Attached files
file | filename |
---|---|
EX-32.1 - CERTIFICATION OF GLENN JENNINGS - DELTA NATURAL GAS CO INC | exhibit321.htm |
EX-31.1 - CERTIFICATION OF GLENN JENNINGS - DELTA NATURAL GAS CO INC | exhibit311.htm |
EX-31.2 - CERTIFICATION OF JOHN BROWN - DELTA NATURAL GAS CO INC | exhibit312.htm |
EX-32.2 - CERTIFICATION OF JOHN BROWN - DELTA NATURAL GAS CO INC | exhibit322.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, 2010
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, 2010, Delta Natural Gas Company, Inc. had 3,356,646 shares of Common Stock outstanding.
1
DELTA NATURAL GAS COMPANY, INC.
INDEX TO FORM 10-Q
PART I -
|
FINANCIAL INFORMATION
|
3
|
|
ITEM 1.
|
3
|
||
Consolidated Statements of Income (Unaudited) for the three, six and twelve month periods ended December 31, 2010 and 2009
|
3
|
||
Consolidated Balance Sheets (Unaudited) as of December 31, 2010, June 30, 2010 and December 31, 2009
|
4
|
||
Consolidated Statements of Changes in Shareholders’ Equity (Unaudited) for the six and twelve month periods ended December 31, 2010 and 2009
|
6
|
||
Consolidated Statements of Cash Flows (Unaudited) for the six and twelve month periods ended December 31, 2010 and 2009
|
7
|
||
Notes to Consolidated Financial Statements (Unaudited)
|
8
|
||
ITEM 2.
|
14
|
||
ITEM 3.
|
18
|
||
ITEM 4.
|
19
|
||
PART II -
|
OTHER INFORMATION
|
20
|
|
ITEM 1.
|
20
|
||
ITEM 1A.
|
20
|
||
ITEM 2.
|
20
|
||
ITEM 3.
|
20
|
||
ITEM 4.
|
20
|
||
ITEM 5.
|
20
|
||
ITEM 6.
|
20
|
||
21
|
|||
2
DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
|
Three Months Ended
|
Six Months Ended
|
Twelve Months Ended
|
||||||||||||||||
December 31,
|
December 31,
|
December 31,
|
|||||||||||||||||
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
||||||||||||||
OPERATING REVENUES
|
$
|
23,756,304
|
$
|
21,114,433
|
$
|
33,772,782
|
$
|
29,245,383
|
$
|
80,949,467
|
$
|
82,816,149
|
|||||||
OPERATING EXPENSES
|
|||||||||||||||||||
Purchased gas
|
$
|
13,316,740
|
$
|
12,298,555
|
$
|
18,371,084
|
$
|
15,782,724
|
$
|
46,688,688
|
$
|
51,455,406
|
|||||||
Operation and maintenance
|
3,388,416
|
3,261,750
|
6,749,012
|
6,429,754
|
13,775,707
|
13,478,337
|
|||||||||||||
Depreciation and amortization
|
1,284,852
|
982,360
|
2,276,219
|
1,966,853
|
4,250,719
|
3,910,666
|
|||||||||||||
Taxes other than income taxes
|
484,124
|
485,758
|
859,847
|
939,502
|
1,939,788
|
1,935,834
|
|||||||||||||
Total operating expenses
|
$
|
18,474,132
|
$
|
17,028,423
|
$
|
28,256,162
|
$
|
25,118,833
|
$
|
66,654,902
|
$
|
70,780,243
|
|||||||
OPERATING INCOME
|
$
|
5,282,172
|
$
|
4,086,010
|
$
|
5,516,620
|
$
|
4,126,550
|
$
|
14,294,565
|
$
|
12,035,906
|
|||||||
OTHER INCOME AND DEDUCTIONS, NET
|
55,027
|
26,187
|
106,413
|
81,489
|
133,723
|
122,327
|
|||||||||||||
INTEREST CHARGES
|
1,035,964
|
1,065,162
|
2,051,996
|
2,111,022
|
4,110,166
|
4,228,501
|
|||||||||||||
NET INCOME BEFORE INCOME TAXES
|
$
|
4,301,235
|
$
|
3,047,035
|
$
|
3,571,037
|
$
|
2,097,017
|
$
|
10,318,122
|
$
|
7,929,732
|
|||||||
INCOME TAX EXPENSE
|
1,607,211
|
1,134,160
|
1,293,190
|
747,146
|
3,738,329
|
2,871,352
|
|||||||||||||
NET INCOME
|
$
|
2,694,024
|
$
|
1,912,875
|
$
|
2,277,847
|
$
|
1,349,871
|
$
|
6,579,793
|
$
|
5,058,380
|
|||||||
BASIC AND DILUTED EARNINGS PER COMMON SHARE
|
$
|
.80
|
$
|
.58
|
$
|
.68
|
$
|
.41
|
$
|
1.97
|
$
|
1.53
|
|||||||
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING (BASIC AND DILUTED)
|
3,351,890
|
3,324,637
|
3,346,584
|
3,322,169
|
3,338,745
|
3,316,931
|
|||||||||||||
DIVIDENDS DECLARED PER COMMON SHARE
|
$
|
.34
|
$
|
.325
|
$
|
.68
|
$
|
.65
|
$
|
1.33
|
$
|
1.29
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
3
DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
December 31,
|
June 30,
|
December 31,
|
|||||||||
2010
|
2010
|
2009
|
|||||||||
ASSETS
|
|||||||||||
CURRENT ASSETS
|
|||||||||||
Cash and cash equivalents
|
$
|
201,851
|
$
|
4,639,145
|
$
|
138,146
|
|||||
Accounts receivable, less accumulated allowances for doubtful accounts of $113,000, $273,000 and $495,000, respectively
|
15,188,720
|
4,727,631
|
12,653,512
|
||||||||
Gas in storage, at average cost
|
8,551,342
|
6,205,731
|
10,978,247
|
||||||||
Deferred gas costs
|
4,116,310
|
3,296,912
|
1,573,758
|
||||||||
Materials and supplies, at average cost
|
626,409
|
536,416
|
525,775
|
||||||||
Prepayments
|
2,274,114
|
3,640,979
|
5,374,954
|
||||||||
Total current assets
|
$
|
30,958,746
|
$
|
23,046,814
|
$
|
31,244,392
|
|||||
PROPERTY, PLANT AND EQUIPMENT
|
$
|
207,548,871
|
$
|
204,248,520
|
$
|
201,406,820
|
|||||
Less-Accumulated provision for depreciation
|
(75,644,496
|
)
|
(73,792,601
|
)
|
(72,174,115
|
)
|
|||||
Net property, plant and equipment
|
$
|
131,904,375
|
$
|
130,455,919
|
$
|
129,232,705
|
|||||
OTHER ASSETS
|
|||||||||||
Cash surrender value of life insurance
|
$
|
482,159
|
$
|
450,064
|
$
|
440,746
|
|||||
Regulatory assets
|
12,525,373
|
12,115,436
|
11,400,086
|
||||||||
Unamortized debt expense and other
|
2,581,779
|
2,564,187
|
2,667,245
|
||||||||
Total other assets
|
$
|
15,589,311
|
$
|
15,129,687
|
$
|
14,508,077
|
|||||
Total assets
|
$
|
178,452,432
|
$
|
168,632,420
|
$
|
174,985,174
|
|||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
4
DELTA NATURAL GAS COMPANY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
(UNAUDITED)
December 31,
|
June 30,
|
December 31,
|
|||||||||
2010
|
2010
|
2009
|
|||||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|||||||||||
CURRENT LIABILITIES
|
|||||||||||
Accounts payable
|
$
|
7,253,951
|
$
|
6,460,620
|
$
|
6,292,716
|
|||||
Notes payable
|
7,035,666
|
—
|
12,015,728
|
||||||||
Current portion of long-term debt
|
1,200,000
|
1,200,000
|
1,200,000
|
||||||||
Accrued taxes
|
1,552,101
|
1,263,755
|
1,475,910
|
||||||||
Customers’ deposits
|
712,602
|
535,516
|
641,019
|
||||||||
Accrued interest on debt
|
855,281
|
854,109
|
854,190
|
||||||||
Accrued vacation
|
607,825
|
731,869
|
612,652
|
||||||||
Deferred income taxes
|
1,244,036
|
1,059,912
|
270,866
|
||||||||
Other
|
393,442
|
417,694
|
522,249
|
||||||||
Total current liabilities
|
$
|
20,854,904
|
$
|
12,523,475
|
$
|
23,885,330
|
|||||
LONG-TERM DEBT
|
$
|
56,961,006
|
$
|
57,112,000
|
$
|
57,259,000
|
|||||
LONG-TERM LIABILITIES
|
|||||||||||
Deferred income taxes
|
$
|
33,756,505
|
$
|
32,462,067
|
$
|
31,058,562
|
|||||
Investment tax credits
|
100,300
|
113,900
|
129,200
|
||||||||
Regulatory liabilities
|
1,553,084
|
1,664,139
|
1,419,468
|
||||||||
Accrued pension
|
782,759
|
1,218,441
|
450,278
|
||||||||
Asset retirement obligations and other
|
2,983,421
|
2,778,228
|
2,346,190
|
||||||||
Total long-term liabilities
|
$
|
39,176,069
|
$
|
38,236,775
|
$
|
35,403,698
|
|||||
COMMITMENTS AND CONTINGENCIES
(Note 8)
|
|||||||||||
Total liabilities
|
$
|
116,991,979
|
$
|
107,872,250
|
$
|
116,548,028
|
|||||
SHAREHOLDERS’ EQUITY
|
|||||||||||
Common shares ($1.00 par value, 20,000,000 shares
|
|||||||||||
authorized; 3,356,646, 3,334,856 and 3,327,573
|
|||||||||||
shares outstanding at December 31, 2010,
|
|||||||||||
June 30, 2010 and December 31, 2009,
|
|||||||||||
respectively)
|
$
|
3,356,646
|
$
|
3,334,856
|
$
|
3,327,573
|
|||||
Premium on common shares
|
45,559,006
|
44,881,401
|
44,703,270
|
||||||||
Retained earnings
|
12,544,801
|
12,543,913
|
10,406,303
|
||||||||
Total shareholders’ equity
|
$
|
61,460,453
|
$
|
60,760,170
|
$
|
58,437,146
|
|||||
Total liabilities and shareholders’ equity
|
$
|
178,452,432
|
$
|
168,632,420
|
$
|
174,985,174
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
5
DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
Six Months Ended
|
Twelve Months Ended
|
||||||||||||
December 31,
|
December 31,
|
||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||
COMMON SHARES
|
|||||||||||||
Balance, beginning of period
|
$
|
3,334,856
|
$
|
3,318,046
|
$
|
3,327,573
|
$
|
3,307,446
|
|||||
Issuance of common shares
|
12,790
|
9,527
|
20,073
|
20,127
|
|||||||||
Issuance of common shares under the
incentive compensation plan
|
9,000
|
—
|
9,000
|
—
|
|||||||||
Balance, end of period
|
$
|
3,356,646
|
$
|
3,327,573
|
$
|
3,356,646
|
$
|
3,327,573
|
|||||
PREMIUM ON COMMON SHARES
|
|||||||||||||
Balance, beginning of period
|
$
|
44,881,401
|
$
|
44,465,601
|
$
|
44,703,270
|
$
|
44,244,428
|
|||||
Issuance of common shares
|
362,890
|
237,669
|
541,021
|
458,842
|
|||||||||
Issuance of common shares under the
incentive compensation plan
|
254,970
|
—
|
254,970
|
—
|
|||||||||
Share-based compensation
|
59,745
|
—
|
59,745
|
—
|
|||||||||
Balance, end of period
|
$
|
45,559,006
|
$
|
44,703,270
|
$
|
45,559,006
|
$
|
44,703,270
|
|||||
RETAINED EARNINGS
|
|||||||||||||
Balance, beginning of period
|
$
|
12,543,913
|
$
|
11,215,535
|
$
|
10,406,303
|
$
|
9,626,143
|
|||||
Net income
|
2,277,847
|
1,349,871
|
6,579,793
|
5,058,380
|
|||||||||
Dividends on common shares
(See Consolidated Statements of
Income for rates)
|
(2,276,959
|
)
|
(2,159,103
|
)
|
(4,441,295
|
)
|
(4,278,220
|
)
|
|||||
Balance, end of period
|
$
|
12,544,801
|
$
|
10,406,303
|
$
|
12,544,801
|
$
|
10,406,303
|
|||||
SHAREHOLDERS’ EQUITY
|
|||||||||||||
Balance, beginning of period
|
$
|
60,760,170
|
$
|
58,999,182
|
$
|
58,437,146
|
$
|
57,178,017
|
|||||
Net income
|
2,277,847
|
1,349,871
|
6,579,793
|
5,058,380
|
|||||||||
Issuance of common shares
|
375,680
|
247,196
|
561,094
|
478,969
|
|||||||||
Issuance of common shares under the
incentive compensation plan
|
263,970
|
—
|
263,970
|
—
|
|||||||||
Share-based compensation
|
59,745
|
—
|
59,745
|
—
|
|||||||||
Dividends on common shares
|
(2,276,959
|
)
|
(2,159,103
|
)
|
(4,441,295
|
)
|
(4,278,220
|
)
|
|||||
Balance, end of period
|
$
|
61,460,453
|
$
|
58,437,146
|
$
|
61,460,453
|
$
|
58,437,146
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
6
DELTA NATURAL GAS COMPANY, INC.
(UNAUDITED)
Six Months Ended
|
Twelve Months Ended
|
||||||||||||
December 31,
|
December 31,
|
||||||||||||
2010
|
2009
|
2010
|
2009
|
||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|||||||||||||
Net income
|
$
|
2,277,847
|
$
|
1,349,871
|
$
|
6,579,793
|
$
|
5,058,380
|
|||||
Adjustments to reconcile net income to net cash flows from operating activities
|
|||||||||||||
Depreciation and amortization
|
2,523,991
|
2,220,423
|
4,752,061
|
4,417,807
|
|||||||||
Deferred income taxes and investment tax credits
|
1,404,417
|
2,900,085
|
3,520,081
|
3,819,321
|
|||||||||
Other – net
|
(111,874
|
)
|
(264,770
|
)
|
(70,003
|
)
|
(370,812
|
)
|
|||||
Change in cash surrender value of officer’s life insurance
|
(32,095
|
)
|
(28,085
|
)
|
(32,839
|
)
|
(55,806
|
)
|
|||||
Share-based compensation
|
323,715
|
—
|
323,715
|
—
|
|||||||||
Decrease (increase) in assets
|
(12,719,426
|
)
|
(11,895,946
|
)
|
(741,298
|
)
|
21,099,404
|
||||||
Increase (decrease) in liabilities
|
557,601
|
2,558,305
|
686,673
|
(5,699,587
|
)
|
||||||||
Net cash provided by (used in) operating activities
|
$
|
(5,775,824
|
)
|
$
|
(3,160,117
|
)
|
$
|
15,018,183
|
$
|
28,268,707
|
|||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|||||||||||||
Capital expenditures
|
$
|
(4,169,186
|
)
|
$
|
(2,969,045
|
)
|
$
|
(6,508,913
|
)
|
$
|
(7,349,706
|
)
|
|
Proceeds from sale of property, plant and equipment
|
92,426
|
94,001
|
160,373
|
194,560
|
|||||||||
Other
|
431,897
|
(60,000
|
)
|
552,319
|
(60,000
|
)
|
|||||||
Net cash used in investing activities
|
$
|
(3,644,863
|
)
|
$
|
(2,935,044
|
)
|
$
|
(5,796,221
|
)
|
$
|
(7,215,146
|
)
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|||||||||||||
Dividends on common shares
|
$
|
(2,276,959
|
)
|
$
|
(2,159,103
|
)
|
$
|
(4,441,295
|
)
|
$
|
(4,278,220
|
)
|
|
Issuance of common shares
|
375,680
|
247,196
|
561,094
|
478,969
|
|||||||||
Repayment of long-term debt
|
(150,994
|
)
|
(340,000
|
)
|
(297,994
|
)
|
(804,000
|
)
|
|||||
Borrowing on bank line of credit
|
15,895,021
|
21,694,291
|
19,406,287
|
42,286,126
|
|||||||||
Repayment of bank line of credit
|
(8,859,355
|
)
|
(13,331,666
|
)
|
(24,386,349
|
)
|
(58,923,153
|
)
|
|||||
Net cash provided by (used in) financing activities
|
$
|
4,983,393
|
$
|
6,110,718
|
$
|
(9,158,257
|
)
|
$
|
(21,240,278
|
)
|
|||
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS
|
$
|
(4,437,294
|
)
|
$
|
15,557
|
$
|
63,705
|
$
|
(186,717
|
)
|
|||
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
|
4,639,145
|
122,589
|
138,146
|
324,863
|
|||||||||
CASH AND CASH EQUIVALENTS,
END OF PERIOD
|
$
|
201,851
|
$
|
138,146
|
$
|
201,851
|
$
|
138,146
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
7
DELTA NATURAL GAS COMPANY, INC.
(1)
|
Nature of Operations
|
Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 customers. Our distribution and transmission systems are located in central and southeastern Kentucky and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system. We have three wholly-owned subsidiaries. Delta Resources, Inc. (“Delta Resources”) buys gas and resells it to industrial or other large use customers on Delta’s system. Delgasco, Inc. buys gas and resells it to Delta Resources, Inc. and to customers not on Delta’s system. Enpro, Inc. owns and operates production properties and undeveloped acreage.
(2)
|
Basis of Presentation
|
All subsidiaries of Delta are included in the consolidated financial statements. Intercompany balances and transactions have been eliminated. All adjustments necessary for a fair presentation of the unaudited results of operations for the three, six and twelve months ended December 31, 2010 and 2009 are included. All such adjustments are accruals of a normal and recurring nature.
The results of operations for the periods ended December 31, 2010 are not necessarily indicative of the results of operations to be expected for the full fiscal year. Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably. Most construction activity and gas storage injections take place during these warmer months. Twelve month ended financial information is provided for additional information only.
The accompanying consolidated financial statements are unaudited and should be read in conjunction with the financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended June 30, 2010.
(3)
|
Fair Value Measurements
|
Our financial assets and liabilities measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in unamortized debt expense and other on the Consolidated Balance Sheets. Contributions to the trust are presented in other investing activities on the Consolidated 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,
|
December 31,
|
|||||
($000)
|
2010
|
2010
|
2009
|
||||
Trust assets
|
489
|
373
|
378
|
The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value.
Our Debentures and Insured Quarterly Notes, presented as current portion of long-term debt and long-term debt on the Consolidated Balance Sheets, are stated at historical cost. Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate. The Insured Quarterly Notes contain insurance that provides for the continuing payment of principal and interest to the holders in the event we default on the Insured Quarterly Notes. Upon default, the insurer would pay interest and principal to the holders through the maturity of the Insured Quarterly Notes and our obligation transfers to the insurer. Therefore, the insurance is not considered in the determination of the fair value of the Insured Quarterly Notes.
8
December 31,
|
December 31,
|
||||||||
2010
|
2009
|
||||||||
Carrying
|
Fair
|
Carrying
|
Fair
|
||||||
($000)
|
Amount
|
Value
|
Amount
|
Value
|
|||||
7% Debentures
|
19,435
|
18,567
|
19,510
|
18,414
|
|||||
5.75% Insured Quarterly Notes
|
38,726
|
33,657
|
38,949
|
33,268
|
(4)
|
Risk Management and Derivative Instruments
|
To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk. We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. We mitigate price risk by efforts to balance supply and demand. None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase contracts and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.
(5)
|
Unbilled Revenue
|
We bill our customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled.
Unbilled revenues and gas costs include the following:
December 31,
|
June 30,
|
December 31,
|
||||||
(000)
|
2010
|
2010
|
2009
|
|||||
Unbilled revenues ($)
|
7,897
|
1,120
|
6,410
|
|||||
Unbilled gas costs ($)
|
4,489
|
333
|
3,669
|
|||||
Unbilled volumes (Mcf)
|
727
|
53
|
550
|
Unbilled revenues are included in accounts receivable and unbilled gas costs are included in deferred gas costs on the accompanying Consolidated Balance Sheets.
(6)
|
Defined Benefit Retirement Plan
|
Net periodic benefit cost for our trusteed, noncontributory defined benefit pension plan for the periods ended December 31 include the following:
Three Months Ended
|
Six Months Ended
|
Twelve Months Ended
|
|||||||||||
December 31,
|
December 31,
|
December 31,
|
|||||||||||
($000)
|
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
|||||||
Service cost
|
235
|
182
|
469
|
364
|
833
|
702
|
|||||||
Interest cost
|
213
|
214
|
427
|
427
|
854
|
833
|
|||||||
Expected return on plan assets
|
(269
|
)
|
(238
|
)
|
(539
|
)
|
(476
|
)
|
(1,016
|
)
|
(982
|
)
|
|
Amortization of unrecognized net loss
|
125
|
124
|
250
|
248
|
499
|
357
|
|||||||
Amortization of prior service cost
|
(22
|
)
|
(22
|
)
|
(43
|
)
|
(43
|
)
|
(86
|
)
|
(86
|
)
|
|
Net periodic benefit cost
|
282
|
260
|
564
|
520
|
1,084
|
824
|
In August, 2010, we made a $1,000,000 discretionary contribution to our defined benefit plan. No additional contributions are expected for fiscal 2011.
9
(7)
|
Notes Payable
|
The current bank line of credit with Branch Banking and Trust Company is $40,000,000, of which $7,036,000 and $12,016,000 were borrowed having weighted average interest rates of 1.8% and 1.7% as of December 31, 2010 and December 31, 2009, respectively. As of June 30, 2010, all of the bank line of credit was available. Our bank line of credit extends through June 30, 2011. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.5%, and the annual cost of the unused bank line of credit is .125%.
Our bank line of credit agreement and the Indentures relating to all of our publicly held Debentures and Insured Quarterly Notes contain defined “events of default” which, among other things, can make the obligations immediately due and payable. Of these, we consider the following covenants to be most restrictive:
|
·
|
Dividend payments cannot be made unless consolidated shareholders’ equity of the Company exceeds $25,800,000 (thus no retained earnings were restricted); and
|
|
·
|
we may not assume any additional mortgage indebtedness in excess of $5,000,000 without effectively securing all Debentures and Insured Quarterly Notes equally to such additional indebtedness.
|
Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes. We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during any period presented.
(8)
|
Commitments and Contingencies
|
We have entered into individual employment agreements with our five officers. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company. In the event all of these agreements were exercised in the form of lump sum payments, approximately $3.5 million would be paid in addition to continuation of specified benefits for up to five years.
The Kentucky Department of Revenue has assessed Delta Resources $5,193,000, which includes $2,759,000 in taxes, $1,852,000 in penalties and $582,000 in interest for failure to collect and remit a 3% Utility Gross Receipts License tax for the period July, 2005 through July, 2010. The tax is a 3% license tax levied on the gross billing by a utility and is passed through to its customers. Case law in the state of Kentucky and opinions issued by the State Attorney General support that the Utility Gross Receipts License Tax is applicable only to regulated utilities. Since Delta Resources is a natural gas marketer and not a utility regulated by the Kentucky Public Service Commission, we believe Delta Resources is exempt from the tax. We have protested the assessment, but cannot currently predict the outcome of the protest. As of December 31, 2010, we have not accrued any amounts related to the contingency.
In the event we are unsuccessful in defending the position, Delta Resources would have the right to seek reimbursement from its customers for amounts paid to the Department of Revenue relating to this assessment, leaving Delta Resources potentially liable for the interest component of the assessment and any uncollectible amounts. However, we would not be liable for penalties as Kentucky law provides a waiver of penalties when, as we have done, the tax position taken is done so in good faith upon the analysis and recommendation of legal counsel.
Although the Kentucky Department of Revenue has not asserted a claim for the tax periods after July, 2010 or interest accrued subsequent to August, 2010, we have calculated that unasserted liabilities approximate $189,000.
In January, 2011 we filed a lawsuit in the Clark County, Kentucky Circuit Court against Chartis Insurance seeking recovery of an insurance claim filed by us with Chartis Insurance in March, 2009. The claim sought reimbursement of $1,350,000 related to gas that escaped from our underground storage field during 2007. During such time we had a policy with Chartis Insurance to insure the natural gas which is stored in the underground storage field, and we believe the policy was designed to cover such a loss. Chartis Insurance has not reimbursed us for our loss, as the external consultant engaged by Chartis Insurance has challenged our right to recover under the policy. We are unable to predict the outcome of this legal proceeding.
10
We are not a party to any additional material pending legal proceeding.
We have entered into forward purchase agreements beginning in November, 2010 and expiring at various dates through December, 2011. These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements. These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements. The remaining aggregate minimum purchase obligations for these agreements are $88,000 and $45,000 for our fiscal years ended June 30, 2011 and 2012, respectively.
(9)
|
Regulatory Matters
|
The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers. We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services. The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.
On April 23, 2010, we filed a request for increased 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, an increase of 11.5%. The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12.0%.
The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense. A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues will be less dependent on customer usage and should occur more evenly throughout the year. The increased base rates were effective for service rendered on and after October 22, 2010.
In addition to the increased base rates, our pipe replacement program and a change to our gas cost recovery clause were approved. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities. The change to our gas cost recovery clause provides recovery of the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.
(10)
|
Operating Segments
|
Our Company has two segments: (i) a regulated natural gas distribution and transmission segment and (ii) a non-regulated segment that participates in related ventures, consisting of natural gas marketing and production. The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky. Virtually all of the revenue recorded under both segments comes from the distribution or transportation of natural gas. Price risk for the regulated segment is mitigated through our gas cost recovery clause, approved quarterly by the Kentucky Public Service Commission. Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict our demand. In addition, we are exposed to price risk resulting from changes in the market price of gas and uncommitted gas volumes for our non-regulated companies.
11
The segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements which are included in our Annual Report on Form 10-K for the year ended June 30, 2010. Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation services. Operating expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown below for the periods:
Three Months Ended
|
Six Months Ended
|
Twelve Months Ended
|
|||||||||||
December 31,
|
December 31,
|
December 31,
|
|||||||||||
($000)
|
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
|||||||
Operating Revenues
|
|||||||||||||
Regulated
|
|||||||||||||
External customers
|
15,247
|
13,807
|
20,114
|
19,072
|
46,717
|
54,724
|
|||||||
Intersegment
|
1,028
|
866
|
1,695
|
1,419
|
3,717
|
3,113
|
|||||||
Total regulated
|
16,275
|
14,673
|
21,809
|
20,491
|
50,434
|
57,837
|
|||||||
Non-regulated
|
|||||||||||||
External customers
|
8,509
|
7,307
|
13,659
|
10,173
|
34,232
|
28,092
|
|||||||
Eliminations for intersegment
|
(1,028
|
)
|
(866
|
)
|
(1,695
|
)
|
(1,419
|
)
|
(3,717
|
)
|
(3,113
|
)
|
|
Total operating revenues
|
23,756
|
21,114
|
33,773
|
29,245
|
80,949
|
82,816
|
|||||||
Net Income
|
|||||||||||||
Regulated
|
2,132
|
1,552
|
1,572
|
730
|
4,560
|
3,798
|
|||||||
Non-regulated
|
562
|
361
|
706
|
620
|
2,020
|
1,260
|
|||||||
Total net income
|
2,694
|
1,913
|
2,278
|
1,350
|
6,580
|
5,058
|
(11) Earnings per Share
Basic earnings per share represents the net income for a period divided by the weighted average common shares outstanding for the same time period, as shown on the accompanying Consolidated Statements of Income. Certain awards under our shareholder approved incentive compensation plan have all the rights of a shareholder of Delta Natural Gas Company, Inc. which includes a right to dividends declared on common shares. Therefore, any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method. There were no such shares outstanding for any of the periods presented in the accompanying financial statements. As of December 31, 2010, 16,000 unvested performance shares were outstanding and are not dilutive as the underlying performance condition has not yet been satisfied. As a result, our basic earnings per common share and our diluted earnings per common share are the same.
(12)
|
Share-Based Compensation
|
In November, 2009, our shareholders adopted and approved the Delta Natural Gas Company, Inc. Incentive Compensation Plan (the “Plan”), which was previously approved by our Board of Directors in August, 2009. The Plan provides for incentive compensation payable in shares of our common stock. The Plan, which became effective on January 1, 2010, is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining our employees, officers and directors that are eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan.
The number of shares of our common stock which may be issued pursuant to the Plan may not exceed in the aggregate 500,000 shares. Shares of common stock may be available from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market.
12
Compensation expense for share-based compensation is recorded based on the fair value of the awards at the grant date and is amortized over the requisite service period. Fair value is the closing price of the shares at the grant date. The grant date is the date at which our commitment to issue the share-based awards arises which is generally the later of the board approval date or the date the terms of the awards are communicated to the employee or director. We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met.
Three Months Ended
|
Six Months Ended
|
Twelve Months Ended
|
|||||||||||
December 31,
|
December 31,
|
December 31,
|
|||||||||||
($000)
|
2010
|
2009
|
2010
|
2009
|
2010
|
2009
|
|||||||
Share-based compensation expense
|
36
|
—
|
324
|
—
|
324
|
—
|
|||||||
The cumulative compensation expense recognized for share-based compensation exceeds the tax deductions allowed on our income tax returns. An immaterial tax deficiency was recognized in income tax expense for the six and twelve months ended December 31, 2010, which increased our taxes payable.
In August, 2010, 9,000 shares of common stock were awarded to virtually all of Delta’s employees and directors in accordance with the Plan. The awards had a grant date fair value of $264,000 or $29.33 per share. The recipients vested in the award shortly after the award was granted, but during the time between the vesting date and the grant date the shares awarded were not transferable by the holders. Once the shares were vested, the shares were immediately transferable.
In August, 2010, performance shares were awarded to the Company's executive officers in accordance with the Plan. The performance share awards will vest only if the performance objective of the awards is met, which is based on the Company's fiscal 2011 audited earnings per share, before any cash bonuses or stock awards. Subject to further limitations described in the Incentive Compensation Plan and the Notice of Performance Shares Award, all Performance Shares paid shall be in the form of unvested shares, which contain a service condition where a recipient of the award shall vest in one-third increments each year beginning on August 31, 2011, and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period. The maximum which would be issued under the performance awards is 16,000 shares, which have a grant date fair value of $469,000 ($29.33 per share). Compensation expense of $36,000, $60,000 and $60,000 has been recognized for the awards for the three, six and twelve months ended December 31, 2010, 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 award based on the probable outcome of meeting the performance objective. The probable outcome of the performance objective is evaluated at each balance sheet date and this evaluation can result in upward or downward revisions of amounts previously recognized until the actual outcome of the performance objective is known for the June 30, 2011 balance sheet date.
To the extent the performance condition is satisfied during the first year of the vesting period, the holder of performance shares will have both dividend participation rights and voting rights during the remaining term of the awards. The holder becomes vested as a result of certain events such as death or disability of the holder. Subject to the satisfaction of the performance condition, the weighted average expected remaining vesting period at December 31, 2010 is 2.7 years. Holders of performance shares may not sell, transfer, or pledge their shares until the shares vest.
13
The following summarizes the activity for performance shares:
Performance shares
|
||||||||||
Number of shares
|
Weighted-average grant date fair value
|
|||||||||
Unvested awards at June 30, 2010
|
—
|
$ —
|
||||||||
Granted
|
16,000
|
(1)
|
$ 29.33
|
|||||||
Vested
|
—
|
—
|
||||||||
Forfeited
|
—
|
—
|
||||||||
Unvested awards at December 31, 2010
|
16,000
|
$ 29.33
|
||||||||
(1)
|
Represents the maximum number of shares which could be issued based on achieving the performance criteria.
|
YEAR TO DATE DECEMBER 31, 2010 OVERVIEW AND FUTURE OUTLOOK
For the six months ended December 31, 2010, consolidated net income per share of $.68 increased $.27 per share as compared to the $.41 net income per share for the six months ended December 31, 2009. The increase is attributable to increases in both our regulated segment’s and non-regulated segment's gross margins.
The results for the year ended June 30, 2011 should be significantly impacted by the new base rates approved by the Kentucky Public Service Commission (as further discussed in Note 9 of the Notes to Consolidated Financial Statements). The new base rates were effective October 22, 2010, and are designed to annually generate an additional $3,513,000 of revenues. Our 2011 results will also be 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. The regulated segment’s largest expense is gas supply, which we are permitted to pass through to our customers. We control remaining expenses through budgeting, approval and review.
Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other customers and the market prices of natural gas, all of which are out of our control. We anticipate our non-regulated segment to continue to contribute to our consolidated net income for the remainder of fiscal 2011.
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 ability to maintain liquidity depends on our bank line of credit, shown as notes payable on the accompanying Consolidated Balance Sheets. Notes payable were $7,036,000 and $12,016,000 at December 31, 2010 and December 31, 2009, respectively. There were no borrowings outstanding on the bank line of credit as of June 30, 2010. Notes payable decreased to $7,036,000 at December 31, 2010 compared to $12,016,000 at December 31, 2009 due to cash provided by operations exceeding cash used in capital expenditures. We made capital expenditures of $4,169,000 and $6,509,000 during the six and twelve months ended December 31, 2010, respectively. In periods when cash provided by operating activities is not sufficient to meet our capital requirements, we finance the balance on an interim basis through our bank line of credit. When we have no borrowings outstanding on our bank line of credit, excess cash is invested in overnight repurchase agreements. Through BB&T, we purchase U. S. Treasury or Federal Agency Securities with a contractual agreement to sell back the securities the next day.
14
Long-term debt decreased to $56,961,000 at December 31, 2010, compared with $57,112,000 at June 30, 2010 and $57,259,000 at December 31, 2009. The decreases resulted from the limited redemptions made by certain holders or their beneficiaries as allowed by the Debentures and Insured Quarterly Notes.
Cash and cash equivalents were $202,000 at December 31, 2010, as compared with $4,639,000 at June 30, 2010 and $138,000 at December 31, 2009. The changes in cash and cash equivalents are summarized in the following table:
Six Months Ended
|
Twelve Months Ended
|
||||||||
December 31,
|
December 31,
|
||||||||
($000)
|
2010
|
2009
|
2010
|
2009
|
|||||
Provided by (used in) operating activities
|
(5,776
|
)
|
(3,160
|
)
|
15,018
|
28,268
|
|||
Used in investing activities
|
(3,645
|
)
|
(2,935
|
)
|
(5,796
|
)
|
(7,215
|
)
|
|
Provided by (used in) financing activities
|
4,984
|
6,111
|
(9,158
|
)
|
(21,240
|
)
|
|||
Increase (decrease) in cash and cash equivalents
|
(4,437
|
)
|
16
|
64
|
(187
|
)
|
|||
For the six months ended December 31, 2010, cash used in operating activities increased $2,616,000 (83%). Cash paid for natural gas increased $5,249,000 due to an increase in quantities of natural gas purchased. The increase was partially offset by a $2,732,000 increase in cash received from customers due to increased volumes sold and increased regulated sales prices.
For the twelve months ended December 31, 2010, cash provided by operating activities decreased $13,250,000 (47%). Cash paid for natural gas increased $7,528,000 due to an increase in quantities of natural gas purchased and cash received from customers decreased $10,747,000 due to the timing of collections on accounts receivable. The decrease in cash provided by operating activities was partially offset by a $3,517,000 decrease in cash paid for income taxes due to a method change that reduced our capitalization of expenses for income tax purposes and a $1,500,000 decrease in cash contributed to our defined benefit plan, as we made additional discretionary contributions during the twelve months ended December 31, 2009.
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, 2010, cash provided by financing activities decreased $1,127,000 (18%) due to decreased net borrowings on the bank line of credit.
For the twelve months ended December 31, 2010, cash used in financing activities decreased $12,082,000 (57%) due to decreased net repayments on the bank line of credit.
Cash Requirements
Our capital expenditures result in a continued need for capital. These capital expenditures are primarily made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2011 to be approximately $7.7 million.
Sufficiency of Future Cash Flows
We expect that cash provided by operations, coupled with short and long-term borrowings, will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future.
To the extent that internally generated cash is not sufficient to satisfy seasonal operating and capital expenditure requirements and to pay dividends, we will rely on our bank line of credit. Our current available line of credit with Branch Banking and Trust Company, shown as notes payable on the accompanying Consolidated Balance Sheets, is $40,000,000, of which $7,036,000 was borrowed at December 31, 2010. The current bank line of credit extends through June 30, 2011.
15
Our ability to borrow on our bank line of credit is dependent on our compliance with covenants. Our bank line of credit agreement and the Indentures relating to all of our publicly held Debentures and Insured Quarterly Notes contain defined "events of default" which, among other things, can make the obligations immediately due and payable. Of these, we consider the following covenants to be most restrictive:
·
|
Dividend payments cannot be made unless consolidated shareholders' equity of the Company exceeds $25,800,000 (thus no retained earnings were restricted); and
|
·
|
We may not assume any additional mortgage indebtedness in excess of $5,000,000 without effectively securing all Debentures and Insured Quarterly Notes equally to such additional indebtedness.
|
Furthermore, a default on the performance on any single obligation incurred in connection with our borrowings simultaneously creates an event of default with the bank line of credit and all of the Debentures and Insured Quarterly Notes. We were not in default on any of our bank line of credit, Debentures or Insured Quarterly Notes during any period presented. We are not aware of any events that would cause us to be in default in fiscal 2011.
Our ability to sustain acceptable earnings levels, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated sales and transportation prices we charge our customers. The Kentucky Public Service Commission sets these prices and we monitor our need to file rate requests with the Kentucky Public Service Commission for general rate increase for our regulated services.
On April 23, 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, an increase of 11.5%. The rate case utilized a test year of the twelve months ended December 31, 2009 and requested a return on common equity of 12.0%.
The Kentucky Public Service Commission approved increased base rates in this general rate case to provide an additional $3,513,000 in annual revenues based upon a 10.4% allowed return on common equity and a $1,770,000 increase in annual depreciation expense. A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues will be less dependent on customer usage and should occur more evenly throughout the year. The increased rates were effective for service rendered on and after October 22, 2010.
In addition to the increased base rates, our pipe replacement program and a change to our gas cost recovery clause were approved. Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities. The change to our gas cost recovery clause provides recovery of the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.
RESULTS OF OPERATIONS
Gross Margins
Throughout the following Results of Operations we refer to “gross margin” . Our operating revenues, with the exception of transportation revenues, have offsetting gas expenses. Gross margin, therefore, refers to operating revenues less purchased gas expense, which can be derived directly from our Consolidated Statements of Income. Operating Income as presented in the Consolidated Statements of Income is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (“GAAP”). “Gross margin” is a “non-GAAP financial measure”, as defined in accordance with SEC rules. We view gross margin as an important performance measure of the core profitability of our business segments. The measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses.
16
Natural gas prices are determined by an unregulated national market. Therefore, the price that we pay for natural gas fluctuates with national supply and demand. See Item 3 for the impact of forward contracts.
In the following table we set forth variations in our gross margins for the three, six and twelve months ended December 31, 2010 compared with the same periods in the preceding year. The variation amounts and percentages presented in the following tables for regulated and non-regulated gross margins include intersegment transactions. These intersegment revenues and expenses are eliminated in the Consolidated Statements of Income.
2010 compared to 2009
|
|||||||
Three Months
|
Six Months
|
Twelve Months
|
|||||
Ended
|
Ended
|
Ended
|
|||||
($000)
|
December 31
|
December 31
|
December 31
|
||||
Increase (decrease) in gross margins:
Regulated segment
|
|||||||
Gas sales
|
968
|
973
|
1,049
|
||||
On-system transportation
|
131
|
208
|
493
|
||||
Off-system transportation
|
50
|
113
|
348
|
||||
Other
|
—
|
(8
|
)
|
(17
|
)
|
||
Intersegment elimination (a)
|
(162
|
)
|
(276
|
)
|
(604
|
)
|
|
Total
|
987
|
1,010
|
1,269
|
||||
Non-regulated segment
Gas sales
|
451
|
634
|
935
|
||||
Other
|
24
|
20
|
91
|
||||
Intersegment elimination (a)
|
162
|
276
|
604
|
||||
Total
|
637
|
930
|
1,630
|
||||
Increase in consolidated gross margins
|
1,624
|
1,940
|
2,899
|
||||
Percentage increase in volumes:
|
|||||||
Regulated segment
|
|||||||
Gas sales
|
15
|
12
|
9
|
||||
On-system transportation
|
5
|
10
|
15
|
||||
Off-system transportation
|
2
|
5
|
6
|
||||
Non-regulated segment
|
|||||||
Gas sales
|
28
|
43
|
47
|
(a)
|
Intersegment eliminations represent the transportation fee charged by the regulated segment to the non-regulated segment.
|
Heating degree days were 111%, 109% and 107% of normal thirty year average temperatures for the three, six and twelve months ended December 31, 2010, respectively, as compared with 104%, 103% and 100% of normal temperatures in the comparable 2009 periods, respectively. 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, 2010, consolidated gross margins increased $1,624,000 (18%) due to increased regulated and non-regulated gross margins of $987,000 (14%) and $637,000 (41%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010, and due to a 15% increase in volumes sold. The increase in volumes sold is attributable to the colder than normal weather. The increase was partially offset by a decrease in rates billed through our weather normalization tariff as a result of the colder than normal weather. Non-regulated gross margins increased due to a 28% increase in volumes sold and a 13% decline in the cost of gas. Non-regulated volumes sold increased due to an increase in our non-regulated customers’ gas requirements.
For the six months ended December 31, 2010, consolidated gross margins increased $1,940,000 (14%) due to increased regulated and non-regulated gross margins of $1,010,000 (9%) and $930,000 (37%), respectively. Regulated gross margins increased due to increased base rates which became effective October 22, 2010, a 12% increase in volumes sold and a 6% increase in volumes transported. The increase was partially offset by a decrease in rates billed through our weather normalization tariff as a result of the colder than normal weather. The increase in volumes sold and transported is attributable to the colder than normal weather. Non-regulated gross margins increased due to a 43% increase in volumes sold and an 8% decline in the cost of gas. During the six months ended December 31, 2009, we experienced a reduction in our non-regulated customers’ gas requirements, which we attributed to the economic conditions during that period of time.
17
For the twelve months ended December 31, 2010, consolidated gross margins increased $2,899,000 (9%) due to increased non-regulated and regulated gross margins of $1,630,000 (25%) and $1,269,000 (5%), respectively. Non-regulated gross margins increased due to a 47% increase in volumes sold and an 18% decline in the cost of gas. During the twelve months ended December 31, 2009, we experienced a reduction in our non-regulated customers’ gas requirements, which we attributed to the economic conditions during that period of time. Regulated gross margins increased due to increased base rates which became effective October 22, 2010, a 9% increase in volumes sold and a 9% increase in volumes transported. The increase in volumes sold and transported is attributable to colder than normal weather. The increase was partially offset by a decrease in rates billed through our weather normalization tariff as a result of the colder than normal weather.
Depreciation and amortization
For the three and six months ended December 31, 2010, depreciation and amortization increased $303,000 (31%) and $309,000 (16%), respectively, due to increased depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case.
Income Tax Expense
For the three, six and twelve months ended December 31, 2010, income tax expense increased $473,000 (42%), $546,000 (73%) and $867,000 (30%), respectively. These increases are a result of increases in net income before income taxes.
Basic and Diluted Earnings Per Common Share
For the three, six and twelve months ended December 31, 2010, our basic earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our Dividend Reinvestment and Stock Purchase Plan as well as those shares awarded through our incentive compensation plan.
Certain awards under our shareholder approved incentive compensation plan have all the rights of a shareholder of Delta Natural Gas Company, Inc. which includes a right to dividends declared on common shares. Therefore, any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method. There were no such shares outstanding for any of the periods presented in the accompanying financial statements. As of December 31, 2010, 16,000 unvested performance shares were outstanding and are not dilutive as the underlying performance conditions have not yet been satisfied. As a result, our basic earnings per common share and our diluted earnings per common share are the same.
We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. The price of spot market gas is based on the market price at the time of delivery. The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the gas. Additionally, we inject some of our gas purchases into gas storage facilities in the non-heating months and withdraw this gas from storage for delivery to customers during the heating season. For our regulated business, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through our gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.
18
Price risk for the non-regulated business is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand. In addition, we are exposed to price risk resulting from changes in the market price of gas on uncommitted gas volumes of our non-regulated companies.
None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.
When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates. The current bank line of credit with Branch Banking and Trust Company is $40,000,000, of which $7,036,000 and $12,016,000 were borrowed having a weighted average interest rate of 1.8% and 1.7% as of December 31, 2010 and December 31, 2009, respectively. As of June 30, 2010, all of the bank line of credit was available. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.5%. Based on the amounts of our outstanding bank line of credit on December 31, 2010 and December 31, 2009, a one percent (one hundred basis point) increase in our average interest rate would decrease our annual pre-tax net income by $70,000 and $120,000, respectively.
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, 2010, 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, 2010 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
19
ITEM 1.
|
|
In January, 2011 we filed a lawsuit in the Clark County, Kentucky Circuit Court against Chartis Insurance seeking recovery of an insurance claim filed by us with Chartis Insurance in March, 2009. The claim sought reimbursement of $1,350,000 related to gas that escaped from our underground storage field during 2007. During such time we had a policy with Chartis Insurance to insure the natural gas which is stored in the underground storage field, and we believe the policy was designed to cover such a loss. Chartis Insurance has not reimbursed us for our loss, as the external consultant engaged by Chartis Insurance has challenged our right to recover under the policy.
|
ITEM 2.
|
|
None.
|
|
ITEM 3.
|
|
None.
|
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.
|
20
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 3, 2011
|
/s/Glenn R. Jennings
|
|
Glenn R. Jennings
Chairman of the Board, President and Chief Executive Officer
(Duly Authorized Officer)
|
||
/s/John B. Brown
|
||
John B. Brown
Chief Financial Officer, Treasurer and Secretary
(Principal Financial Officer)
|
21