
   
21,332
 
       
Total
 
6,809,639
 
6,717,828
   
6,791,770
 
6,701,019
       
Percentage allocated to common shares
 
99.7
%
100.0
%
 
99.7
%
100.0
%
     

 
15

 


(12)
Share-Based Compensation

We have a shareholder approved incentive compensation plan (the “Plan”) that 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.  In accordance with the provisions of the Plan, the number of shares that may be issued under the Plan and all unvested shares have been adjusted for the two-for-one stock split having a May 1, 2012 distribution date, as further discussed in Note 14 of Notes to Condensed Consolidated Financial Statements.

The number of shares of our common stock that may be issued pursuant to the Plan may not exceed in the aggregate 1,000,000 shares.  As of March 31, 2012, 928,000 shares of common stock were available for issuance under the Plan.  Shares of common stock may be issued from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market. 

Compensation expense for share-based compensation is recorded in operation and maintenance expense in the Condensed Consolidated Statements of 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
 
Nine Months Ended
     
   
March 31,
 
March 31,
     
 
($000)
2012
 
2011
 
2012
 
2011
         
                           
 
Share-based compensation expense
99
 
131
 
613
 
455
         
                           
For the nine months ended March 31, 2012, 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 nine months ended March 31, 2011.

Stock Awards

For the nine months ended March 31, 2012 and 2011, common stock was awarded to virtually all Delta employees and directors having grant date fair values of $337,000 (22,000 shares) and $264,000 (18,000 shares), respectively.  The recipients vested in the awards shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.

 
Performance Shares

For the nine months ended March 31, 2012 and 2011, performance shares were awarded to the Company’s executive officers having grant date fair values of $552,000 (36,000 shares) and $469,000 (32,000 shares), respectively. The performance share awards vest only if the performance objectives of the awards are met, which are based on the Company’s earnings per common share, 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.

 
16

 
If the performance objectives for the 2012 performance shares are met, up to 36,000 unvested shares could be issued to the recipients. The performance objectives for the 2011 performance shares were met and 32,000 unvested shares were issued on August 31, 2011, of which 21,000 shares remain unvested as of March 31, 2012.

For the three and nine months ended March 31, 2012, compensation expense related to the performance shares was $99,000 and $276,000, respectively.  For the three and nine months ended March 31, 2011, compensation expense related to the performance shares was $131,000 and $191,000, 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

In 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 nine months ended March 31, 2012.

(14)           Subsequent Events

On February 17, 2012, the Company’s Board of Directors declared a two-for-one stock split of the Company’s issued and outstanding common stock, par value $1.00 per share.  The stock split was distributed May 1, 2012 to all shareholders of record on April 17, 2012.  As a result of the stock split, all amounts related to shares, share prices and earnings per share have been retroactively restated, where appropriate, throughout this Form 10-Q.



ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
YEAR TO DATE MARCH 31, 2012 OVERVIEW AND FUTURE OUTLOOK

For the nine months ended March 31, 2012, basic and diluted earnings per common share of $.83 decreased $.16 per common share as compared to the $.99 basic and diluted earnings per common share for the nine months ended March 31, 2011.  During the nine months ended March 31, 2012, we experienced warmer weather as compared to the prior year, which resulted in decreased volumes of natural gas sold in both our regulated and non-regulated segments.  Also during the nine months ended March 31, 2012, we accrued $839,000 ($520,000, 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 March 31, 2012 are not necessarily indicative of the results of operations to be expected for the full fiscal year.  Because of the seasonal nature of our sales, we generate a significant proportion of our operating revenues during the heating months (November – April) when our sales volumes increase considerably.  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 is purchased gas, which we are permitted to pass through to our customers.  We control remaining expenses through budgeting, approval and review.

 
17

 
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 the remainder of 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 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.  There were no borrowings outstanding on the bank line of credit as of March 31, 2012 or June 30, 2011.
 
Long-term debt decreased to $56,500,000 at March 31, 2012, compared with $56,751,000 at June 30, 2011.  The decrease resulted from an increase in the current portion of our long-term debt as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures, as further discussed in Note 7 of the Notes to Condensed Consolidated Financial Statements.
 
Cash and cash equivalents were $7,800,000 at March 31, 2012, as compared with $7,340,000 at June 30, 2011.  Changes in cash and cash equivalents are summarized in the following table:
 
   
Nine Months Ended
     
   
March 31,
     
($000)
 
2012
 
2011
         
                   
Provided by operating activities
 
8,400
 
14,930
         
Used in investing activities
 
(4,821
)
(5,513
)
       
Used in financing activities
 
(3,119
)
(3,119
)
       
Increase in cash and cash equivalents
 
460
 
6,298
         
                   

For the nine months ended March 31, 2012, cash provided by operating activities decreased $6,530,000 (44%) due to a $4,148,000 decrease in cash received from customers resulting from a decline in sales volumes due to warmer weather and a $2,995,000 increase in cash paid for natural gas due to the timing of natural gas purchases.  These changes were partially offset by a $1,500,000 decrease in contributions to our defined benefit plan as we made additional elective contributions in the prior year to maintain the funded status of the plan.

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

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 2012 to be approximately $6.5 million.


 
18

 


The following table summarizes our contractual cash obligations for the remainder of fiscal 2012, and fiscal years thereafter:
   
Payments Due by Fiscal Year
($000)
2012
 
2013-2014
 
2015-2016
 
After 2016
 
Total
                             
Interest payments
 
643
   
4,947
   
4,555
   
26,606
   
36,751
Long-term debt (a)
 
   
3,000
   
3,000
   
52,000
   
58,000
Pension contributions
 
   
1,000
   
1,000
   
4,500
   
6,500
Gas purchases
 
205
   
391
   
   
   
596
Total contractual obligations
 
848
   
9,338
   
8,555
   
83,106
   
101,847

(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 bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000.  There were no borrowings outstanding on the bank line of credit as of March 31, 2012.

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

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

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

With our bank line of credit and Series A Notes, we have agreed to certain financial 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 plus the Company’s cumulative earnings after September 30, 2011 adjusted for certain unusual or non-recurring items.

 
19

 
The following table shows the required and actual financial covenants under our Series A Notes as of March 31, 2012:

   
Requirement
 
Actual
         
Tangible net worth
 
no less than $25,800,000
 
$  66,221,461
 
Debt to capitalization ratio
 
no more than 70%
 
46%
 
Fixed charge coverage ratio
 
no less than 1.20x
 
5.49x
 
Dividends paid
 
no more than $21,490,000
 
$    2,381,000
 

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; and
 
·  
sell subsidiaries or transfer assets outside of the normal course of business; and
 
·  
incur secured debt in an amount that exceeds 10% of tangible net worth; and
 
·  
merge with another company;  and
 
·  
change the general nature of our business; and
 
·  
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; and
 
·  
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.


 
20

 


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
 
Nine Months Ended
 
 
March 31,
 
March 31,
 
($000)
2012
 
2011
 
2012
 
2011
 
                 
Operating revenues (a)
26,716
 
35,355
 
62,139
 
69,128
 
Less – Regulated purchased gas (a)
(7,205
)
(10,674
)
(13,491
)
(18,859
)
Less – Non-regulated purchased gas (a)
(7,066
)
(11,347
)
(20,253
)
(21,533
)
Consolidated gross margin
12,445
 
13,334
 
28,395
 
28,736
 

(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 nine months ended March 31, 2012 compared with the same periods in the preceding year. The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Income.

 
21

 



   
2012 compared to 2011
 
   
Three Months
 
Nine Months
     
   
Ended
 
Ended
     
($000)
 
March 31,
 
March 31,
     
               
Increase (decrease) in gross margins
  Regulated segment
Natural gas sales
 
(650
)
(322
)
   
On-system transportation
 
(108
)
(71
)
   
Off-system transportation
 
(217
)
(99
)
   
Other
 
(2
)
37
     
Intersegment elimination (a)
 
270
 
136
     
Total
 
(707
)
(319
)
   
               
   Non-regulated segment
    Natural gas sales
 
(202
)
(623
)
   
Natural gas liquids
 
302
 
753
     
Other
 
(13
)
(16
)
   
Intersegment elimination (a)
 
(270
)
(136
)
   
Total
 
(183
)
(22
)
   
               
Decrease in consolidated gross margins
 
(890
)
(341
)
   
 
Percentage increase (decrease) in volumes
  Regulated segment
             
Natural gas sales
 
(26
)
(23
)
   
On-system transportation
 
(5
)
(4
)
   
Off-system transportation
 
(20
)
(4
)
   
               
  Non-regulated segment
             
Natural gas sales
 
(26
)
6
     
               
 
(a) Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment.

Heating degree days were 78% and 84% of normal thirty year average temperatures for the three and nine months ended March 31, 2012, respectively, as compared with 102% and 105% of normal temperatures in the 2011 periods.  A “heating degree day” results from a day during which the average of the high and low temperature is at least one degree less than 65 degrees Fahrenheit.

For the three months ended March 31, 2012, consolidated gross margins decreased $890,000 (7%) due to decreased regulated and non-regulated gross margins of $707,000 (7%) and $183,000 (6%), respectively. Regulated gross margins decreased due to a 26% decline in 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. Non-regulated gross margins decreased due to a 26% decline in volumes sold due to a decline in our non-regulated customers’ gas requirement, partially offset by a decline in the cost of gas and the sale of natural gas liquids.

For the nine months ended March 31, 2012, consolidated gross margins decreased $341,000 (1%) due to decreased regulated gross margins of $319,000 (1%). Regulated gross margins decreased due to a 23% decline in 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. 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.


 
22

 


Depreciation and Amortization

For the three months ended March 31, 2012, there were no significant changes in depreciation and amortization as compared to the three months ended March 31, 2011.

For the nine months ended March 31, 2012, depreciation and amortization increased $717,000 (19%) due to increased depreciation rates allowed in our 2010 rate case.

Taxes Other Than Income Taxes

For the three and nine months ended March 31, 2012, taxes other than income taxes increased $134,000 (32%) and $351,000 (27%) due to increased property tax expense resulting from both higher assessed values and rates assessed by taxing jurisdictions.

Interest Charges

For the three months ended March 31, 2012, interest charges decreased $264,000 (26%) as a result of refinancing our 5.75% Insured Quarter Notes and 7% Debentures (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements).

For the nine months ended March 31, 2012, interest charges increased $465,000 (15%) primarily due to $832,000 of interest accrued for a tax assessment issued by the Kentucky Department of Revenue (as further discussed in Note 8 of Notes to Condensed Consolidated Financial Statements). The assessment is currently under protest by us with the Kentucky Department of Revenue. The increase was partially offset by decreased interest charges as a result of refinancing our 5.75% Insured Quarter Notes and 7% Debentures (as further discussed in Note 7 of Notes to Condensed Consolidated Financial Statements).

Income Tax Expense

For the three and nine months ended March 31, 2012, income tax expense decreased $267,000 (10%) and $528,000 (13%), respectively, due to a decrease in our net income before income taxes. There were no significant changes to our effective tax rate for the three and nine months ended March 31, 2012.

Basic and Diluted Earnings Per Common Share
 
For the three and nine months ended March 31, 2012, our basic and diluted earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our dividend reinvestment and stock purchase plan as well as those awarded through our incentive compensation plan.

Certain unvested awards under our shareholder approved incentive compensation plan provide the recipients of the awards all the rights of a shareholder of Delta Natural Gas Company, Inc. including a right to dividends declared on common shares. 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 March 31, 2012, there were 21,000 participating unvested shares outstanding.  As of March 31, 2011, there were no participating unvested shares outstanding.

There were 36,000 and 32,000 unvested non-participating performance shares outstanding as of March 31, 2012 and 2011, respectively.  As of March 31, 2012, the unvested performance shares are not dilutive as the underlying performance conditions have not yet been satisfied.  Upon satisfaction of the performance conditions unvested non-participating performance shares are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  For the three and nine months ended March 31, 2012 and 2011 there were no antidilutive shares.


 
23

 
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
We purchase our gas supply through a combination of spot market natural gas purchases and forward natural gas purchases. The price of spot market natural gas is based on the market price at the time of delivery.  The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the natural gas.  Additionally, we inject some of our natural gas purchases into gas storage facilities in the non-heating months and withdraw this natural 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 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 monthly to the London Interbank Offered Rate.  There were no borrowings outstanding on the bank line of credit as of March 31, 2012 and June 30, 2011.

 
ITEM 4. CONTROLS AND PROCEDURES
 
Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 (“Exchange Act”) is recorded, processed, summarized, and reported within the time periods specified by the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of March 31, 2012, and, based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any change in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended March 31, 2012 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 


 
24

 


 

 
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
 
                   None.
 
ITEM 5.                 OTHER INFORMATION
 
    None.
 
ITEM 6.                 EXHIBITS

 
31.1
 
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2
 
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
32.1
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
32.2
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
101.INS
 
XBRL Instance Document
 
101.SCH
 
XBRL Taxonomy Extension Schema
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
 
XBRL Taxonomy Extension Definition Database
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase
 
 
25

 
       
 
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 nine month periods ended March 31, 2012 and 2011;
 
(iii)
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine month periods ended March 31, 2012 and 2011; and
 
(iv)
 
Condensed Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and June 30, 2011
 
(v)
 
Condensed Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the nine month periods ended March 31, 2012 and 2011;
 
(vi)
 
Notes to Condensed Consolidated Financial Statements (Unaudited).
 
 
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part 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.
 


 
26

 


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


DATE:  May 8, 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)


 
27

 

XNAS:DGAS Delta Natural Gas Co Quarterly Report 10-Q Filling

Delta Natural Gas Co XNAS:DGAS Stock - Get Quarterly Report SEC Filing of Delta Natural Gas Co XNAS:DGAS stocks, including company profile, shares outstanding, strategy, business segments, operations, officers, consolidated financial statements, financial notes and ownership information.

XNAS:DGAS Delta Natural Gas Co Quarterly Report 10-Q Filing - 5/8/2012
Name |  Ticker |  Star Rating |  Market Cap |  Stock Type |  Sector |  Industry Star Rating |  Investment Style |  Total Assets |  Category |  Top Holdings |  Top Sectors |  Symbol |  Title Star Rating |  Category |  Total Assets |  Top Holdings |  Top Sectors |  Symbol |  Name Title |  Date |  Author |  Collection |  Interest |  Popularity Topic |  Sector |  Key Indicators |  User Interest |  Market Cap |  Industry Name |  Ticker |  Star Rating |  Market Cap |  Stock Type |  Sector |  Industry Star Rating |  Investment Style |  Total Assets |  Category |  Top Holdings |  Top Sectors |  Symbol / Ticker |  Title Star Rating |  Category |  Total Assets |  Symbol / Ticker |  Name Title |  Date |  Author |  Collection |  Popularity |  Interest Title |  Date |  Company |  Symbol |  Interest |  Popularity Topic |  Sector |  Key Indicators |  User Interest |  Market Cap |  Industry Title |  Date |  Company |  Symbol |  Interest |  Popularity

Previous: XNAS:DGAS Delta Natural Gas Co Quarterly Report 10-Q Filing - 2/7/2012  |  Next: XNAS:DGICA Donegal Group Inc Class A Insider Activity 4 Filing - 1/2/2012