Attached files

file filename
EX-21 - SUBSIDIARIES OF THE REGISTRANT - DELTA NATURAL GAS CO INCexhibit21.htm
EX-12 - RATIO OF EARNINGS TO FIXED CHARGES - DELTA NATURAL GAS CO INCexhibit12.htm
EX-32.2 - CERTIFICATION OF CFO PURSUANT TO SOX - DELTA NATURAL GAS CO INCexhibit322.htm
EX-31.2 - CERTIFICATION OF CFO - DELTA NATURAL GAS CO INCexhibit312.htm
EX-32.1 - CERTIFICATION OF CEO PURSUANT TO SOX - DELTA NATURAL GAS CO INCexhibit321.htm
EX-31.1 - CERTIFICATION OF CEO - DELTA NATURAL GAS CO INCexhibit311.htm
EX-23 - CONSENT OF INDEPENDENT REGISTERED ACCTG FIRM - DELTA NATURAL GAS CO INCexhibit23.htm





 


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC  20549
______________
FORM 10-K
______________
(Mark one)
x           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended June 30, 2011

¨           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)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock $1 Par Value
NASDAQ
Securities registered pursuant to Section 12(g) of the Act:
None

 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £  No x
 
 Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act.  Yes  £  No x

 
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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   £

 
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 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

 
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recent completed second fiscal quarter.  $105,331,551.
 
 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.  As of August 15, 2011, Delta Natural Gas Company, Inc. had outstanding 3,366,292 shares of common stock $1 par value.

 
DOCUMENTS INCORPORATED BY REFERENCE
 
 
 The Registrant’s definitive proxy statement, to be filed with the Commission not later than 120 days after June 30, 2011, is incorporated by reference in Part III of this Report.


 
 

 



TABLE OF CONTENTS
   
Page Number
       
 
Business
2
       
 
Risk Factors
9
       
 
Unresolved Staff Comments
11
       
 
Properties
12
       
 
Legal Proceedings
12
       
 
(Removed and Reserved)
12
       
     
 
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of  Equity Securities
13
       
 
Selected Financial Data
15
       
 
Management’s Discussion and Analysis of  Financial Condition and Results of Operations
16
       
 
Quantitative and Qualitative Disclosures About Market Risk
25
       
 
Financial Statements and Supplementary Data
26
       
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
26
       
 
Controls and Procedures
26
       
 
Other Information
29
       
     
 
Directors, Executive Officers and Corporate Governance
29
       
 
Executive Compensation
29
       
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
30
       
 
Certain Relationships and Related Transactions, and Director Independence
30
       
 
Principal Accountant Fees and Services
30
       
     
 
Exhibits and Financial Statement Schedules
31
       
   
34


 
1

 
PART I

Item 1.     Business

General

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

We seek to provide dependable, high-quality service to our customers while steadily enhancing value for our shareholders. Our efforts have been focused on developing a balance of regulated and non-regulated businesses to contribute to our earnings by profitably selling, transporting and producing natural gas in our service territory.

We strive to achieve operational excellence through economical, reliable service with an emphasis on responsiveness to customers. We continue to invest in facilities for the distribution, transmission and storage of natural gas. We believe that our responsiveness to customers and the dependability of the service we provide afford us additional opportunities for growth. While we seek those opportunities, our strategy will continue a conservative approach that seeks to minimize our exposure to market risk arising from fluctuations in the prices of gas.

We operate through two segments, a regulated segment and a non-regulated segment.

Our executive offices are located at 3617 Lexington Road, Winchester, Kentucky 40391. Our telephone number is (859) 744-6171. Our website is www.deltagas.com.


Regulated Operations

Distribution and Transportation

Through our regulated segment, we distribute natural gas to our retail customers in 23 predominantly rural counties. In addition, our regulated segment transports gas to industrial customers on our system who purchase gas in the open market. Our regulated segment also transports gas on behalf of local producers and other customers not on our distribution system.

The economy of our service area is based principally on coal mining, farming and light industry. The communities we serve typically contain populations of less than 20,000. Our three largest service areas are Nicholasville, Corbin and Berea, Kentucky. In Nicholasville we serve approximately 8,000 customers, in Corbin we serve approximately 6,000 customers and in Berea we serve approximately 4,000 customers. Some of the communities we serve continue to expand, resulting in growth opportunities for us. Industrial parks have been developed in our service areas, which could result in additional growth in industrial customers as well.

The Kentucky Public Service Commission exercises regulatory authority over our regulated natural gas distribution and transportation services. The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers.  The impact of this regulation is further discussed in Note 14 of Notes to Consolidated Financial Statements in Item 8., Financial Statements and Supplemental Data.

Factors that affect our regulated revenues include the rates we charge our customers, economic conditions in our service areas, competition, our supply cost for the natural gas we purchase for resale and weather.  Our current rate design lessens the impact natural gas prices and weather have on our regulated revenues as our rates include a weather normalization provision in our tariff, which reduces fluctuations in our earnings due to variations in weather, and a gas cost recovery clause, which mitigates market risk arising from fluctuations in the price of gas.
 
 
2

 
Through our gas cost recovery clause the Kentucky Public Service Commission permits us to pass through to our regulated customers changes in the price we must pay for our gas supply.  However, increases in our rates may cause our customers to conserve or to use alternative energy sources.

Our regulated sales are seasonal and temperature-sensitive, since the majority of the gas we sell is used for heating.  During 2011, 77% of the regulated volumes were sold during the heating season (December through April).  Variations in the average temperature during the winter impact our volumes sold.  The Kentucky Public Service Commission, through a weather normalization provision in our tariff, permits us to adjust the rates we charge our customers in response to winter weather that is warmer or colder than normal temperatures.

We compete with alternate sources of energy for our regulated distribution customers. These alternate sources include electricity, coal, oil, propane and wood.

Our larger regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities.  Customers for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers.  Customers may undertake such a by-pass in order to achieve lower prices for their gas and/or transportation services.  Our larger customers who are in close proximity to alternative supplies would be most likely to consider taking this action. Additionally, some of our industrial customers are able to switch to alternative sources of energy. These are competitive concerns that we continue to address by utilizing our non-regulated segment to offer these customers gas supply at competitive market-based rates.

Some natural gas producers in our service area can access pipeline delivery systems other than ours, which generates competition for our transportation services. We continue our efforts to purchase or transport natural gas that is produced in reasonable proximity to our transportation facilities through our regulated segment.

As an active participant in many areas of the natural gas industry, we plan to continue efforts to expand our gas transmission and distribution system and customer base. We continue to consider acquisitions of other gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas.

Gas Supply

We maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of gas for our customers.  We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2011, we purchased approximately 99% of our natural gas from interstate sources.

Interstate Gas Supply

Our regulated segment acquires its interstate gas supply from gas marketers. We currently have commodity requirements agreements with Atmos Energy Marketing (“Atmos”) for our Columbia Gas Transmission Corporation (“Columbia Gas”), Columbia Gulf Transmission Corporation (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”) and Texas Eastern Transmission Corporation (“Texas Eastern”) supplied areas. Under these commodity requirements agreements, Atmos is obligated to supply the volumes consumed by our regulated customers in defined sections of our service areas. The gas we purchase under these agreements is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  The index-based market prices are determined based on the prices published on the first of the month in Platts’ Inside FERC’s Gas Market Report in the indices that relate to the pipelines through which the gas will be transported, plus or minus an agreed-to fixed price adjustment per million British Thermal Units of gas purchased.  Consequently, the price we pay for interstate gas is based on current market prices.

Our agreements with Atmos for the Columbia Gas, Columbia Gulf, Tennessee and Texas Eastern supplied service areas continue year to year unless cancelled by either party by written notice at least sixty days prior to the annual anniversary date (April 30) of the agreement. In our fiscal year ended June 30, 2011, approximately 41% of our regulated gas supply was purchased under our agreements with Atmos.

 
3

 
Our regulated segment purchases gas from M & B Gas Services, Inc. (“M & B”) for injection into our underground natural gas storage field and to supply a portion of our system. We are not obligated to purchase any minimum quantities from M & B nor to purchase gas from M & B for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  Our agreement with M & B may be terminated upon 30 days prior written notice by either party.  In our fiscal year ended June 30, 2011, approximately 58% of our regulated gas supply was purchased under our agreement with M & B.

We also purchase interstate natural gas from other gas marketers as needed at either current market prices, determined by industry publications, or at forward market prices.

Transportation of Interstate Gas Supply

Our interstate natural gas supply is transported to us from market hubs, production fields and storage fields by Tennessee, Columbia Gas, Columbia Gulf and Texas Eastern.

Our agreements with Tennessee extend through 2013 and thereafter automatically renew for subsequent five-year terms unless Delta notifies Tennessee of its intent not to renew the agreements at least one year prior to the expiration of any renewal terms.  Subject to the terms of Tennessee’s Federal Energy Regulatory Commission Gas Tariff, Tennessee is obligated under these agreements to transport up to 19,600 thousand cubic feet (“Mcf”) per day for us.  During fiscal 2011, Tennessee transported a total of 946,000 Mcf for us under these contracts.  Annually, approximately 25% of our regulated supply requirements flow through Tennessee to our points of receipt under our transportation agreements with Tennessee.  We have gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee’s storage fields and we reserve the right to withdraw daily gas volumes up to certain specified fixed quantities.  These gas storage agreements renew on the same schedule as our transportation agreements with Tennessee.

Under our agreements with Columbia Gas and Columbia Gulf, Columbia Gas is obligated to transport, including utilization of our defined storage space as required, up to 12,600 Mcf per day for us, and Columbia Gulf is obligated to transport up to a total of 4,300 Mcf per day for us.  During fiscal 2011, Columbia Gas and Columbia Gulf transported for us a total of 565,000 Mcf, or approximately 15% of our regulated supply requirements, under all of our agreements with them.  Our transportation agreements with Columbia Gas and Columbia Gulf extend through 2015.  After 2015, our agreement with Columbia Gas continues on a year-to-year basis unless terminated by one of the parties.  After 2015, our agreement with Columbia Gulf may be extended by mutual agreement.

Columbia Gulf also transported additional volumes under agreements it has with M & B to a point of interconnection between Columbia Gulf and us where we purchase the gas to inject into our storage field.  The amounts transported and sold to us under the agreement between Columbia Gulf and M & B for fiscal 2011 constituted approximately 58% of our regulated gas supply.  We are not a party to any of these separate transportation agreements on Columbia Gulf.

We have no direct agreement with Texas Eastern. However, Atmos has an arrangement with Texas Eastern to transport the gas to us that we purchase from Texas Eastern to supply our customers’ requirements in specific geographic areas. Consequently, Texas Eastern transports a small percentage of our interstate gas supply.  In our fiscal year ended June 30, 2011, Texas Eastern transported approximately 13,000 Mcf of natural gas to our system, which constituted less than 1% of our gas supply.

Kentucky Gas Supply

We have an agreement with Vinland Energy Operations LLC ("Vinland") to purchase natural gas on a year-to-year basis unless terminated by one of the parties.  We purchased 43,000 Mcf from Vinland during fiscal 2011.  The price for the gas we purchase from Vinland is based on the index price of spot gas delivered to Columbia Gas in the relevant region as reported in Platt’s Inside FERC’s Gas Market Report, plus a fixed adjustment per million British Thermal Units of gas purchased.  Vinland delivers this gas to our customers directly from its own pipelines.

 
4

 

Gas in Storage

We own and operate an underground natural gas storage field that we use to store a significant portion of our winter gas supply needs.  This storage capability permits us to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months.

Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services.  The Kentucky Public Service Commission's regulation of our business includes setting the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services.  The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.

In April, 2010, we filed a request for increased base rates with the Kentucky Public Service Commission.  This general rate case, Case No. 2010-00116, requested an annual revenue increase of approximately $5,315,000, an increase of 11.5%, as further discussed in Note 14 of the Notes to Consolidated Financial Statements.  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 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 rates, our pipe replacement program was approved in our 2010 rate case.  Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities.  The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.  In February, 2011, the Kentucky Public Service Commission approved our initial pipe replacement filing, effective May, 2011, which will provide us $139,000 in additional annual revenues.

The Kentucky Public Service Commission allows us a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs.  Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission.  Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred.  In our general rate case, the Kentucky Public Service Commission approved a change to our gas cost recovery clause, effective January, 2011, allowing us to recover the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.

Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which allows us to adjust our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles.  These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts.

The Kentucky Public Service Commission also allows us a conservation and efficiency program for our residential customers.  The program provides for us to perform energy audits, promote conservation awareness and provide rebates on the purchase of certain high-efficiency appliances.  The program helps to align our interests with our residential customer's interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation.  Our rates are adjusted annually to recover the costs incurred under these programs, including the reimbursement of margins on lost sales and the incentives provided to us.

 
5

 
In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds.  No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise.  We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, the areas served do not have governmental organizations authorized to grant franchises or the city governments do not require a franchise.  We attempt to acquire or reacquire franchises whenever feasible.  Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city.  To date, the absence of a franchise has caused no adverse effect on our operations.


Non-Regulated Operations

Marketing and Production

We operate our non-regulated segment through three wholly-owned subsidiaries.  Two of these subsidiaries, Delta Resources and Delgasco, purchase natural gas in the open market, including natural gas from Kentucky producers.  We resell this gas to industrial customers on our distribution system and to others not on our system.  Our third subsidiary, Enpro, produces natural gas that is sold to Delgasco for resale in the open market.

Factors that affect our non-regulated revenues include rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition.

Our larger non-regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Additionally, some of our industrial customers are able to switch economically to alternative sources of energy.  We continue to address these competitive concerns by offering these customers gas supply at competitive market based rates.

We anticipate continuing our non-regulated gas production and marketing activities and intend to pursue and increase these activities wherever practicable.

In our non-regulated segment two customers each provided more than 5% of our operating revenues.  Seminole Energy provided $11,461,000, $6,722,000 and $4,285,000 of non-regulated revenues during 2011, 2010 and 2009, respectively.  Atmos provided $8,067,000 and $5,097,000 of non-regulated revenues during 2011 and 2010, respectively.  There is no assurance that revenues from these customers will continue at these levels.

Gas Supply

           Our non-regulated segment purchases gas from M & B.  Our underlying agreement with M & B does not obligate us to purchase any minimum quantities from M & B nor to purchase gas from M & B for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices.  Our agreement with M & B may be terminated upon 30 days prior written notice by either party. Any purchase agreements for unregulated sales activities may have longer terms or multiple month purchase commitments. In our fiscal year ended June 30, 2011, approximately 78% of our non-regulated gas supply was purchased under our agreement with M & B.

Additionally, our non-regulated segment purchases natural gas from Atmos as needed. This spot gas purchasing arrangement is pursuant to an agreement with Atmos containing an “evergreen” clause which permits either party to terminate the agreement by providing not less than sixty days written notice. Our purchases from Atmos under this spot purchase agreement are generally month-to-month. However, we have the option of forward-pricing gas for one or more months. The price of gas under this agreement is based on current market prices. In our fiscal year ended June 30, 2011, approximately 20% of our non-regulated gas supply was purchased under our agreement with Atmos.

We also purchase interstate natural gas from other gas marketers and Kentucky producers as needed at either current market prices, determined by industry publications, or at forward market prices.

 
6

 
Capital Expenditures

Capital expenditures during 2011 were $8.1 million and for 2012 are estimated to be $6.5 million.  Our expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities.  Expenditures for 2011 included costs for a processing facility to extract heavy liquids from portions of our natural gas supply.

Financing

Our capital expenditures and operating cash requirements are met through the use of internally generated funds and a short-term bank line of credit.  The current available line of credit is $40 million, all of which was available at June 30, 2011.

The current bank line of credit extends through June 30, 2013 and will be utilized to meet planned capital expenditures and operating cash requirements.  The amounts and types of future long-term debt and equity financings will depend upon our capital needs and market conditions.


Employees

On June 30, 2011, we had 153 full-time employees.  We consider our relationship with our employees to be satisfactory.  Our employees are not represented by unions nor are they subject to any collective bargaining agreements.


Available Information

We make available free of charge on our Internet website http://www.deltagas.com, our Business Code of Conduct and Ethics, annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains an internet site http://www.sec.gov that contains reports, proxy and information statements and other information regarding Delta. The public may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC  20549.  The SEC's phone number is 1-800-732-0330.

 
7

 


 
 
 
Consolidated Statistics
                     
                       
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
2008
 
2007
 
                       
Average Retail Customers Served
                     
Residential
 
30,420
 
30,575
 
30,881
 
31,520
 
31,941
 
Commercial
 
4,949
 
4,957
 
5,009
 
5,107
 
5,128
 
Industrial
 
44
 
46
 
49
 
54
 
 59
 
                       
Total
 
35,413
 
35,578
 
35,939
 
36,681
 
 37,128
 
                       
Operating Revenues ($000) (a)
                     
Residential sales
 
25,800
 
23,783
 
33,774
 
30,742
 
28,648
 
Commercial sales
 
16,672
 
15,894
 
24,125
 
21,171
 
19,339
 
Industrial sales
 
1,199
 
1,075
 
1,769
 
1,707
 
 1,676
 
Total regulated sales (b)(c)
 
43,671
 
40,752
 
59,668
 
53,620
 
49,663
 
                       
On-system transportation (b)(c)
 
4,830
 
4,421
 
4,118
 
4,461
 
4,258
 
Off-system transportation (b)(c)
 
3,670
 
3,650
 
3,786
 
3,864
 
2,979
 
Non-regulated sales
 
34,343
 
30,746
 
41,159
 
54,438
 
44,669
 
Other
 
303
 
294
 
333
 
293
 
242
 
Intersegment eliminations (d)
 
(3,777
)
(3,441
)
(3,427
)
(4,019
)
(3,643
)
                       
Total
 
83,040
 
76,422
 
105,637
 
112,657
 
 98,168
 
                       
System Throughput (Million Cu. Ft.) (a)
                     
Residential sales
 
1,737
 
1,756
 
1,721
 
1,695
 
1,801
 
Commercial sales
 
1,310
 
1,331
 
1,346
 
1,286
 
1,345
 
Industrial sales
 
120
 
111
 
113
 
121
 
 136
 
Total regulated sales
 
3,167
 
3,198
 
3,180
 
3,102
 
3,282
 
                       
On-system transportation
 
4,830
 
4,533
 
4,215
 
4,975
 
5,161
 
Off-system transportation
 
11,531
 
11,039
 
11,908
 
12,623
 
9,774
 
Non-regulated sales
 
6,010
 
4,787
 
4,219
 
5,394
 
4,921
 
Intersegment eliminations (d)
 
(5,890
)
(4,692
)
(4,135
)
(5,276
)
(4,822
)
                       
Total
 
19,648
 
18,865
 
19,387
 
20,818
 
 18,316
 
                       
Average Annual Consumption Per
                     
Average Residential Customer
                     
 (Thousand Cu. Ft.)
 
57
 
57
 
56
 
54
 
56
 
                       
Lexington, Kentucky Degree Days
                     
Actual
 
4,725
 
4,782
 
4,651
 
4,464
 
4,419
 
Percent of 30 year average
 
103
 
104
 
101
 
96
 
95
 
                       

(a)  
Additional financial information related to our segments can be found in Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 15 of the Notes to Consolidated Financial Statements.
(b)  
We implemented new regulated base rates, as approved by the Kentucky Public Service Commission in October, 2007, which were designed to generate additional annual revenue of $3,920,000.
(c)  
We implemented new regulated base rates, as approved by the Kentucky Public Service Commission in October, 2010, which were designed to generate additional annual revenue of $3,513,000.
(d)  
Intersegment eliminations represent the transportation fee charged by the regulated segment to the non-regulated segment.

 
8
 

Item 1A.    Risk Factors

The risk factors below should be carefully considered.

WEATHER CONDITIONS MAY CAUSE OUR REVENUES TO VARY FROM YEAR TO YEAR. Our revenues vary from year to year, depending on weather conditions. We estimate that approximately 77% of our annual gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, which would reduce our revenues and profits.  The weather normalization provision in our tariff, approved by the Kentucky Public Service Commission, only partially mitigates this risk.  Under our weather normalization provision in our tariff, we adjust our rates for our residential and small non-residential customers to reflect variations from thirty-year average weather for our December through April billing cycles.

CHANGES IN FEDERAL REGULATIONS COULD REDUCE THE AVAILABILITY OR INCREASE THE COST OF OUR INTERSTATE GAS SUPPLY. We purchase almost all of our gas supply from interstate sources. For example, in our fiscal year ended June 30, 2011, approximately 99% of our gas supply was purchased from interstate sources. The Federal Energy Regulatory Commission regulates the transmission of the natural gas we receive from interstate sources, and it could increase our transportation costs or decrease our available pipeline capacity by changing its regulatory policies.  Additionally, federal legislation could restrict or limit drilling which could decrease the supply of available natural gas.

OUR GAS SUPPLY DEPENDS UPON THE AVAILABILITY OF ADEQUATE PIPELINE TRANSPORTATION CAPACITY. We purchase almost all of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of gas.

OUR CUSTOMERS ARE ABLE TO BY-PASS OUR DISTRIBUTION AND TRANSMISSION SYSTEMS. Our larger customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities.  Customers for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers.  Customers may undertake such by-passes in order to achieve lower prices for their gas and/or transportation services.  Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. This potential to by-pass our distribution and transportation systems creates a risk of the loss of large customers and thus could result in lower revenues and profits.

WE FACE REGULATORY UNCERTAINTY AT THE STATE LEVEL. We are regulated by the Kentucky Public Service Commission. Our regulated segment generates a significant portion of our operating revenues.  We face the risk that the Kentucky Public Service Commission may fail to grant us adequate and timely rate increases or may take other actions that would cause a reduction in our income from operations, such as limiting our ability to pass on to our customers our increased costs of natural gas. Such regulatory actions would decrease our revenues and our profitability.

VOLATILITY IN THE PRICE OF NATURAL GAS COULD REDUCE OUR PROFITS. Significant increases in the price of natural gas will likely cause our regulated retail customers to continue to conserve or switch to alternate sources of energy. Any decrease in the volume of gas we sell that is caused by such actions will reduce our revenues and profits. Higher prices also make it more difficult to add new customers. Significant decreases in the price of natural gas will likely cause our non-regulated segment margins to decrease.

INTERSTATE AND OTHER PIPELINES DELTA INTERCONNECTS WITH CAN IMPOSE RESTRICTIONS ON THEIR PIPELINE.  The pipelines interconnected to Delta's system are owned and operated by third parties who can impose restrictions on the quantity and quality of natural gas they will accept into their pipelines.  To the extent natural gas on Delta's system does not conform to these restrictions, Delta could experience a decrease in volumes sold or transported to these pipelines.

FUTURE PROFITABILITY OF THE NON-REGULATED SEGMENT IS DEPENDENT ON A FEW INDUSTRIAL AND OTHER LARGE USE CUSTOMERS.  Our larger non-regulated customers are primarily industrial and other large use customers.  Fluctuations in the gas requirements of these customers can have a significant impact on the profitability of the non-regulated segment.

 
9

 
WE RELY ON ACCESS TO CAPITAL TO MAINTAIN LIQUIDITY.  To the extent that internally generated cash coupled with short-term borrowings under our bank line of credit is not sufficient for our operating cash requirements and normal capital expenditures, we may need to obtain additional financing.  Our access to funds under our bank line of credit is dependent on the liquidity of the lender, Branch Banking & Trust Company.  Additionally, market disruptions may increase our cost of borrowing or adversely affect our access to capital markets.  Such disruptions could include:  economic downturns, the bankruptcy of an unrelated energy company, general capital market conditions, market price for natural gas, terrorist attacks or the overall health of the energy industry.  In 2011, although our bank line of credit was used for financing on an interim basis, cash provided by operating activity was sufficient to meet our capital needs.

POOR INVESTMENT PERFORMANCE OF PENSION PLAN HOLDINGS AND OTHER FACTORS IMPACTING PENSION PLAN COSTS COULD UNFAVORABLY IMPACT OUR LIQUIDITY AND RESULTS OF OPERATIONS.  Our cost of providing a non-contributory defined benefit pension plan is dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and our required or voluntary contributions made to the plan.  Without sustained growth in the pension investments over time to increase the value of the plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plan with additional significant amounts of cash.  Such cash funding obligations could have a material impact on our financial position, results of operations or cash flows.

WE ARE EXPOSED TO CREDIT RISKS OF CUSTOMERS AND OTHERS WITH WHOM WE DO BUSINESS.  Adverse economic conditions affecting, or financial difficulties of, customers and others with whom we do business could impair the ability of these customers and others to pay for our services or fulfill their contractual obligations or cause them to delay such payments or obligations.  We depend on these customers and others to remit payments on a timely basis.  Any delay or default in payment could adversely affect our cash flows, financial position or results of operations.

SUBSTANTIAL OPERATIONAL RISKS ARE INVOLVED IN OPERATING A NATURAL GAS DISTRIBUTION, PIPELINE AND STORAGE SYSTEM AND SUCH OPERATIONAL RISKS COULD REDUCE OUR REVENUES AND INCREASE EXPENSES.  There are substantial risks associated with the operation of a natural gas distribution, transportation and storage system, such as operational hazards and unforeseen interruptions caused by events beyond our control.  These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline and storage facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond our control.  These risks could result in injury or loss of life, extensive property damage and environmental pollution, which in turn could lead to substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. Liabilities incurred that are not fully covered by insurance could adversely affect our results of operations and financial condition.  Additionally, interruptions to the operation of our gas distribution, transmission or storage system caused by such an event could reduce our revenues and increase our expenses.

HURRICANES, EXTREME WEATHER OR WELL-HEAD DISASTERS COULD DISRUPT OUR GAS SUPPLY AND INCREASE NATURAL GAS PRICES.  Hurricanes, extreme weather or well-head disasters could damage production or transportation facilities, which could result in decreased supplies of natural gas and increased supply costs for us and higher prices for our customers. Such events could also result in new governmental regulations or rules that limit production or raise production costs.

CROSS-DEFAULT PROVISIONS IN OUR BORROWING ARRANGEMENTS INCREASE THE CONSEQUENCES OF A DEFAULT ON OUR PART.  Indentures under which our outstanding debt has been issued and the loan agreements for our bank line of credit, contain a cross-default provision which provides that we will be in default under such indenture or loan agreement in the event of certain defaults under any of the other indentures or loan agreements.  Accordingly, should an event of default occur under one of our debt agreements, we face the prospect of being in default under all of our debt agreements and obliged in such instance to satisfy all of our then-outstanding indebtedness.  In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us.

 
10

 
OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS NEGATIVE COVENANTS THAT RESTRICT OUR ACTIVITIES.  Without bank approval or repaying the bank line of credit, our bank line of credit restricts us from:

·
merging with another entity,
·
selling a material portion of our assets other than in the ordinary course of business,
·
issuing stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, and
·
having any person or group of related persons hold more than twenty percent (20%) of our outstanding shares of common stock.
   
Our 7.00% Debentures and 5.75% Insured Quarterly Notes restrict us from:

·
assuming additional secured indebtedness in excess of $5,000,000, unless we secure our 7.00% Debentures and 5.75% Insured Quarterly Notes equally with the additional secured indebtedness, and
·
paying dividends on or repurchasing our common stock unless our consolidated shareholders’ equity minus the value of our intangible assets exceed $25,800,000 after a dividend is paid or repurchase is made.

These negative covenants create the risk that we may be unable to take advantage of business and financing opportunities as they arise.

NEW LAWS OR REGULATIONS COULD HAVE A NEGATIVE IMPACT ON OUR FINANCIAL POSITION, RESULTS OF OPERATIONS OR CASH FLOWS.  Changes in laws and regulations, including new accounting standards and tax law, could change the way in which we are required to record revenues, expenses, assets and liabilities.  Additionally, governing bodies may choose to re-interpret laws and regulations.  These changes could have a negative impact on our financial position, cash flows, results of operations or access to capital.

CLIMATE CHANGE LEGISLATION MAY POSE NEW FINANCIAL OR REGULATORY RISKS.  A number of proposals to limit greenhouse gas emissions are pending at the regional, federal, and international levels.  These proposals, if enacted and made applicable to us, may require us to measure and potentially limit greenhouse gas emissions from our utility operations and our customers or purchase allowances for such emissions.  While we cannot predict the extent of these limitations or when or if they will become effective, the adoption of such proposals could:

·
increase utility costs related to operations, energy efficiency activities and compliance,
·
affect the demand for natural gas, and
·
increase the prices we charge our utility customers.

Unless we are able to timely recover such impacts from customers through the regulatory process, costs associated with any such regulatory or legislative changes could adversely affect Delta’s results of operations, financial condition and cash flows.


Item 1B.    Unresolved Staff Comments

None.


 
11

 

Item 2.             Properties

We own our corporate headquarters in Winchester, Kentucky. We own eleven buildings used for field operations in the cities we serve.

We own approximately 2,500 miles of natural gas gathering, transmission, distribution and storage lines. These lines range in size up to twelve inches in diameter.

We hold leases for the storage of natural gas under 8,000 acres located in Bell County, Kentucky. We developed this property for the underground storage of natural gas.

We use all the properties described in the three paragraphs immediately above principally in connection with our regulated segment, as further discussed in Item 1.  Business.

Through our wholly-owned subsidiary, Enpro, we produce natural gas as part of the non-regulated segment of our business.

Enpro owns interests in oil and natural gas leases on 10,300 acres located in Bell, Knox and Whitley Counties. Thirty-five gas wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated at 2.8 million Mcf.  Also, Enpro owns the natural gas underlying 15,400 additional acres in Bell, Clay and Knox Counties. These properties have been leased to others for further drilling and development.  We have performed no reserve studies on these properties.  Enpro produced a total of 91,000 Mcf of natural gas during fiscal 2011 from all the properties described in this paragraph.

A producer plans to conduct further exploration activities on part of Enpro’s developed holdings. Enpro reserved the option to participate in wells drilled by this producer and also retained certain working and royalty interests in any production from future wells.

Our assets have no significant encumbrances.


Item 3.              Legal Proceedings

In January, 2011 we filed a lawsuit in the Clark County, Kentucky Circuit Court against Chartis Insurance (“Chartis”) seeking recovery of an insurance claim filed by us with Chartis in March, 2009.  The claim sought reimbursement of $1,350,000 related to gas that escaped from our underground storage field during 2007.  During such time we had a policy with Chartis to insure the natural gas which is stored in the underground storage field, and we believed the policy was designed to cover such a loss.  Chartis has not reimbursed us for our loss, as the external consultant engaged by Chartis has challenged our right to recover under the policy.  Upon the request of Chartis, the case was subsequently removed to the United States District Court for the Eastern District of Kentucky.  Delta and Chartis filed motions on the issue of which party has the burden of proof with respect to the cause of the gas loss.  In May, 2011, the Court ruled on the motions citing that Delta has the burden of proof to demonstrate the loss was caused by an external factor.  Although this matter is currently in litigation, we have also engaged in settlement discussions with Chartis.


Item 4.             (Removed and Reserved)



 
12

 

PART II

Item 5.             Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

We have paid cash dividends on our common stock each year since 1964. The frequency and amount of future dividends will depend upon our earnings, financial requirements and other relevant factors, including limitations imposed by the indenture for our Insured Quarterly Notes and Debentures (as described in Note 10 of the Notes to Consolidated Financial Statements).

Our common stock is listed on NASDAQ and trades under the symbol “DGAS”. There were 1,630 record holders of our common stock as of August 15, 2011. The accompanying table sets forth, for the periods indicated, the high and low sales prices for the common stock on the NASDAQ stock market and the cash dividends declared per share.

 
   
Range of Stock Prices ($)
 
Dividends
 
   
High
 
Low
 
Per Share ($)
 
               
Quarter
             
               
Fiscal 2011
             
First
 
31.61
 
26.34
 
.34
 
Second
 
32.98
 
29.51
 
.34
 
Third
 
33.99
 
30.20
 
.34
 
Fourth
 
32.97
 
30.00
 
.34
 
               
Fiscal 2010
             
First
 
26.54
 
22.80
 
.325
 
Second
 
29.80
 
25.34
 
.325
 
Third
 
30.00
 
27.96
 
.325
 
Fourth
 
30.00
 
28.43
 
.325
 
               

The sales prices shown above reflect prices between dealers and do not include markups or markdowns or commissions and may not necessarily represent actual transactions.



 
13

 
 
Comparison of Five-Year Cumulative Total Shareholder Return

The following graph sets forth a comparison of five year cumulative total shareholder return (equal to dividends plus stock price appreciation) among our common shares, the Dow Jones Utilities Index and the Standard & Poor’s 500 Stock Index during the past five fiscal years. Information reflected on the graph assumes an investment of $100 on June 30, 2006 in each of our common shares, the Dow Jones Utilities Index and the Standard & Poor’s Stock Index.  Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.
stock graph
   
2006
 
2007
 
2008
 
2009
 
2010
 
2011
 
                           
Delta
 
100
 
110.59
 
117.33
 
107.06
 
142.06
 
163.94
 
                           
Dow Jones Utilities Index
 
100
 
124.18
 
133.87
 
96.09
 
100.58
 
127.27
 
                           
Standard & Poor’s 500 Stock Index
 
100
 
120.59
 
104.77
 
77.31
 
88.46
 
115.61
 
                           
 
 
14
 
 

 
 
Item 6.    Selected Financial Data
                     
                         
 
      The following selected financial data is derived from the Company’s audited consolidated financial statements and should be read in conjunction with those financial statements and notes thereto contained in this Form 10-K.
                         
 
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
2008
 
2007
 
                         
 
Summary of Operations ($)
                     
                         
 
Operating revenues (a)(d)
 
83,040,251
 
76,422,068
 
105,636,824
 
112,657,117
 
98,168,391
 
                         
 
Operating income (a)(b)(d)
 
14,061,794
 
12,904,494
 
12,793,200
 
15,663,736
 
12,968,043
 
                         
 
Net income (a)(b)(d)
 
6,364,895
 
5,651,817
 
5,210,729
 
6,829,868
 
5,298,347
 
                         
 
Earnings per common share (a)(b)(d)
                     
 
Basic and diluted
 
1.90
 
1.70
 
1.58
 
2.08
 
1.62
 
                         
 
Cash dividends declared per common share
 
1.36
 
1.30
 
1.28
 
1.24
 
1.22
 
                         
 
Weighted Average Number of Common Shares Basic
 
3,353,612
 
3,326,160
 
3,306,026
 
3,285,464
 
3,265,800
 
 
Weighted Average Number of Common Shares Diluted
 
3,356,402
 
3,326,160
 
3,306,026
 
3,285,464
 
3,265,800
 
                         
 
Total Assets ($)
 
174,896,239
 
168,632,420
 
162,505,295
 
170,814,856
 
160,400,950
 
                         
 
Capitalization ($)
                     
                         
 
Common shareholders’ equity
 
63,767,184
 
60,760,170
 
58,999,182
 
57,593,585
 
54,428,471
 
                         
 
Long-term debt
 
56,751,006
 
57,112,000
 
57,599,000
 
58,318,000
 
 58,625,000
 
                         
 
Total capitalization
 
120,518,190
 
117,872,170
 
116,598,182
 
115,911,585
 
113,053,471
 
                         
 
Short-Term Debt ($)(c)
 
1,200,000
 
1,200,000
 
4,853,103
 
8,028,791
 
5,389,918
 
                         
 
Other Items ($)
                     
                         
 
     Capital expenditures
 
8,123,479
 
5,275,194
 
8,422,433
 
5,563,667
 
8,082,918
 
                         
 
     Total property, plant and equipment
 
211,409,336
 
204,248,520
 
199,254,216
 
192,127,184
 
187,148,032
 
 
(a) We implemented new regulated base rates as approved by the Kentucky Public Service Commission in October, 2007 and the rates were designed to generate additional annual
       revenue of $3,920,000.
(b) We recorded a $1,350,000 non-recurring inventory adjustment at December 31, 2008 for our gas in storage, as discussed in Note 16 of the Notes to Consolidated Financial Statements.
(c) Includes current portion of long-term debt.
(d) We implemented new regulated base rates as approved by the Kentucky Public Service Commission in October, 2010 and the rates were designed to generate additional annual
       revenue of $3,513,000, with a $1,770,000 increase in annual depreciation expense.
 
   
     

 
15

 
Item 7.             Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview of 2011 and Future Outlook

Overview

The following is a discussion of the segments we operate, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during 2011. Our Company has two segments:  (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related ventures, consisting of natural gas marketing and production.

Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors.  Regulated sales volumes are temperature-sensitive. Our regulated sales volumes in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes.  The impact of winter temperatures on our revenues is partially reduced given our ability to adjust our winter rates for residential and small non-residential customers based on the degree to which actual winter temperatures deviate from normal.

Our non-regulated segment produces natural gas and markets natural gas to large-use customers both on and off our regulated system.  We endeavor to enter sales agreements to match estimated demand with supply and provide an acceptable margin.

Consolidated earnings per common share increased for 2011 compared with 2010 by $.20 per common share primarily due to new base rates approved by the Kentucky Public Service Commission (as further discussed in Note 14 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, with an accompanying increase in annual depreciation expense of $1,770,000.

Future Outlook

The results for 2012 will continue to be impacted by the new base rates approved by the Kentucky Public Service Commission.  The regulated segment’s largest expense is gas supply, which we are permitted to pass through to our customers.  We control remaining expenses through budgeting, approval and review.

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


Liquidity and Capital Resources

Sources and Uses of Cash

Operating activities provide our primary source of cash.  Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes and changes in working capital.  Our sales and cash requirements are seasonal.  The largest portion of our sales occurs during the heating months, whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months.  Therefore, our ability to maintain liquidity depends on our bank line of credit when cash provided by operating activities is not sufficient to meet our capital requirements.  There were no borrowings outstanding on the bank line of credit as of June 30, 2011 or June 30, 2010.  When we have no borrowings outstanding on our bank line of credit, excess cash is invested in overnight repurchase agreements.  Through Branch Banking & Trust Company, we purchase U.S. Treasury or Federal Agency Securities with a contractual agreement to sell back the securities the next day.

 
16

 
Long-term debt decreased to $56,751,000 at June 30, 2011, compared with $57,112,000 at June 30, 2010. The $361,000 decrease resulted from the redemption of the Debentures and Insured Quarterly Notes, which allows for limited redemptions to be made by certain holders or their beneficiaries.

Cash and cash equivalents were $7,340,000 at June 30, 2011 compared with $4,639,000 at June 30, 2010 and $123,000 at June 30, 2009.  These changes in cash and cash equivalents are summarized in the following table:
 
($000)
 
2011
 
2010
 
2009
 
               
Provided by operating activities
 
14,467
 
17,600
 
15,434
 
Used in investing activities
 
(7,520
)
(5,052
)
(7,956
)
Used in financing activities
 
(4,246
)
(8,031
)
(7,605
)
               
Increase (decrease) in cash and cash equivalents
 
2,701
 
4,517
 
(127
)

In 2011, $3,133,000 less cash was provided by operating activities as compared to 2010.  Cash contributed to our defined benefit pension plan increased $1,500,000 as we made an elective contribution in the current year to increase the funded status of the plan.  Cash paid for natural gas increased $6,164,000 due to increased volumes purchased during the current year to meet our customers’ gas requirements as well as increased volumes purchased for injection into our storage field.  Cash paid for other operation and maintenance expenses increased $434,000.  These increases were partially offset by a $5,464,000 increase in cash received from our customers due to increased rates in our regulated segment and increased volumes sold.

In 2010, $2,166,000 more cash was provided by operating activities as compared to 2009. Cash paid for natural gas decreased $32,397,000 due to a decrease in the cost of gas purchased.  Cash paid for taxes decreased $2,307,000 due to an income tax refund resulting from a method change that reduced our capitalization of expenses for income tax purposes.  Cash contributed to our defined benefit pension plan decreased $2,177,000 as we made an elective contribution in the prior year to maintain the funded status of the plan.  Additionally, cash paid for taxes other than income taxes and cash paid for interest decreased $694,000. These decreases in amounts paid were partially offset by a $36,159,000 decrease in cash received from customers due to decreased sales prices.

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

In 2011, cash used in financing activities decreased $3,785,000 due to decreased repayments on our bank line of credit.

In 2010, there were no significant changes in cash used in financing activities as compared to 2009.

Cash Requirements

Our capital expenditures result in a continued need for cash.  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.



 
17

 


The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2011:

   
Payments Due by Fiscal Year
 
 
($000)
 
 
  2012
 
 
2013-2014
 
 
2015-2016
 
 
After 2016
 
 
Total
 
 
Interest payments (a)
 
$
3,702
 
$
7,251
 
$
7,170
 
$
24,230
 
$
42,353
 
Long-term debt (b)
   
1,200
   
2,400
   
2,400
   
51,951
   
57,951
 
Pension contributions (c)
   
500
   
1,000
   
1,000
   
4,500
   
7,000
 
Gas purchases (d)
   
218
   
   
   
   
218
 
Total contractual obligations (e)
 
$
5,620
 
$
10,651
 
$
10,570
 
$
80,681
 
$
107,522
 
                                 

 
(a)
Our long-term debt, notes payable, customers’ deposits and unrecognized tax positions all require interest payments. Interest payments are projected based on fiscal 2011 interest payments until the underlying obligation is satisfied. Interest on notes payable represents interest payments expected on the bank line of credit which extends through June 30, 2013.  As of June 30, 2011, we have accrued $56,000 of interest related to uncertain tax positions.  This amount has been excluded from the above table of contractual obligations as the timing of such payments is uncertain.

 
(b)
See Note 10 of the Notes to Consolidated Financial Statements for a description of this debt.  The cash obligations represent the maximum annual amount of redemptions to be made to certain holders or their beneficiaries through the debt maturity date.  Our long-term debt does not have any sinking fund requirements.

 
(c)
This represents currently projected contributions to the defined benefit plan through 2025, as recommended by our actuary.

 
(d)
As of June 30, 2011 we had one contract which had a minimum purchase obligation.  This contract expires in December, 2011.  The remainder of our gas purchase contracts are either requirements-based contracts, or contracts with a minimum purchase obligation extending for a time period not exceeding one month.

 
(e)
We have other long-term liabilities which include deferred income taxes ($35,114,000), regulatory liabilities ($1,508,000), asset retirement obligations ($2,561,000) and deferred compensation ($511,000).  Based on the nature of these items their expected settlement dates cannot be estimated.

All of our operating leases are year-to-year and cancelable at our option.

See Note 13 of the Notes to Consolidated Financial Statements for other commitments and contingencies.

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 operating and capital expenditure requirements and to pay dividends, we rely on our bank line of credit.  Our current available bank line of credit with Branch Banking and Trust Company is $40,000,000, all of which was available at June 30, 2011.  The current bank line of credit extends through June 30, 2013.

 
18

 
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 or our capital stock repurchased unless after giving effect to such dividend payments or repurchases our consolidated shareholders' equity minus the value of the Company’s intangible assets exceeds $25,800,000 (thus no retained earnings are restricted),

·  
we may not assume any secured indebtedness in excess of $5,000,000, unless we secure our 7.00% Debentures and 5.75% Insured Quarterly Notes equally with the additional secured indebtedness, and

·  
without the consent of the bank that has extended to us our bank line of credit (or paying off and terminating our bank line of credit), we may not:

   ·  
merge with another entity,
   ·  
sell a material portion of our assets other than in the ordinary course of business,
   ·  
issue stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, or
   ·  
permit any person or group of related persons hold more than twenty percent (20%) of the Company’s outstanding shares of common stock.

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 in our Consolidated Financial Statements.  We are not aware of any events that would cause us to be in default in fiscal 2012.

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 a general rate increases for our regulated services.

In August, 2011, Standard & Poor downgraded long-term U.S. sovereign debt from AAA to AA+, with a negative outlook.  Although a downgrade of long-term sovereign credit ratings is not unprecedented, a downgrade of the U.S. credit rating is, and the potential impact is uncertain.  U.S. treasuries continue to trade in active markets, and the yield curve on U.S. treasuries remains an appropriate basis for determining risk-free rates.  The downgrade could materially affect global and domestic financial markets and economic conditions, which may affect our results of operations, financial position, or cash flows in future periods.


Critical Accounting Policies and Estimates

Preparation of financial statements and related disclosures in compliance with generally accepted accounting principles requires the use of assumptions and estimates regarding future events, including the likelihood of success of particular investments or initiatives, estimates of future prices or rates, legal and regulatory challenges and anticipated recovery of costs.  Therefore, the possibility exists for materially different reported amounts under different conditions or assumptions.  We consider an accounting estimate to be critical if (i) the accounting estimate requires us to make assumptions about matters that were reasonably uncertain at the time the accounting estimate was made and (ii) changes in the estimate are reasonably likely to occur from period to period.

These critical accounting estimates should be read in conjunction with the Notes to Consolidated Financial Statements.  We have other accounting policies that we consider to be significant; however, these policies do not meet the definition of critical accounting estimates, because they generally do not require us to make estimates or judgments that are particularly difficult or subjective.

 
19

 
Regulatory Accounting

Our accounting policies reflect the effects of the rate-making process in accordance with regulatory accounting standards.  Our regulated segment continues to be cost-of-service rate regulated, and we believe the application of regulatory accounting standards to that segment continues to be appropriate.  We must reaffirm this conclusion at each balance sheet date.  If, as a result of a change in circumstances, it is determined that the regulated segment no longer meets the criteria of regulatory accounting, that segment will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on our consolidated financial statements.

The application of regulatory accounting standards results in recording regulatory assets and liabilities.  Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the Kentucky Public Service Commission.  We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery.  We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies and the status of any potential new legislation.  Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred, or they represent probable future refunds to customers.

We use our best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our consolidated financial statements.  We believe it is probable that we will recover the regulatory assets that have been recorded.

Pension

We have a trusteed, non-contributory, defined benefit pension plan covering all eligible employees hired prior to May 9, 2008.  Our reported costs of providing retirement benefits (as described in Note 6(a) of the Notes to Consolidated Financial Statements) are dependent upon numerous factors resulting from actual plan experience and assumptions concerning future experience.

Pension costs associated with our defined benefit pension plan, for example, are impacted by employee demographics (including age, compensation levels and employment periods), the level of contributions we make to the plan and earnings on plan assets.  Additionally, changes made to the provisions of the plan may impact current and future pension costs.  Pension costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.

Changes in pension obligations associated with the above factors may not be immediately recognized as pension costs in the Consolidated Statements of Income, but may be deferred and amortized in the future over the average remaining service period of active plan participants.  For the years ended June 30, 2011, 2010 and 2009, we recorded pension costs for our defined benefit pension plan of $1,129,000, $1,040,000 and $608,000, respectively.

Our pension plan assets are principally comprised of equity and fixed income investments.  Differences between actual portfolio returns and expected returns may result in increased or decreased pension costs in future periods.  Likewise, changes in assumptions regarding current discount rates and expected rates of return on plan assets could also increase or decrease recorded pension costs.

In selecting our discount rate assumption we considered rates of return on high-quality fixed-income investments that are expected to be available through the maturity dates of the pension benefits.  Our expected long-term rate of return on pension plan assets was 7% for 2011 and was based on our targeted asset allocation assumption of approximately 65% equity investments and approximately 35% fixed income investments.  Our target investment allocation for equity investments includes allocations to domestic, global and real estate markets.  Our asset allocation is designed to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective.  We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

 
20

 
We calculate the expected return on assets in our determination of pension costs based on the market value of assets at the measurement date. Using the market value recognizes investment gains or losses in the year in which they occur.

Based on an assumed long-term rate of return of 7%, discount rate of 5.25%, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plan will decrease from $1,129,000 in 2011 to $481,000 in 2012. Modifying the expected long-term rate of return on our pension plan assets by .25% would change pension costs for 2012 by approximately $53,000.  Increasing the discount rate assumption by .25% would decrease pension costs by approximately $65,000.  Decreasing the discount rate assumption by .25% would increase pension costs by approximately $66,000.

Provisions for Doubtful Accounts

We encounter risks associated with the collection of our accounts receivable.  As such, we record a monthly provision for accounts receivable that are considered to be uncollectible.  In our regulated segment, the risk of collection on accounts receivable is partially mitigated by our ability to recover the portion of the monthly provision which relates to the customers’ gas cost.  Effective January, 2011, we began to recover the uncollectible gas cost portion through our gas cost recovery clause.

In order to calculate the appropriate monthly provision, we primarily utilize our historical experience related to accounts written-off.  Quarterly, at a minimum, we review the reserve for reasonableness based on the level of revenue and the aging of the receivable balance.  The underlying assumptions used for the allowance can change from period to period and the allowance could potentially cause a material impact to the Consolidated Statements of Income.  The actual weather, commodity prices and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact operating income.

Unbilled Revenues and Gas Costs

At each month-end, we estimate the gas service that has been rendered from the date the customer’s meter was last read to month-end.  This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather-sensitive usage for each degree day during the unbilled period.  Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month-end. Actual usage patterns may vary from these assumptions and may impact operating income.

Asset Retirement Obligations

We have accrued asset retirement obligations for gas well plugging and abandonment costs.  Additionally, we have recorded asset retirement obligations required pursuant to Federal regulations related to the retirement of our service lines and mains, although the timing of such retirements is uncertain.  The fair value of our retirement obligations are recorded at the time the obligations are incurred. We do not recognize asset retirement obligations relating to assets with indeterminate useful lives.  Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability.  Over time the liabilities are accreted for the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets.  For asset retirement obligations attributable to assets of our regulated operations, the depreciation and accretion are deferred as a regulatory asset.  We must use judgment to identify all appropriate asset retirement obligations.  The underlying assumptions used for the value of the retirement obligations and related capitalized costs can change from period to period.  These assumptions include the estimated future retirement costs, the estimated retirement date and the assumed credit-adjusted risk-free interest rate.  Our asset retirement obligations are further discussed in Note 4 of the Notes to Consolidated Financial Statements.

New Accounting Pronouncements

Significant management judgment is generally required during the process of adopting new accounting pronouncements. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of these pronouncements.

 
21

 
Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations and the other sections of this report contain forward-looking statements that relate to future events or our future performance.  We have attempted to identify these statements by using words such as “estimates”, “attempts”, “expects”, “monitors”, “plans”, “anticipates”, “intends”, “continues”, “could”, “strives” ,”seeks”, “will rely”, “believes” and similar expressions.

These forward-looking statements include, but are not limited to, statements about:

·
operational plans,
·
the cost and availability of our natural gas supplies,
·
capital expenditures,
·
sources and availability of funding for our operations and expansion,
·
anticipated growth and growth opportunities through system expansion and acquisition,
·
competitive conditions that we face,
·
production, storage, gathering, transportation and marketing activities,
·
acquisition of service franchises from local governments,
·
pension fund costs and management,
·
contractual obligations and cash requirements,
·
management of our gas supply and risks due to potential fluctuation in the price of natural gas,
·
revenues, income, margins and profitability,
·
efforts to purchase and transport locally produced natural gas,
·
recovery of regulatory assets,
·
litigation,
·
regulatory and legislative matters, and
·
dividends.

Our forward-looking statements are not guarantees of future performance and are based upon currently available competitive, financial and economic data along with our operating plans.

Item 1A.  Risk Factors lists factors that could cause future results to differ materially from those expressed in or implied by the forward-looking statements or historical results.


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.  Throughout the following discussion of Results of Operations, we show revenue from gas sales, net of their corresponding purchased gas expenses and define “gross margin” as gas sales less purchased gas expenses, plus transportation and other revenues.  Gross margin, therefore, refers to operating revenues less purchased gas expenses, which can be derived directly from our Consolidated Statements of Income as follows:

($000)
 
2011
 
2010
 
2009
 
               
Operating revenues (a)
 
83,040
 
76,422
 
105,637
 
Less – Purchased gas (a)
 
47,839
 
44,100
 
72,078
 
               
Gross margin
 
35,201
 
32,322
 
33,559
 

(a)  
amounts derived from the Consolidated Statements of Income included in Item 8.  Financial Statements and Supplemental Data

 
22

 
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 operations.  This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments.  We believe that investors benefit from having access to the same financial measures that our management uses.

Natural gas prices are determined by an unregulated national market.  Therefore, the price that we pay for natural gas fluctuates with national supply and demand. See Item 7A.  Quantitative and Qualitative Disclosures About Market Risk for discussion of our forward contracts.

In the following table we set forth variations in our gross margins for the last two fiscal years 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.
 
 
 
($000)
 
2011 compared
 to 2010
 
2010 compared
 to 2009
 
               
Increase (decrease) in gross margins
         
 
Regulated segment
         
   
Gas sales
 
2,360
 
(297
)
   
On-system transportation
 
409
 
303
 
   
Off-system transportation
 
20
 
(136
)
   
Other
 
9
 
(38
)
   
Intersegment elimination (a)
 
(336
)
(14
)
               
   
Total
 
2,462
 
(182
)
               
 
Non-regulated segment
         
   
Gas sales
 
61
 
(1,094
)
   
Other
 
20
 
25
 
   
Intersegment elimination (a)
 
336
 
14
 
               
   
Total
 
417
 
(1,055
)
               
Increase (decrease) in consolidated gross margins
 
2,879
 
(1,237
)
               
Percentage increase (decrease) in volumes
         
 
Regulated segment
         
   
Gas sales
 
(1
)
1
 
   
On-system transportation
 
7
 
8
 
   
Off-system transportation
 
4
 
(7
)
               
 
Non-regulated segment
         
   
Gas sales
 
26
 
13
 

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

 
23

 
Heating degree days were 103% of normal thirty year average temperatures for fiscal 2011, as compared with 104% and 101% of normal temperatures for 2010 and 2009, 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.

In 2011, consolidated gross margins increased $2,879,000 (9%) due to increased regulated and non-regulated gross margins of $2,462,000 (10%) and $417,000 (6%), respectively.  Regulated gross margins increased due to increased base rates which became effective October 22, 2010 and an increase in volumes transported.  Non-regulated margins increased due to an increase in volumes sold due to an increase in our non-regulated customers’ gas requirements, which was partially offset by a decline in sales prices.

In 2010, consolidated gross margins decreased $1,237,000 (4%) due to decreased non-regulated and regulated gross margins of $1,055,000 (13%) and $182,000 (1%), respectively.  Our non-regulated gross margins decreased due to a 23% decline in sales prices, partially offset by a 13% increase in volumes sold.

Operation and Maintenance

In 2011, there were no significant changes in operation and maintenance expense as compared to 2010.

In 2010, operation and maintenance expense decreased $1,574,000 (10%).  The decrease was primarily due to an inventory adjustment for our gas in storage ($1,350,000, as further discussed in Note 16 of the Notes to Consolidated Financial Statements) recorded in 2009 and decreased uncollectible expense ($994,000) partially offset by increased employee benefit expense ($410,000).  Uncollectible expense decreased due to the collection of past due balances which were specifically reserved for as of June 30, 2009.

Depreciation and Amortization

In 2011, depreciation and amortization increased $1,216,000 (31%) due to increased depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case.

In 2010, there were no significant changes in depreciation and amortization as compared to 2009.

Other Income and Deductions, Net

In 2011, there were no significant changes in other income and deductions, net as compared to 2010.

In 2010, other income and deductions, net, increased $155,000 (334%) due to increases in the cash surrender value of life insurance as well as an increase in the fair value of the supplemental retirement plan.  The increase in the fair value of the supplemental retirement plan was offset by increased operating expense resulting from a corresponding increase in the liability of the plan.

Other Interest

In 2011, there were no significant changes in other interest as compared to 2010.

In 2010, other interest decreased $316,000 (64%) due to decreased borrowings on our bank line of credit and decreases in the average interest rate on our bank line of credit.

Income Tax Expense

In 2011, income tax expense increased $568,000 (18%) due to an increase in net income before income taxes.  There were no significant changes in our effective tax rate for 2011 as compared to 2010.

In 2010, there were no significant changes in income tax expense or our effective tax rate as compared to 2009.

 
24

 

Basic and Diluted Earnings Per Common Share

For 2011 and 2010, our basic earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding.  We increased our number of common shares outstanding as a result of shares issued through our Dividend Reinvestment and Stock Purchase Plan as well as those awarded through our incentive compensation plan.

Certain awards under our shareholder approved incentive compensation plan provide the recipient of the award 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.  There were 16,000 participating unvested shares outstanding as of June 30, 2011.  As of June 30, 2011, there were no non-participating unvested performance shares outstanding.  Non-participating unvested performance shares would be included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.  There were no antidilutive shares in 2011 or 2010.


Item 7A.   Quantitative and Qualitative Disclosures About Market Risk

We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. The price of spot market gas is based on the market price at the time of delivery. The price we pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed prior to the delivery of the gas. Additionally, we inject some of our gas purchases into a storage facility in the non-heating months and withdraw this gas from storage for delivery to customers during the heating season. For our regulated business, we have minimal price risk resulting from these forward gas purchase and storage arrangements because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism, approved quarterly by the Kentucky Public Service Commission.

Price risk for the non-regulated business is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand. In addition, we are exposed to changes in the market price of gas on uncommitted gas volumes of our non-regulated companies.

None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase and gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.

When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates.  The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate.  There were no borrowings outstanding on our bank line of credit as of June 30, 2011 or June 30, 2010.  The weighted average interest rate on our bank line of credit was 1.8% and 1.9% as of June 30, 2011 and June 30, 2010, respectively.  Based on the average borrowings on our bank line of credit during 2011, a 1% (one hundred basis points) increase in our average interest rate would result in a $35,000 decrease  in our annual pre-tax net income.



 
25

 

Item 8.        Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE
PAGE
   
Report of Independent Registered Public Accounting Firm
35
   
Consolidated Statements of Income for the years ended June 30, 2011, 2010 and 2009
36
   
Consolidated Statements of Cash Flows for the years ended June 30, 2011, 2010 and 2009
37
   
Consolidated Balance Sheets as of June 30, 2011 and 2010
39
   
Consolidated Statements of Changes in Shareholders’ Equity for the years ended June 30, 2011, 2010 and 2009
41
   
Notes to Consolidated Financial Statements
42
   
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2011, 2010 and 2009
63

Schedules other than those listed above are omitted because they are not required, are not applicable or the required information is shown in the financial statements or notes thereto.


Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 None.


Item 9A.   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 in the Securities and Exchange Commission’s (“SEC”) 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 Rule 13a-15(e) and 15d-15(e)  under the Exchange Act) as of June 30, 2011 and based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).  Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of June 30, 2011 based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that evaluation, management concluded that our internal control over financial reporting was effective as of June 30, 2011.

 
26

 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended June 30, 2011 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting. That report immediately follows:

 
27

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:


We have audited the internal control over financial reporting of Delta Natural Gas Company, Inc. and subsidiaries (the "Company") as of June 30, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Certification of the Chief Executive Officer and Certification of the Chief Financial Officer. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended June 30, 2011 of the Company and our report dated August 26, 2011 expressed an unqualified opinion on those financial statements and financial statement schedule.


/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana
August 26, 2011


 
28

 

Item 9B.    Other Information

None.

                                                                PART III

Item 10.    Directors, Executive Officers and Corporate Governance

We have a Business Code of Conduct and Ethics that applies to all directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer.  Our Business Code of Conduct and Ethics can be found on our website by going to the following address:  http://www.deltagas.com.   We will post any amendments to the Business Code of Conduct and Ethics, as well as any waivers that are required to be disclosed by the rules of either the Securities and Exchange Commission or the NASDAQ OMX Group, on our website.

Our Board of Directors has adopted charters for the Audit, Corporate Governance and Compensation and Executive Committees of the Board of Directors.  These documents can be found on our website by going to the following address:  http://www.deltagas.com and clicking on the appropriate link.

A printed copy of any of the materials referred to above can be obtained by contacting us at the following address:

 
Delta Natural Gas Company, Inc.
 
Attn:  John B. Brown
 
3617 Lexington Road
 
Winchester, KY  40391
 
(859) 744-6171
   
The Audit Committee of our Board of Directors is an “audit committee” for purposes of Section 3(a)(58) of the Securities Exchange Act of 1934.

The other information required by this Item is contained under the captions “Election of Directors”, “Board Leadership, Committees and Meetings”, “Executive Officers”, “Certain Relationships and Related Transactions” and “Section 16(a) Beneficial Ownership Reporting Compliance”  in our definitive Proxy Statement for the Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2011.  We incorporate that information in this document by reference.


Item 11.    Executive Compensation

Information in response to this item is contained under the captions “Director Compensation”, “Compensation Committee Interlocks and Insider Participation”, “Compensation Discussion and Analysis”, “Compensation Risks”, “Corporate Governance and Compensation Committee Report”, “Summary Compensation Table”, “Grant of Plan Based Awards”, “Outstanding Equity Awards”, “Retirement Benefits”, “Potential Payments Upon Termination Or Change in Control” and “Termination Table” in our definitive Proxy Statement for the Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2011.  We incorporate that information in this document by reference.



 
29

 


Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity Compensation Plans

Pursuant to the Delta Natural Gas Company, Inc., Incentive Compensation Plan, which our shareholders approved in November, 2009, we have the ability to grant stock bonuses, performance shares and restricted stock to employees, officers and directors. The plan does not provide for the awarding of options, warrants or rights. We do not have any equity compensation plans which have not been approved by our shareholders.

The following table sets forth certain information with respect to our equity compensation plan at June 30, 2011:



Column A
 
Column B
 
Column C
         
 
 
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
 
 
 
 
Weighted-average exercise price of outstanding options, warrants and rights
 
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column A)
         
                            —
 
                        —
 
                    475,000

The other information required by this Item is contained under the caption “Security Ownership of Certain Beneficial Owners and Management” in our definitive Proxy Statement for the Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2011.  We incorporate that information in this document by reference.


Item 13.  Certain Relationships and Related Transactions, and Director Independence

The information required by this item is contained under the captions “Election of Directors”, “Board Leadership, Committees and Meetings” and  “Certain Relationships and Related Transactions” in our definitive Proxy Statement for the Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2011.  We incorporate that information in this document by reference.


Item 14.  Principal Accountant Fees and Services

The information required by this item is contained under the caption “Audit Committee Report” in our definitive Proxy Statement for the Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2011.  We incorporate that information in this document by reference.



 
30

 


PART IV


Item 15.
Exhibits and Financial Statement Schedules

(a)
 
Financial Statements, Schedules and Exhibits
 
 
(1)
Financial Statements
See Index at Item 8
 
 
(2)
Financial Statement Schedules
See Index at Item 8
 
 
(3)
Exhibits
     
 
Exhibit No.

 
3(i)
Registrant’s Amended and Restated Articles of Incorporation (dated November 16, 2006) are incorporated herein by reference to Exhibit 3(i) to Registrant’s Form 10-K/A (File No. 000-08788) for the period ended June 30, 2007.
 
3(ii)
Registrant’s Amended and Restated By-Laws (dated September 24, 2010) are incorporated herein by reference to Exhibit 3.1 to Registrant's Form 8-K (File No. 000-8788) dated September 27, 2010.
 
4(a)
The Indenture dated January 1, 2003 in respect of 7% Debentures due February 1, 2023, is incorporated herein by reference to Exhibit 4(d) to Registrant’s Form S-2 (Reg. No. 333-100852) dated October 30, 2002.
 
4(b)
The Indenture dated March 1, 2006 in respect of 5.75% Insured Quarterly Notes due April 1, 2021, is incorporated herein by reference to Exhibit 4(d) to Registrant’s Form S-3 (Reg. No. 333-132322) dated March 10, 2006.
 
10.01
Gas Sales Agreement, dated May 1, 2000 by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10(c) to Registrant’s Form S-2/A (Reg. No. 333-100852) dated December 13, 2002.
 
10.02
Base Contract for Short-Term Sale and Purchase of Natural Gas, dated January 1, 2002, by and between M & B Gas Services, Inc. and Registrant, is incorporated herein by reference to Exhibit 10(n) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
10.03
Gas Sales Agreement, dated May 1, 2003, by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10(d) to Registrant's Form 10-K (File No. 000-08788) for the period ended June 30, 2003.
 
10.04
Gas Sales Agreement, dated May 1, 2005, by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10(c) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2005.
 
10.05
Gas Transportation Agreement (Service Package 9069), dated December 19, 1994, by and between Tennessee Gas Pipeline Company and Registrant is incorporated herein by reference to Exhibit 10(e) to Registrant’s Form S-2/A (Reg. No. 333-100852) dated December 13, 2002.
 
10.06
Agreement to transport natural gas between Nami Resources Company L.L.C. and Registrant, dated March 10, 2005, is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 8-K (File No. 000-08788) dated March 23, 2005.
 
10.07
Amendment, dated July 22, 2010, of agreement to transport natural gas between Nami Resources Company, L.L.C. and Registrant, filed herewith.
 
10.08
GTS Service Agreements, dated November 1, 1993 (Service Agreement Nos. 37,813, 37,814 and 37,815), and Appendix A to respective Service Agreements, effective November 1, 2010, by and between Columbia Gas Transmission Corporation and Registrant, filed herewith.
 
10.09
FTS1 Service Agreements, dated October 4, 1994, (Service Agreement Nos. 43,827, 43,828 and 43,829), and Appendix A to respective Service Agreements, effective November 1, 2010, by and between Columbia Gulf Transmission Corporation and Registrant, filed herewith.
 
10.10
Underground Gas Storage Lease and Agreement, dated March 9, 1994, by and between Equitable Resources Exploration, a division of Equitable Resources Energy Company, and Lonnie D. Ferrin and Amendment No. 1 and Novation to Underground Gas Storage Lease and Agreement, dated March 22, 1995, by and between Equitable Resources Exploration, Lonnie D. Ferrin and Registrant, is incorporated herein by reference to Exhibit 10(m) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
 
31

 
 
10.11
Oil and Gas Lease, dated July 19, 1995, by and between Meredith J. Evans and Helen Evans and Paddock Oil and Gas, Inc.; Assignment, dated June 15, 1995, by Paddock Oil and Gas, Inc., as assignor, to Lonnie D. Ferrin, as assignee; Assignment, dated August 31, 1995, by Paddock Oil and Gas, Inc., as assignor, to Lonnie D. Ferrin, as assignee; and Assignment and Assumption Agreement, dated November 10, 1995, by and between Lonnie D. Ferrin and Registrant, is incorporated herein by reference to Exhibit 10(o) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
10.12
Gas Storage Lease, dated October 4, 1995, by and between Judy L. Fuson, Guardian of Jamie Nicole Fuson, a minor, and Lonnie D. Ferrin and Assignment and Assumption Agreement, dated November 10, 1995, by and between Lonnie D. Ferrin and Registrant is incorporated herein by reference to Exhibit 10(j) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
10.13
Gas Storage Lease, dated November 6, 1995, by and between Thomas J. Carnes, individually and as Attorney-in-fact and Trustee for the individuals named therein, and Registrant, is incorporated herein by reference to Exhibit 10(k) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
10.14
Deed and Perpetual Gas Storage Easement, dated December 21, 1995, by and between Katherine M. Cornelius, William Cornelius, Frances Carolyn Fitzpatrick, Isabelle Fitzpatrick Smith and Kenneth W. Smith and Registrant is incorporated herein by reference to Exhibit 10(l) to Registrant’s Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
 
10.15
Loan Agreement, dated October 31, 2002, by and between Branch Banking and Trust Company and Registrant is incorporated herein by reference to Exhibit 10(i) to Registrant’s Form S-2/A (Reg. No. 333-100852) dated December 13, 2002.
 
10.16
Promissory Note, in the original principal amount of $40,000,000, made by Registrant to the order of Branch Banking and Trust Company, is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended September 30, 2002.
 
10.17
Modification Agreement extending to October 31, 2004 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2003.
 
10.18
Modification Agreement extending to October 31, 2005 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2004.
 
10.19
Modification Agreement extending to October 31, 2007 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated August 19, 2005.
 
10.20
Modification Agreement extending to October 31, 2009 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended September 30, 2007.
 
10.21
Modification Agreement extending to June 30, 2011 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated June 30, 2009.
 
10.22
Modification Agreement extending to June 30, 2013 the Promissory Note and Loan Agreement dated October 31, 2002 between Branch Banking and Trust Company and Registrant, is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated June 30, 2011.
 
10.23
Employment agreement dated March 1, 2000, between Glenn R. Jennings, Registrant’s Chairman of the Board, President and Chief Executive Officer, and Registrant, is incorporated herein by reference to Exhibit (k) to Registrant’s Form 10-Q (File No. 000-08788) dated March 31, 2000.
 
10.24
Officer agreements dated March 1, 2000, between two officers, those being John B. Brown and Johnny L. Caudill, and Registrant, are incorporated herein by reference to Exhibit 10(k) to Registrant’s Form 10-Q (File No. 000-08788) for the period ended March 31, 2000.
 
10.25
Officer agreement dated November 20, 2008, between Brian S. Ramsey and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated November 21, 2008.
 
10.26
Officer agreement dated November 19, 2010, between Matthew D. Wesolosky and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant's Form 8-K (File No. 000-08788) dated November 24, 2010.
 
 
32

 
 
10.27
Supplemental retirement benefit agreement and trust agreement between Glenn R. Jennings and Registrant is incorporated herein by reference to Exhibit 10(a) to Registrant’s Form 8-K (File No. 000-08788) dated February 25, 2005.
 
10.28
Registrant's Amended and Restated Dividend Reinvestment and Stock Purchase Plan, dated November 17, 2005, is incorporated herein by reference to Exhibit 99(b) to Registrant’s S-3D (Reg. No. 333-130301) dated December 14, 2005.
 
10.29
Registrant's Incentive Compensation Plan, dated January 1, 2008, is incorporated herein by reference to Exhibit 4.1 to Registrant’s S-8 (Reg. No. 333-165210) dated March 4, 2010.
 
10.30
Notices of Performance Shares Award between four officers, those being John B. Brown, Johnny L. Caudill, Glenn R. Jennings, and Brian S. Ramsey, and Registrant, are incorporated herein by reference to Exhibits 10.3, 10.4, 10.5 and 10.6 of Registrant’s Form 8-K (File No. 000-8788) dated August 20, 2010.
 
10.31
Notices of Performance Shares Award between five officers, those being John B. Brown, Johnny L. Caudill, Glenn R. Jennings, Brian S. Ramsey and Matthew D. Wesolosky and Registrant, are incorporated herein by reference to Exhibits 10.1, 10.2, 10.3, 10.4 and 10.5 of Registrant’s Form 8-K (File No. 000-8788) dated August 16, 2011.
 
12
Computation of the Consolidated Ratio of Earnings to Fixed Charges.
 
21
Subsidiaries of the Registrant.
 
23
Consent of Independent Registered Public Accounting Firm.
 
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.

 
33

 

 
SIGNATURES


Pursuant to the requirements of Section 13 or 15(d) 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, on the 26th day of August, 2011.

 
DELTA NATURAL GAS COMPANY, INC.
   
 
By:  /s/Glenn R. Jennings
 
Glenn R. Jennings
 
Chairman of the Board, President and Chief
Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

(i)           Principal Executive Officer:
   
     
/s/Glenn R. Jennings
Chairman of the Board, President
August 26, 2011
(Glenn R. Jennings)
and Chief Executive Officer
 
     
(ii)Principal Financial Officer
   
     
 /s/John B. Brown
Chief Financial Officer,
August 26, 2011
(John B. Brown)
Treasurer and Secretary
 
     
(iii)        Principal Accounting Officer:
   
     
 /s/ Matthew D. Wesolosky
Vice President - Controller
August 26, 2011
(Matthew D. Wesolosky)
   
     
(iv)           A Majority of the Board of Directors:
   
     
/s/Glenn R. Jennings
Chairman of the Board, President
August 26, 2011
(Glenn R. Jennings)
and Chief Executive Officer
 
     
/s/Linda K. Breathitt
Director
August 26, 2011
(Linda K. Breathitt)
   
     
/s/Lanny D. Greer
Director
August 26, 2011
(Lanny D. Greer)
   
     
/s/Michael J. Kistner
Director
August 26, 2011
(Michael J. Kistner)
   
     
/s/Lewis N. Melton
Director
August 26, 2011
(Lewis N. Melton)
   
     
/s/Arthur E. Walker, Jr.
Director
August 26, 2011
(Arthur E. Walker, Jr.)
   
     
/s/Michael R. Whitley
Director
August 26, 2011
(Michael R. Whitley)
   
     

 
34

 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:

We have audited the accompanying consolidated balance sheets of Delta Natural Gas Company, Inc. and subsidiaries (the “Company”) as of June 30, 2011 and 2010, and the related consolidated statements of income, changes in shareholders' equity, and cash flows for each of the three years in the period ended June 30, 2011. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at June 30, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of June 30, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated August 26, 2011 expressed an unqualified opinion on the Company's internal control over financial reporting.


/S/  DELOITTE & TOUCHE LLP

Indianapolis, Indiana
August 26, 2011



 
35

 


 Delta Natural Gas Company, Inc.
             
               
Consolidated Statements of Income
             
               
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
                     
Operating Revenues
                   
Regulated revenues
 
$
48,697,530
 
$
45,675,860
 
$
64,477,638
 
Non-regulated revenues
   
34,342,721
   
30,746,208
   
41,159,186
 
Total operating revenues
 
$
83,040,251
 
$
76,422,068
 
$
105,636,824
 
                     
Operating Expenses
                   
Purchased gas
 
$
47,839,274
 
$
44,100,329
 
$
72,077,631
 
Operation and maintenance
   
14,065,725
   
13,456,449
   
15,030,287
 
Depreciation and amortization
   
5,156,973
   
3,941,353
   
3,855,099
 
Taxes other than income taxes
   
1,916,485
   
2,019,443
   
1,880,607
 
Total operating expenses
 
$
68,978,457
 
$
63,517,574
 
$
92,843,624
 
                     
Operating Income
 
$
14,061,794
 
$
12,904,494
 
$
12,793,200
 
                     
Other Income and Deductions, Net
 
$
151,506
 
$
108,800
 
$
(46,418
 
)
                     
Interest Charges
                   
Interest on long-term debt
 
$
3,584,772
 
$
3,606,086
 
$
3,648,243
 
Other interest
   
116,763
   
175,843
   
492,151
 
Amortization of debt expense
   
387,263
   
387,263
   
387,263
 
Total interest charges
 
$
4,088,798
 
$
4,169,192
 
$
4,527,657
 
                     
                     
Income Before Income Taxes
 
$
10,124,502
 
$
8,844,102
 
$
8,219,125
 
                     
Income Tax Expense
 
$
3,759,607
 
$
3,192,285
 
$
3,008,396
 
                     
Net Income
 
$
6,364,895
 
$
5,651,817
 
$
5,210,729
 
                     
Earnings Per Common Share (Note 11)
                   
Basic
 
$
1.90
 
$
1.70
 
$
1.58
 
Diluted
 
$
1.90
 
$
1.70
 
$
1.58
 
                     
Dividends Declared Per Common Share
 
$
1.36
 
$
1.30
 
$
1.28
 







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

 
36

 


 Delta Natural Gas Company, Inc.
             
               
Consolidated Statements of Cash Flows
             
               
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
                     
Cash Flows From Operating Activities
                   
Net income
 
$
6,364,895
 
$
5,651,817
 
$
5,210,729
 
                     
Adjustments to reconcile net income to net
                   
cash from operating activities
                   
Depreciation and amortization
   
5,640,916
   
4,448,496
   
4,362,241
 
Provision for inventory adjustment
   
   
   
1,350,300
 
Deferred income taxes and investment
                   
tax credits
   
2,536,234
   
5,015,750
   
2,135,347
 
Gain on sale of property, plant and equipment
   
   
   
(156,023
)
Change in cash surrender value of officer’s
                   
life insurance
   
(58,744
)
 
(28,829
)
 
31,651
 
Share-based compensation
   
526,859
   
   
 
                     
(Increase) decrease in assets
                   
Accounts receivable
   
(1,833,298
)
 
(845,479
)
 
7,334,709
 
Gas in storage
   
(605,529
)
 
3,541,037
   
3,379,325
 
Deferred gas cost
   
(81,799
)
 
(939,969
)
 
2,255,751
 
Materials and supplies
   
20,629
   
143,764
   
(93,516
)
Prepayments
   
1,874,828
   
(1,473,433
)
 
(2,173,506
)
Other assets
   
(34,260
)
 
(285,347
)
 
(77,411
)
                     
Increase (decrease) in liabilities
                   
Accounts payable
   
1,936,487
   
1,706,121
   
(7,418,187
)
Accrued taxes
   
122,358
   
256,066
   
(773,761
)
Other current liabilities
   
(1,351,841
)
 
761,374
   
486,664
 
Asset retirement obligations and other
   
(591,014
)
 
(351,057
)
 
(420,393
)
                     
Net cash provided by operating activities
 
$
14,466,721
 
$
17,600,311
 
$
15,433,920
 
                     
Cash Flows From Investing Activities
                   
Capital expenditures
 
$
(8,123,479
)
$
(5,275,194
)
$
(8,422,433
)
Proceeds from sale of property, plant and equipment
   
171,641
   
161,949
   
526,763
 
Other
   
431,897
   
60,422
   
(60,000
)
Net cash used in investing activities
 
$
(7,519,941
)
$
(5,052,823
)
$
(7,955,670
)
                     






The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
 
37

 
Delta Natural Gas Company, Inc.
             
               
Consolidated Statements of Cash Flows (continued)
             
               
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
                     
Cash Flows From Financing Activities
                   
Dividends on common shares
 
$
(4,562,284
)
$
(4,323,439
)
$
(4,231,239
)
Issuance of common shares
   
677,544
   
432,610
   
520,407
 
Repayment of long-term debt
   
(360,993
)
 
(487,000
)
 
(719,000
)
Borrowings on bank line of credit
   
17,824,196
   
25,205,557
   
74,107,057
 
Repayment of bank line of credit
   
(17,824,196
)
 
(28,858,660
)
 
(77,282,745
)
 
                   
Net cash used in financing activities
 
$
(4,245,733
)
$
(8,030,932
)
$
(7,605,520
)
                     
                     
Net Increase (Decrease) in Cash and Cash Equivalents
 
$
2,701,047
 
$
4,516,556
 
$
(127,270
)
                     
                     
Cash and Cash Equivalents,  Beginning of Year
   
4,639,145
   
122,589
   
249,859
 
                     
                     
Cash and Cash Equivalents,  End of Year
 
$
7,340,192
 
$
4,639,145
 
$
122,589
 
                     
Supplemental Disclosures of Cash Flow Information
                   
                     
Cash paid during the year for
                   
Interest
 
$
3,702,692
 
$
3,785,630
 
$
4,148,311
 
Income taxes (net of refunds)
 
$
(124,861
)
$
(676,439
)
$
1,630,937
 
                     
Significant non-cash transactions
                   
Accrued capital expenditures
 
$
340,670
 
$
460,357
 
$
414,385
 
Share-based compensation
 
$
526,859
 
$
 
$
 

















The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
 
38

 
 Delta Natural Gas Company, Inc.
         
           
Consolidated Balance Sheets
         
           
As of June 30,
 
2011
 
2010
 
               
Assets
             
               
Current Assets
             
Cash and cash equivalents
 
$
7,340,192
 
$
4,639,145
 
    Accounts receivable, less accumulated allowances for doubtful
   
6,540,702
   
4,727,631
 
accounts of $190,000 and  $273,000 in 2011 and 2010,
             
respectively
             
Gas in storage, at average cost (Notes 1 and 16)
   
6,811,260
   
6,205,731
 
Deferred gas costs (Notes 1 and 14)
   
3,378,711
   
3,296,912
 
Materials and supplies, at average cost
   
555,883
   
536,416
 
Prepayments
   
2,113,224
   
3,640,979
 
               
Total current assets
 
$
26,739,972
 
$
23,046,814
 
               
Property, Plant and Equipment
 
$
211,409,336
 
$
204,248,520
 
Less – Accumulated provision for depreciation
   
(78,232,077
)
 
(73,792,601
)
               
Net property, plant and equipment
 
$
133,177,259
 
$
130,455,919
 
               
Other Assets
             
Cash surrender value of  life insurance
             
(face amount of $1,178,360)
 
$
508,808
 
$
450,064
 
Prepaid Pension (Note 6)
   
3,141,116
   
 
Regulatory assets (Note 1)
   
8,823,310
   
12,115,436
 
Unamortized debt expense and other (Notes 1 and 10)
   
2,505,774
   
2,564,187
 
               
Total other assets
 
$
14,979,008
 
$
15,129,687
 
               
Total assets
 
$
174,896,239
 
$
168,632,420
 














The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
 
39

 
Delta Natural Gas Company, Inc.
         
           
Consolidated Balance Sheets (continued)
         
           
As of June 30,
 
2011
 
2010
 
               
Liabilities and Shareholders’ Equity
             
               
Current Liabilities
             
Accounts payable
 
$
8,201,249
 
$
6,460,620
 
Current portion of long-term debt (Note 10)
   
1,200,000
   
1,200,000
 
Accrued taxes
   
1,447,094
   
1,263,755
 
Customers’ deposits
   
643,692
   
535,516
 
Accrued interest on debt
   
852,952
   
854,109
 
Accrued vacation
   
707,544
   
731,869
 
Deferred income taxes
   
1,092,255
   
1,059,912
 
Other liabilities
   
317,867
   
417,694
 
               
Total current liabilities
 
$
14,462,653
 
$
12,523,475
 
               
Long-Term Debt (Note 10)
 
$
56,751,006
 
$
57,112,000
 
               
Long-Term Liabilities
             
Deferred income taxes
 
$
35,114,249
 
$
32,462,067
 
Investment tax credits
   
86,700
   
113,900
 
Regulatory liabilities (Note 1)
   
1,507,928
   
1,664,139
 
Accrued pension
   
   
1,218,441
 
Asset retirement obligations and other (Note 4)
   
3,206,519
   
2,778,228
 
 
             
Total long-term liabilities
 
$
39,915,396
 
$
38,236,775
 
               
Commitments and Contingencies (Note 13)
             
               
Total liabilities
 
$
111,129,055
 
$
107,872,250
 
               
Shareholders’ Equity
             
    Common shares ($1.00 par value), 20,000,000 shares authorized; 3,366,172 and 3,334,856 shares outstanding at June 30, 2011 and June 30, 2010, respectively
 
$
3,366,172
 
$
3,334,856
 
Premium on common shares
   
46,054,488
   
44,881,401
 
Retained earnings
   
14,346,524
   
12,543,913
 
               
Total shareholders’ equity
 
$
63,767,184
 
$
60,760,170
 
               
Total liabilities and shareholders’ equity
 
$
174,896,239
 
$
168,632,420
 




The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
 
40

 
Delta Natural Gas Company, Inc.
             
               
Consolidated Statements of Changes in Shareholders’ Equity
         
               
For the Years Ended June 30,
 
2011
 
2010
 
2009
 
                     
Common Shares
                   
Balance, beginning of year
 
$
3,334,856
 
$
3,318,046
 
$
3,295,759
 
Issuance of common shares
                   
$1.00 par value of 22,316, 16,810,
                   
and 22,287 shares issued in 2011,
                   
2010 and 2009, respectively
   
22,316
   
16,810
   
22,287
 
Issuance of common shares under the incentive compensation plan
   
9,000
   
   
 
                     
Balance, end of year
 
$
3,366,172
 
$
3,334,856
 
$
3,318,046
 
                     
Premium on Common Shares
                   
Balance, beginning of year
 
$
44,881,401
 
$
44,465,601
 
$
43,967,481
 
Issuance of common shares
   
655,228
   
415,800
   
498,120
 
Issuance of common shares under the incentive compensation plan
   
254,970
   
   
 
Share-based compensation
   
262,889
   
   
 
                     
Balance, end of year
 
$
46,054,488
 
$
44,881,401
 
$
44,465,601
 
                     
Retained Earnings
                   
Balance, beginning of year
 
$
12,543,913
 
$
11,215,535
 
$
10,330,345
 
Change in defined benefit plan measurement date (net of $57,699 of tax) (Note 2)
   
   
   
(94,300
)
Balance, beginning of year, as adjusted
 
$
12,543,913
 
$
11,215,535
 
$
10,236,045
 
Net income
   
6,364,895
   
5,651,817
   
5,210,729
 
Cash dividends declared on common
                   
shares (See Consolidated Statements
                   
of Income for rates)
   
(4,562,284
)
 
(4,323,439
)
 
(4,231,239
)
                     
Balance, end of year
 
$
14,346,524
 
$
12,543,913
 
$
11,215,535
 
                     
Common Shareholders’ Equity
                   
Balance, beginning of year
 
$
60,760,170
 
$
58,999,182
 
$
57,593,585
 
Change in defined benefit plan measurement
date (net of $57,699 of tax) (Note 2)
   
   
   
(94,300
)
Balance, beginning of year, as adjusted
 
$
60,760,170
 
$
58,999,182
 
$
57,499,285
 
Net income
   
6,364,895
   
5,651,817
   
5,210,729
 
Issuance of common shares
   
677,544
   
432,610
   
520,407
 
Issuance of common shares under the incentive compensation plan
   
263,970
   
   
 
Share-based compensation
   
262,889
   
   
 
Dividends on common shares
   
(4,562,284
)
 
(4,323,439
)
 
(4,231,239
)
                     
Balance, end of year
 
$
63,767,184
 
$
60,760,170
 
$
58,999,182
 



The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
 
 
41

 
 DELTA NATURAL GAS COMPANY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)  Summary of Significant Accounting Policies

(a) Principles of Consolidation  Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately 37,000 customers.  Our distribution and transportation 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. All subsidiaries of Delta are included in the consolidated financial statements. Intercompany balances and transactions have been eliminated.

(b) Cash Equivalents   For the purposes of the Consolidated Statements of Cash Flows, all temporary cash investments with a maturity of three months or less at the date of purchase are considered cash equivalents.

(c) Property, Plant and Equipment   Property, plant and equipment is stated at original cost, which includes materials, labor, labor related costs and an allocation of general and administrative costs.  A betterment or replacement of a unit of property is accounted for as an addition of utility plant.  Construction work in progress has been included in the rate base for determining customer rates, and therefore an allowance for funds used during construction has not been recorded.  The cost of regulated plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, less salvage value, is charged to the accumulated provision for depreciation.

Property, plant and equipment is comprised of the following major classes of assets:

($000)
 
2011
 
2010
         
Regulated segment
       
Distribution, transmission and storage
 
182,041
 
179,366
General, miscellaneous and intangibles
 
21,847
 
21,040
Construction work in progress
 
5,142
 
1,602
Total regulated segment
 
209,030
 
202,008
         
Non-regulated segment
 
2,379
 
2,241
Total property, plant and equipment
 
211,409
 
204,249

We have a pipe replacement program approved by the Kentucky Public Service Commission, which allows us to adjust rates annually to earn a return on capital expenditures for the replacement of pipe and related facilities incurred subsequent to the test year in our most recent rate case.  The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.

(d) Depreciation  We determine the provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant.  The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of 2.6%, 2.1% and 2.1% of average depreciable plant for 2011, 2010 and 2009, respectively.  Effective October, 2010 we implemented new depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case which decreased the remaining depreciable lives of our depreciable assets.

As approved by the Kentucky Public Service Commission, we accrue asset removal costs for certain type of property through depreciation expense with a corresponding credit to regulatory liabilities on the Consolidated Balance Sheet.  When depreciable utility plant and equipment is retired any related removal costs incurred are charged against the regulatory liability.

(e) Maintenance   All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts in the month incurred.

 
42

 
(f) Gas Cost Recovery    We have a Gas Cost Recovery (“GCR”) component of our regulated gas rates which provides for a dollar-tracker that matches revenues and gas costs and provides eventual dollar-for-dollar recovery of all gas costs incurred by the regulated segment and is approved by the Kentucky Public Service Commission.  We expense gas costs based on the amount of gas costs recovered through revenue.  Any differences between actual gas costs and those estimated costs billed are deferred and reflected in the computation of future billings to customers using the GCR mechanism.  In our general rate case, the Kentucky Public Service Commission approved a change to our gas cost recovery clause, effective January, 2011, allowing us to recover the uncollectible gas cost portion of bad debt expense as a component of the GCR adjustment.

(g) Revenue Recognition    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:

(000)
 
2011
 
2010
 
           
Unbilled revenues ($)
 
1,437
 
1,120
 
Unbilled gas costs ($)
 
410
 
333
 
Unbilled volumes (Mcf)
 
58
 
53
 

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

(h)  Excise Taxes    Certain excise taxes levied by state or local governments are collected by Delta from our customers.  These taxes are accounted for on a net basis and therefore are not included as revenues in the accompanying Consolidated Statements of Income.

(i) Revenues and Customer Receivables    We serve 37,000 customers in central and southeastern Kentucky. Revenues and customer receivables arise primarily from sales of natural gas to customers and from transportation services for others.  Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable. Customer accounts are charged off when deemed to be uncollectible or when turned over to a collection agency to pursue.

(j) Use of Estimates   The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(k) Rate Regulated Basis of Accounting     We account for our regulated segment in accordance with applicable regulatory guidance.  The economic effects of regulation can result in a regulated company recovering costs from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise.  When this results, costs are deferred as assets on the Consolidated Balance Sheets (“regulatory assets”) and recorded as expenses when such amounts are reflected in rates.  Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (“regulatory liabilities”).  The amounts recorded as regulatory assets and regulatory liabilities are as follows:

 
43

 


($000)
 
2011
 
2010
 
           
Regulatory assets
         
Current assets
         
Deferred gas costs
 
3,379
 
3,297
 
           
Other assets
         
Conservation/efficiency program expenses
 
206
 
183
 
Loss on extinguishment of debt
 
1,967
 
2,157
 
Asset retirement obligations
 
2,391
 
2,000
 
Accrued pension
 
4,069
 
7,557
 
Regulatory case expenses
 
190
 
218
 
Total other assets
 
8,823
 
12,115
 
           
Total regulatory assets
 
12,202
 
15,412
 
           
Regulatory liabilities
         
Accrued cost of removal on long-lived assets
 
346
 
381
 
Regulatory liability for deferred income taxes
 
1,162
 
1,283
 
Total regulatory liabilities
 
1,508
 
1,664
 

All of our regulatory assets and liabilities have been approved for recovery by the Kentucky Public Service Commission and are currently being recovered or refunded through our regulated gas rates.  In addition, the unrecovered balance of the loss on extinguishment of debt is included in rate base and, therefore, earns a return.  The weighted average recovery period of regulatory assets not earning a return is 20 years.

(l) Impairment of Long-Lived Assets   We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets.  If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for an impairment loss if the carrying value is greater than the fair value.  In the opinion of management, our long-lived assets are appropriately valued in the accompanying consolidated financial statements.

(m)  Derivatives  Certain of our natural gas purchase and sale contracts qualify as derivatives.  All such contracts have been designated as normal purchases and sales and as such are accounted for under the accrual basis and are not recorded at fair value in the accompanying consolidated financial statements.

(n)  Marketable Securities  We have a supplemental retirement benefit agreement with Glenn R. Jennings, our Chairman of the Board, President and Chief Executive Officer, that is a non-qualified deferred compensation plan.  The agreement establishes an irrevocable rabbi trust, in which the assets of the trust are earmarked to pay benefits under the agreement.  We have recognized a liability related to the obligation to pay these benefits to Mr. Jennings.  We make discretionary contributions to the trust in order to fully fund the related deferred compensation liability.

The assets of the trust consist of exchange traded mutual funds and are classified as trading securities.  The assets are recorded at fair value on the Consolidated Balance Sheets based on observable market prices from active markets.  Net realized and unrealized gains and losses are included in earnings each period to effectively offset the corresponding earnings impact associated with the change in the fair value of the deferred compensation liability to which the assets relate.

 
44

 
    (o)  Fair Value   Fair value is considered to be the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date.  The fair value focuses on an exit price, which is the price that would be received by us to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability.

We determine fair value based on the following fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels:

Level 1 -
Observable inputs consisting of quoted prices in active markets for identical assets or liabilities;

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

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

Although accounting standards permit entities to elect to measure many financial instruments and certain other items at fair value, we do not currently have any financial assets or financial liabilities for which this provision has been elected. However, in the future, we may elect to measure certain financial instruments at fair value in accordance with these standards.

      (p) Gas In Storage   We operate a natural gas underground storage field that we utilize to inject and store natural gas during the non-heating season, and we then withdraw natural gas during the heating season to meet our customers’ needs.  The potential exists for differences between actual volumes stored versus our perpetual records primarily due to inaccuracies in measurement of injections and withdrawals or the risks of gas escaping from the facility. We periodically analyze the volumes, pressure and other data relating to the storage field in order to substantiate the gas inventory carried in our perpetual inventory records.  The periodic analysis of the storage field data utilizes trends in the underlying data and can require multiple periods of observation to determine if differences exist.  The analysis can result in adjustments made to our perpetual inventory records, as further discussed in Note 16 of the Notes to Consolidated Financial Statements.  The gas in storage inventory is recorded at average cost.


(2)  New Accounting Pronouncements

Recently Issued Pronouncements

(a)  Fair Value Measurement and Disclosure  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 set of standards into a single conceptual framework which would change how fair value measurement guidance is applied in future periods.  The guidance, which will be effective for our quarter ending March 31, 2012, is not expected to have a material impact on our results of operations or financial position.


(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:
               
 
($000)
2011
 
2010
     
               
 
Trust assets
511
 
373
     

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

 
45

 
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 would transfer to the insurer.  Therefore, the insurance is not considered in the determination of the fair value of the Insured Quarterly Notes.
         
   
2011
 
2010
   
Carrying
 
Fair
 
Carrying
 
Fair
 
($000)
Amount
 
Value
 
Amount
 
Value
                 
 
7% Debentures
19,410
 
18,988
 
19,460
 
18,839
 
5.75% Insured Quarterly Notes
38,541
 
34,400
 
38,852
 
34,128


(4)   Asset Retirement Obligations

Legal obligations

As of June 30, 2011 and 2010, we have accrued liabilities and related assets, net of accumulated depreciation, relative to the legal obligation to retire certain gas wells, storage tanks, mains and services.  During the fiscal year ended 2011, we recognized asset retirement obligations for mains and services placed into service in the amount of $1,000.  In 2011, our asset retirement obligations increased to reflect revisions to the estimated cost to retire certain mains and wells.  In 2010, our asset retirement obligations increased to reflect revisions to the estimated cost to retire certain services.  For asset retirement obligations related to regulated assets, accretion of the liability and depreciation of the asset retirement costs are recorded as regulatory assets, pursuant to regulatory accounting standards, as we recover the cost of removing our regulated assets through our depreciation rates.

The following is a summary of our asset retirement obligations and related assets (net of accumulated depreciation), reflected on the accompanying Consolidated Balance Sheets under the captions asset retirement obligations and other, and property, plant and equipment, respectively:
           
($000)
 
2011
 
2010
 
           
Asset Retirement Obligations
         
Beginning of year
 
2,201
 
1,670
 
Liabilities incurred
 
1
 
4
 
Liabilities settled
 
(434
)
(371
)
Accretion
 
167
 
126
 
Revisions in estimated cash flows
 
626
 
772
 
           
End of year
 
2,561
 
2,201
 

We have an additional asset retirement obligation relative to the retirement of wells located at our underground natural gas storage facility.  Since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the underlying asset has an indeterminate life.  Therefore, we have not recorded a liability associated with the cost to retire the wells.

Non-legal obligations

In accordance with established regulatory practices, we accrue costs of removal on long-lived assets through depreciation expense to the extent recovery of such costs is granted by our regulator even though such costs do not represent legal obligations.  In accordance with regulatory accounting standards, $346,000 and $382,000 of such accrued cost of removal was recorded as a regulatory liability on the accompanying Consolidated Balance Sheets as of June 30, 2011 and 2010, respectively.

 
46

 

(5)   Income Taxes

We provide for income taxes on temporary differences resulting from the use of alternative methods of income and expense recognition for financial and tax reporting purposes.  The differences result primarily from the use of accelerated tax depreciation methods for certain properties versus the straight-line depreciation method for financial reporting purposes, differences in recognition of purchased gas costs and certain accruals which are not currently deductible for income tax purposes.  Investment tax credits were deferred for certain periods prior to fiscal 1987 and are being amortized to income over the estimated useful lives of the applicable properties.  We utilize the asset and liability method for accounting for income taxes, which requires that deferred income tax assets and liabilities be computed using tax rates that will be in effect when the book and tax temporary differences reverse. Changes in tax rates applied to accumulated deferred income taxes are not immediately recognized in operating results because of ratemaking treatment.  A regulatory liability has been established to recognize the regulatory obligation to refund these excess deferred taxes through customer rates.  The current portion of the net accumulated deferred income tax liability is shown as current liabilities and the long-term portion is included in deferred credits and other on the accompanying Consolidated Balance Sheets.  Delta’s state net operating loss carry forward expires in 2029.  The temporary differences which gave rise to the net accumulated deferred income tax liability for the periods are as follows:

($000) 
 
 
 
2011
 
2010
 
           
Deferred Tax Liabilities
         
Accelerated depreciation
 
32,827
 
31,002
 
Deferred gas costs
 
1,283
 
1,252
 
Regulatory assets – loss on extinguishment of debt
 
747
 
819
 
Regulatory assets – asset retirement obligations
 
589
 
600
 
Regulatory assets – unrecognized accrued pension
 
1,545
 
2,869
 
Pension
 
1,035
 
 
Prepaid expenses
 
346
 
358
 
Other
 
506
 
114
 
           
Total
 
38,878
 
37,014
 
           
Deferred Tax Assets
         
Alternative minimum tax credits
 
36
 
762
 
Regulatory liabilities
 
441
 
487
 
Investment tax credits
 
33
 
43
 
Reserve for bad debt
 
81
 
104
 
Asset retirement obligations
 
910
 
608
 
Accrued employee benefits
 
765
 
486
 
Section 263(a) capitalized costs
 
77
 
75
 
Pension
 
 
473
 
State net operating loss carryforward
 
116
 
268
 
Other
 
213
 
186
 
           
Total
 
2,672
 
3,492
 
           
Net accumulated deferred income tax liability
 
36,206
 
33,522
 


 
47

 


The components of the income tax provision are comprised of the following for the years ended June 30:
 
($000)
 
2011
 
2010
 
2009
 
               
Components of Income Tax Expense
             
Current
             
Federal
 
956
 
(1,709
)
560
 
State
 
276
 
(115
)
255
 
Total
 
1,232
 
(1,824
)
815
 
Deferred
 
2,528
 
5,016
 
2,193
 
Income tax expense
 
3,760
 
3,192
 
3,008
 


Reconciliation of the statutory federal income tax rate to the effective income tax rate is shown in the table below: 

(%)
 
2011
 
2010
 
2009
 
               
Statutory federal income tax rate
 
34.0
 
34.0
 
34.0
 
State income taxes, net of federal benefit
 
4.0
 
4.0
 
4.0
 
Amortization of investment tax credits
 
(0.3
)
(0.3
)
(0.4
)
Other differences, net
 
(0.6
)
(1.6
)
(1.0
)
Effective income tax rate
 
37.1
 
36.1
 
36.6
 

We recognize the income tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.  The liability for unrecognized tax benefits expected to be recognized within the next twelve months has partially offset our prepaid income taxes and been presented in prepayments on the Consolidated Balance Sheets.  The liability for unrecognized tax benefits not expected to be recognized within the next twelve months has been presented in asset retirement obligations and other on the Consolidated Balance Sheets.  Interest and penalties on tax uncertainties are classified in income tax expense in the Consolidated Statements of Income.

The amount of unrecognized tax benefits, net of tax, which, if recognized, would impact the effective tax rate was $80,000 and $66,000 as of June 30, 2011 and 2010, respectively.  As of June 30, 2011, we have accrued interest of $56,000 on unrecognized tax positions, of which $26,000 and $9,000 was recognized in the 2011 and 2010 Consolidated Statements of Income, respectively.

The following is a tabular reconciliation of our unrecognized tax benefits:
 
 ($000)
   
2011
 
2010
 
               
Beginning Balance
     
194
 
378
 
Gross increases
             
Tax positions in prior period
     
102
 
28
 
Gross decreases
             
Tax positions in prior period
     
(30
)
(24
)
Lapse of statute of limitations
     
 
(188
)
Ending Balance
     
266
 
194
 
               
We file income tax returns in the federal and Kentucky jurisdictions.  Tax years previous to June 30, 2008 and June 30, 2007 are no longer subject to examination for federal and Kentucky income taxes, respectively.  Our federal 2008 and 2009 tax returns are currently under examination.

 
48

 

(6)  Employee Benefit Plans

(a)   Defined Benefit Retirement Plan   We have a trusteed, noncontributory, defined benefit retirement plan covering all eligible employees hired prior to May 9, 2008.  Retirement income is based on the number of years of service and annual rates of compensation.  The Company has historically made annual contributions equal to the amounts necessary to fund the plan adequately.  We contributed $2,000,000 to the plan in fiscal 2011.

Generally accepted accounting principles (“GAAP”) require employers who sponsor defined benefit plans to recognize the funded status of a defined benefit pension plan on the balance sheet and to recognize through comprehensive income the changes in the funded status in the year in which the changes occur.  However, regulatory accounting standards provide that regulated entities can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current cost-of-service ratemaking in Kentucky allows recovery of net periodic benefit cost as determined under GAAP.  The Kentucky Public Service Commission has been clear and consistent with its historical treatment of such rate recovery; therefore, we have recorded a regulatory asset representing the probable recovery of the portion of the change in funded status of the defined benefit plan that is expected to be recognized in future net periodic benefit cost.  The regulatory asset is adjusted annually as prior service cost and actuarial losses are recognized in net periodic benefit cost.

Our obligations and the funded status of our plan, measured at June 30, 2011 and June 30, 2010, respectively, are as follows:
 
($000)
 
2011
 
2010
 
           
Change in Benefit Obligation
         
Benefit obligation at beginning of year
 
16,506
 
14,058
 
Service cost
 
939
 
728
 
Interest cost
 
854
 
855
 
Actuarial loss
 
64
 
2,044
 
Benefits paid
 
(448
)
(1,179
)
Benefit obligation at end of year
 
17,915
 
16,506
 
           
Change in Plan Assets
         
Fair value of plan assets at beginning of year
 
15,288
 
13,629
 
Actual return on plan assets
 
4,216
 
2,338
 
Employer contributions
 
2,000
 
500
 
Benefits paid
 
(448
)
(1,179
)
Fair value of plan assets at end of year
 
21,056
 
15,288
 
 
Recognized Amounts
         
Projected benefit obligation
 
(17,915
)
(16,506
)
Plan assets at fair value
 
21,056
 
15,288
 
Funded status
 
3,141
 
(1,218
)
           
Net amount recognized as prepaid (accrued) benefit costs on the Consolidated Balance Sheets
 
3,141
 
(1,218
)

 
49

 

   
2011
 
2010
 
           
 Items Not Yet Recognized as a Component of Net Periodic Benefit Costs
         
Prior service cost
 
(576
)
(662
)
Net loss
 
4,645
 
8,219
 
Amounts recognized as regulatory assets
 
4,069
 
7,557
 
 
 
 
The accumulated benefit obligation was $15,721,000 and $14,426,000 for 2011 and 2010, respectively.
 
($000)
 
2011
 
2010
 
2009
 
               
Components of Net Periodic Benefit Cost
             
Service cost
 
939
 
727
 
677
 
Interest cost
 
854
 
855
 
810
 
Expected return on plan assets
 
(1,079
)
(953
)
(1,010
)
Amortization of unrecognized net loss
 
501
 
497
 
217
 
Amortization of prior service cost
 
(86
)
(86
)
(86
)
Net periodic benefit cost
 
1,129
 
1,040
 
608
 
               
Weighted-Average % Assumptions Used to Determine Benefit Obligations
             
Discount rate
 
5.25
 
5.25
 
6.25
 
Rate of compensation increase
 
4.0
 
4.0
 
4.0
 
               
Weighted-Average % Assumptions Used to Determine Net Periodic Benefit Cost
             
Discount rate
 
5.25
 
6.25
 
6.50
 
Expected long-term return on plan assets
 
7.0
 
7.0
 
7.0
 
Rate of compensation increase
 
4.0
 
4.0
 
4.0
 

Plan Assets

Our target investment allocations have been developed using an asset allocation model which weighs risk versus return of various investment indices to create a target asset allocation to maximize return subject to a moderate amount of portfolio risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolios contain a diversified blend of equity and fixed income investments. Our target investment allocations are approximately 65% equity investments and 35% fixed income investments. Our equity investment target allocations are heavily weighted toward domestic equity securities, with allocations to real estate equity securities and foreign equity securities for the purposes of diversification. Fixed income securities primarily include U.S. government obligations and corporate debt securities. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

The assets of the plan are comprised of investments in mutual funds and common collective trusts. Each individual mutual fund or common collective trust has been selected based on its investment strategy which mirrors a specific asset class within our target allocation.



 
50

 


 
       
Actual Allocation
   
Target
   
(%)
 
Allocation
 
2011
 
2010
Asset Class (a)
           
Cash
 
-
 
-
 
-
             
Equity Securities
           
U.S. Equity Securities
 
38
 
47
 
46
Foreign Equity Securities
 
17
 
16
 
17
Domestic Real Estate
 
10
 
12
 
13
   
65
 
75
 
76
             
Fixed Income Securities
 
35
 
25
 
24
   
100
 
100
 
100

(a)      Each mutual fund and common collective trust has been categorized based on its primary investment
strategy.

The mutual funds are categorized as Level 1 in the fair value hierarchy as the fair value of the mutual funds is determined based on the quoted market price of each fund. The common/collective trusts are categorized as Level 2 in the fair value hierarchy. The fair value of the common/collective trusts are determined based on the net asset value as published by the respective fund manager multiplied by the number of units held in the trust.  For our investments in the common/collective trusts, there are no restrictions on our ability to sell these investments.  The respective level within the fair value hierarchy is determined as described in Note 1 of the Notes to Consolidated Financial Statements.  The following represents the fair value of plan assets:
                 
($000)
 
2011
 
Level 1
 
Level 2
 
Level 3
Asset Class (a)
               
Cash
 
21
 
21
 
-
 
-
                 
Exchange Traded Mutual Funds
               
U.S. Equity Securities
 
717
 
717
 
-
 
-
Fixed Income Securities
 
1,098
 
1,098
 
-
 
-
Foreign Equity Securities
 
1,263
 
1,263
 
-
 
-
Domestic Real Estate Securities
 
2,442
 
2,442
 
-
 
-
   
5,520
 
5,520
 
-
 
-
                 
Common Collective Trusts
               
Short-Term Income Fund
 
68
 
-
 
68
 
-
U.S. Fixed Income Fund
 
2,179
 
-
 
2,179
 
-
Global Equity Growth Fund
 
2,559
 
-
 
2,559
 
-
Global Equity Value Fund
 
1,150
 
-
 
1,150
 
-
U.S. Equity Index Fund
 
2,000
 
-
 
2,000
 
-
Foreign Equity Index Fund
 
2,039
 
-
 
2,039
 
-
Blended Fund (b)
 
5,520
 
-
 
5,520
 
-
   
15,515
 
-
 
15,515
 
-
                 
Total
 
21,056
 
5,541
 
15,515
 
-
                 


 
51

 


($000)
 
2010
 
Level 1
 
Level 2
 
Level 3
Asset Class (a)
               
Cash
 
9
 
9
 
-
 
-
                 
  Exchange Traded Mutual Funds
               
  U.S. Equity Securities
 
502
 
502
 
-
 
-
  Foreign Equity Securities
 
1,161
 
1,161
 
-
 
-
  Domestic Real Estate Securities
 
1,916
 
1,916
 
-
 
-
   
3,579
 
3,579
 
-
 
-
                 
Common Collective Trusts
               
  Short-Term Income Fund
 
224
 
-
 
224
 
-
  U.S. Fixed Income Fund
 
2,210
 
-
 
2,210
 
-
  Global Equity Growth Fund
 
1,659
 
-
 
1,659
 
-
  Global Equity Value Fund
 
798
 
-
 
798
 
-
  U.S. Equity Index Fund
 
1,394
 
-
 
1,394
 
-
  Foreign Equity Index Fund
 
1,418
 
-
 
1,418
 
-
  Blended Fund (b)
 
3,997
 
-
 
3,997
 
-
   
11,700
 
-
 
11,700
 
-
                 
Total
 
15,288
 
3,588
 
11,700
 
-
                 
(a)   Each mutual fund and common collective trust has been categorized based on its primary investment strategy.
(b)   The blended fund is a combination of the U.S. equity securities (65%) and U.S. fixed income securities (35%).

We determined the expected long-term rate of return for plan assets with input from plan actuaries and investment consultants based upon many factors including asset allocations, historical asset returns and expected future market conditions. The discount rates used by the Company for valuing pension liabilities are based on a review of high quality corporate bond yields with maturities approximating the remaining life of the projected benefit obligations.

We made $2,000,000 of discretionary contributions to the defined benefit plan in 2011.  We expect to contribute $500,000 to the defined benefit plan in 2012.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

($000)
     
       
2012
   
754
 
2013
   
1,345
 
2014
   
577
 
2015
   
2,377
 
2016
   
727
 
2017 – 2021
   
6,070
 

Effective May 9, 2008, any employees hired on and after that date were not eligible to participate in our defined benefit retirement plan.  Freezing the defined benefit plan for new entrants did not impact the level of benefits for existing participants.

We do not provide postretirement or postemployment benefits other than the pension plan for retired employees.

(b)  Employee Savings Plan   We have an Employee Savings Plan (“Savings Plan”) under which eligible employees may elect to contribute a portion of their annual compensation up to the maximum amount permitted by law. The Company matches 100% of the employee’s contribution up to a maximum company contribution of 4% of the employee’s annual compensation.  Employees hired after May 9, 2008, who are not eligible to participate in the defined benefit retirement plan, annually receive an additional 4% non-elective contribution into their Savings Plan account.  Company contributions are discretionary and subject to change with approval from our Board of Directors.  For 2011, 2010, and 2009, Delta’s Savings Plan expense was $301,000, $293,000 and  $308,000, respectively.

 
52

 
(c)  Supplemental Retirement Agreement   We sponsor a nonqualified defined contribution supplemental retirement agreement for Glenn R. Jennings, Delta’s Chairman of the Board, President and Chief Executive Officer. Delta contributes $60,000 annually into an irrevocable trust until Mr. Jennings’ retirement. At retirement, the trustee will make annual payments of $100,000 to Mr. Jennings until the trust is depleted. As of June 30, 2011 and 2010, the irrevocable trust assets are $511,000 and $373,000, respectively. These amounts are included in unamortized debt expense and other on the accompanying Consolidated Balance Sheets. Liabilities, in corresponding amounts, are included in asset retirement obligations and other on the accompanying Consolidated Balance Sheets.


(7)  Dividend Reinvestment and Stock Purchase Plan

Our Dividend Reinvestment and Stock Purchase Plan (“Reinvestment Plan”) provides that shareholders of record can reinvest dividends and also make limited additional investments of up to $50,000 per year in shares of common stock of the Company.  Under the Reinvestment Plan we issued 22,316, 16,810 and 22,287 shares in 2011, 2010 and 2009, respectively.  We registered 200,000 shares for issuance under the Reinvestment Plan in 2006, and as of June 30, 2011 there were 94,685 shares available for issuance.


(8)  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.


(9)  Notes Payable

Based on the average borrowings on our bank line of credit during 2011, a 1% (one hundred basis points) increase in our average interest rate would result in a $35,000 decrease in our annual pre-tax net income.  The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available as of June 30, 2011 and June 30, 2010.  The maximum amount borrowed during 2011 and 2010 was $7,709,000 and $13,429,000, respectively.  Effective June 30, 2011, the bank line of credit was extended through June 30, 2013.  The extension decreased the interest rate on the used line of credit from the London Interbank Offered Rate plus 1.5% to the London Interbank Offered Rate plus 1.15%.  The annual cost of the unused bank line of credit is .125%.


(10)  Long-Term Debt

In April, 2006, we issued $40,000,000 of 5.75% Insured Quarterly Notes that mature in April, 2021, of which $38,541,000 and $38,852,000 was outstanding as of June 30, 2011 and 2010, respectively.  Redemption of up to $25,000 annually will be made on behalf of individual deceased holders, up to an aggregate of $800,000 annually for all deceased beneficial owners.  The 5.75% Insured Quarterly Notes can be redeemed by us with no premium.  In the event of default on the Insured Quarterly Notes, the holders are insured for both principal and interest payments.  The insurer would continue to pay interest and principal through the maturity of the Insured Quarterly Notes.

In February, 2003 we issued $20,000,000 of 7.00% Debentures that mature in February, 2023, of which $19,410,000 and $19,460,000 was outstanding as of June 30, 2011 and 2010, respectively.  Redemption of up to $25,000 annually will be made on behalf of individual deceased holders, up to an aggregate of $400,000 annually for all deceased beneficial owners.  The 7.00% Debentures can be redeemed by us with no premium.

 
53

 
We amortize debt issuance expenses over the life of the related debt on a straight-line basis, which approximates the effective interest method.  At June 30, 2011 and 2010, the unamortized balance was $3,961,000 and $4,349,000, respectively. Loss on extinguishment of debt of $1,967,000 and $2,157,000 included in the above has been deferred as a regulatory asset and is being amortized over the term of the related debt consistent with regulatory accounting as further discussed in Note 1 of Notes to Consolidated Financial Statements.

The current portion of long-term debt of $1,200,000 represents the maximum aggregate principal amounts which can be paid to deceased beneficial owners. Therefore, the maximum maturities over the next five years are $1,200,000 each year. The Insured Quarterly Notes and Debentures do not have any sinking fund requirements.

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 or our capital stock repurchased unless after giving effect to such dividend payments or repurchases our consolidated shareholders’ equity minus the value of the Company’s intangible assets exceeds $25,800,000 (thus no retained earnings were restricted),

 
·
we may not assume any secured indebtedness in excess of $5,000,000, unless we secure our 7.00% Debentures and 5.75% Insured Quarterly Notes equally with the additional secured indebtedness, and

        ·  
without the consent of the bank that has extended to us our bank line of credit (or paying off and terminating our bank line of credit), we may not:

·  
merge with another entity,
·  
sell a material portion of our assets other than in the ordinary course of business,
·  
issue stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, or
·  
permit any person or group of related persons to hold more than twenty percent (20%) of the Company’s outstanding shares of common stock.

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.



 
54

 


(11)
Earnings per Share

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

               
               
   
2011
 
2010
 
2009
             
Numerator – Basic and Diluted
                         
Net Income ($000)
 
6,365
 
5,652
 
5,211
             
Less:  dividends paid ($000)
 
(4,562
)
(4,323
)
(4,231
)
           
                           
Undistributed earnings ($000)
 
1,803
 
1,329
 
980
             
Percentage allocated to common shares (a)
 
99.9
%
100.00
%
100.00
%
           
                           
Undistributed earnings allocated to common shares ($000)
 
1,801
 
1,329
 
980
             
Add:  dividends declared allocated to common shares ($000)
 
4,557
 
4,323
 
4,231
             
                           
Net income available to common shares ($000)
 
6,358
 
5,652
 
5,211
             
                           
Denominator  –  Basic
Weighted-average
                         
Common shares
 
3,353,612
 
3,326,160
 
3,306,026
             
Add:  Incremental unvested non-participating shares
 
2,790
 
 
             
                           
Denominator  –  Diluted
 
3,356,402
 
3,326,160
 
3,306,026
             
                           
Per common share net income ($)
                         
Basic
 
1.90
 
1.70
 
1.58
             
Diluted
 
1.90
 
1.70
 
1.58
             
                           
(a) Percentage allocated to common shares – weighted average
                         
Common shares outstanding
 
3,353,612
 
3,326,160
 
3,306,026
             
Unvested participating shares
 
4,000
 
 
             
Total
 
3,357,612
 
3,326,160
 
3,306,026
             
Percentage allocated to common shares
 
99.9
%
100.0
%
100.0
%
           
                           
Certain awards under our shareholder approved incentive compensation plan provide the recipient of the award 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.  There were 16,000 participating unvested shares outstanding as of June 30, 2011.  As of June 30, 2011, there were no non-participating unvested performance shares outstanding.  Non-participating unvested performance shares would be included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including such shares is antidilutive.  There were no antidilutive shares in 2011.



 
55

 

(12)  Operating Leases

We have no non-cancellable operating leases. Our operating leases relate primarily to well and compressor station site leases and are cancellable at our option. Rental expense under operating leases was $72,000, $74,000 and $78,000 for the years ended June 30, 2011, 2010 and 2009, respectively.


(13)  Commitments and Contingencies

We have entered into forward purchase agreements beginning in July, 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.  These agreements have aggregate minimum purchase obligations of $218,000 for our fiscal year ended June 30, 2012.

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and Change of 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 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.  Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 18 and Note 20 of Notes to 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 billing by a utility and is passed through to its customers.  Delta Resources is a natural gas marketer and not a utility regulated by the Kentucky Public Service Commission.  Since case law in the state of Kentucky and opinions issued by the State Attorney General support that the Utility Gross Receipts License Tax is applicable only to regulated utilities, we believe Delta Resources is exempt from the tax.  We have protested the assessment, but cannot currently predict the outcome of the protest.  As of June 30, 2011, we have not accrued any amounts related to this assessment.

Although the Kentucky Department of Revenue has not asserted a claim for the interest accrued subsequent to the date of the assessments, we have calculated that unasserted liabilities for interest approximate $132,000.

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.

In January, 2011, we filed a lawsuit 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, as further discussed in Note 16 of the Notes to Consolidated Financial Statements.  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 believed 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.  Delta and Chartis filed motions on the issue of which party has the burden of proof with respect to the cause of the gas loss.  In May, 2011 the Court ruled on the motion citing that Delta has the burden of proof to demonstrate the loss was caused by an external factor.  Although the matter is currently in litigation, we have also engaged in settlement discussions with Chartis.  We are unable to predict the outcome of this legal proceeding or the settlement discussions.

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

 
56

 

(14)  Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services.  The Kentucky Public Service Commission’s regulation of our business includes setting the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our natural gas and transportation services.  The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return.

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

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 rates, our pipe replacement program was approved in our 2010 rate case.  Our pipe replacement program allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to the test year which are associated with the replacement of pipe and related facilities.  The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.  In February, 2011, the Kentucky Public Service Commission approved our initial pipe replacement filing, effective May, 2011, which will provide us $139,000 in additional annual revenues.

The Kentucky Public Service Commission allows us a conservation and efficiency program for our residential customers.  The program provides for us to perform energy audits, promote conservation awareness and provide rebates on the purchase of certain high-efficiency appliances.  The program helps to align our interests with our residential customer's interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation.  Our rates are adjusted annually to recover the costs incurred under these programs, including the reimbursement of margins on lost sales and the incentives provided to us.

The Kentucky Public Service Commission allows us a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs. Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission.  Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred.  In our general rate case, the Kentucky Public Service Commission approved a change to our gas cost recovery clause, effective January, 2011, allowing us to recover the uncollectible gas cost portion of bad debt expense as a component of the gas cost recovery adjustment.

Additionally, we have a weather normalization provision in our tariffs, approved by the Kentucky Public Service Commission, which allows us to adjust our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles.  These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts.

In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise.  We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, the areas served do not have governmental organizations authorized to grant franchises or the city governments do not require a franchise.  We attempt to acquire or reacquire franchises whenever feasible.  Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city.  To date, the absence of a franchise has caused no adverse effect on our operations.

 
57

 

(15)  Operating Segments

Our Company has two segments:  (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which 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 revenues recorded under both segments come from the sale or transportation of natural gas. Price risk for the regulated business is mitigated through our gas cost recovery clause, approved quarterly by the Kentucky Public Service Commission.  Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand.  However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict our demand. In addition, we are exposed to changes in the market price of gas on uncommitted gas volumes of our non-regulated companies.

In our non-regulated segment two customers each provided more than 5% of our operating revenues.  Our largest customer provided $11,461,000, $6,722,000 and $4,285,000 of non-regulated revenues during 2011, 2010 and 2009, respectively.  Our second largest customer provided $8,067,000 and $5,097,000 of non-regulated revenues during 2011 and 2010, respectively.  There is no assurance that revenues from these customers will continue at these levels.

In 2011, 2010 and 2009, we purchased approximately 99% of our natural gas from Atmos Energy Marketing and M & B Gas Services.

The segments follow the accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements. Intersegment revenues and expenses consist of intercompany revenues and expenses from intercompany gas transportation and gas storage services. Intersegment transportation revenues and expenses are recorded at our tariff rates. Revenues and expenses for the storage of natural gas are recorded based on quantities stored. Operating expenses, taxes and interest are allocated to the non-regulated segment.  Segment information is shown in the following table:

 ($000)
 
 
2011
 
2010
 
2009
 
Operating Revenues
             
Regulated
             
External customers
 
48,697
 
45,676
 
64,479
 
Intersegment
 
3,777
 
3,441
 
3,427
 
Total regulated
 
52,474
 
49,117
 
67,906
 
Non-regulated
             
External customers
 
34,343
 
30,746
 
41,158
 
Eliminations for intersegment
 
(3,777
)
(3,441
)
(3,427
)
Total operating revenues
 
83,040
 
76,422
 
105,637
 
               
Operating Expenses
             
Regulated
             
Purchased gas
 
21,078
 
20,518
 
39,138
 
Depreciation
 
5,037
 
3,823
 
3,737
 
Other
 
14,318
 
15,105
 
15,246
 
Total regulated
 
40,433
 
39,446
 
58,121
 
Non-regulated
             
Purchased gas
 
26,762
 
23,582
 
32,940
 
Depreciation
 
120
 
118
 
118
 
Other
 
5,440
 
3,813
 
5,092
 
Total non-regulated
 
32,322
 
27,513
 
38,150
 
Eliminations for intersegment
 
(3,777
)
(3,441
)
(3,427
)
Total operating expenses
 
68,978
 
63,518
 
92,844
 
               
 
 
58

 
($000)
 
2011
 
2010
 
2009
 
Other Income and Deductions, Net
             
Regulated
 
153
 
108
 
(50
)
Non-regulated
 
(1
)
 
4
 
Total other income and deductions
 
152
 
108
 
(46
)
               
Interest Charges
             
Regulated
 
4,029
 
4,055
 
4,305
 
Non-regulated
 
60
 
114
 
223
 
Total interest charges
 
4,089
 
4,169
 
4,528
 

Income Tax Expense
             
Regulated
 
3,012
 
2,008
 
1,949
 
Non-regulated
 
748
 
1,184
 
1,059
 
Total income tax expense
 
3,760
 
3,192
 
3,008
 
               
Net Income
             
Regulated
 
5,153
 
3,717
 
3,479
 
Non-regulated
 
1,212
 
1,935
 
1,732
 
Total net income
 
6,365
 
5,652
 
5,211
 
               
Assets
             
Regulated
 
168,997
 
164,871
 
154,297
 
Non-regulated
 
5,899
 
3,761
 
8,208
 
Total assets
 
174,896
 
168,632
 
162,505
 
               
Capital Expenditures
             
Regulated
 
8,120
 
5,275
 
8,422
 
Non-regulated
 
3
 
 
 
Total capital expenditures
 
8,123
 
5,275
 
8,422
 


(16)         Gas in Storage Inventory Adjustment

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

Fiscal 2009 storage field data suggested that an inventory adjustment was required related to a storage well that allowed natural gas to escape.  After analyzing the data, we recorded an adjustment of $1,350,000.  The adjustment was included in operation and maintenance expense in the 2009 Consolidated Statement of Income.

In March, 2009, we filed an insurance claim for $1,350,000 relating to the escaped gas.  As of June 30, 2011, we have not received any insurance proceeds and are currently in litigation with our insurance carrier, as further discussed in Note 13 of the Notes to Consolidated Financial Statements.


(17)        Sale of Property, Plant and Equipment

During 2009, we sold two surplus office buildings for $335,000, which resulted in us recording $156,000 of gains on the sales.  The gains are included in operation and maintenance expense in the 2009 Consolidated Statement of Income.



 
59

 


(18)
Share-Based Compensation

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

The number of shares of our common stock which may be issued pursuant to the Plan may not exceed in the aggregate 500,000 shares.  As of June 30, 2011, 475,000 shares of common stock were available for issuance under the Plan.  Shares of common stock may be available from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market. 

Compensation expense for share-based compensation is recorded in operation and maintenance expense in the Consolidated Statement 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 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 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.

               
               
 
($000)
2011
 
2010
                 
                           
 
Share-based compensation expense
527
 
                 
                           
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 during 2011, which increased our taxes payable.

In August, 2010, shares of common stock were awarded to virtually all of Delta’s employees and directors in accordance with the Plan.  The 9,000 shares awarded had a grant date fair value of $264,000 at $29.33 per share.  The recipients vested in the awards shortly after the awards were 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.  The maximum which could be issued under the performance awards was 16,000 shares, which had a grant date fair value of $469,000 ($29.33 per share).  The performance share awards vest only if the performance objective of the awards is met, which was based on the Company's fiscal 2011 earnings per common share, before any cash bonuses or stock awards.  As of June 30, 2011, the performance objective has been satisfied and subject to further limitations described in the Incentive Compensation Plan and the Notice of Performance Shares Awards, 16,000 shares will be paid in the form of unvested shares, which contain a service condition whereby 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.   Compensation expense of $263,000 was recognized during 2011 related to these awards and a remaining $206,000 of compensation expense is expected to be recognized between 2012 and 2014.

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 objective.

Since the performance condition has been satisfied, 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 June 30, 2011 is 2.2 years.  Holders of performance shares may not sell, transfer, or pledge their shares until the shares vest.

 
60

 
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 June 30, 2011
 
16,000
 
$          29.33
         
                     
(1)  
Represents the maximum number of shares which could be issued based on achieving the performance criteria.


 (19)           Quarterly Financial Data (Unaudited)

The quarterly data reflects, in the opinion of management, all normal recurring adjustments necessary to present fairly the results for the interim periods.
 
 
 
 
 
Quarter Ended
 
Operating
Revenues
 
 
 
 
Operating
Income
 
 
 
 
Net Income
(Loss)
 
Basic
Earnings (Loss)
per Common
Share
   
 
Diluted
Earnings (Loss) per Common Share
 
                         
Fiscal 2011
                               
                                 
September 30
 
$
10,016,478
 
$
234,448
 
$
(416,177
)
$
(.12
)
$
(.12
)
December 31
   
23,756,304
   
5,282,172
   
2,694,024
   
.80
   
.80
 
March 31
   
35,355,010
   
7,945,879
   
4,331,090
   
1.29
   
1.29
 
June 30
   
13,912,459
   
599,295
   
(244,042
)
 
(.07
)
 
(.07
)
                                 
                                 
Fiscal 2010
                               
                                 
September 30
 
$
8,130,950
 
$
40,540
 
$
(563,004
)
$
(.17
)
$
(.17
)
December 31
   
21,114,433
   
4,086,010
   
1,912,875
   
.58
   
.58
 
March 31
   
36,090,839
   
7,779,167
   
4,332,078
   
1.30
   
1.30
 
June 30
   
11,085,846
   
998,777
   
(30,132
)
 
(.01
)
 
(.01
)
                                 



 
61

 

 
 (20)           Subsequent Events

In August, 2011, 11,000 shares were awarded as a stock bonus for employees and officers and as equity compensation for members of the Board of Directors, which had a grant date fair value of $337,000.  Additionally, in August, 2011, performance shares were awarded to the Company’s executive officers.  The performance share awards will vest only if the performance objective of the awards is met, which is based on the Company’s fiscal 2012 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 Share Awards, all performance shares paid shall be in the form of unvested shares, which contain a service condition whereby recipients of the awards shall vest in one-third increments each year beginning on August 31, 2012, and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period.  The maximum number of shares which could be issued under the performance awards is 18,000, having a grant date fair value of $552,000.


 
62

 


 


SCHEDULE II


DELTA NATURAL GAS COMPANY, INC.
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED JUNE 30, 2011, 2010 and 2009


Column A
 
Column B
 
Column C
 
Column D
 
Column E
 
       
Additions
 
Deductions
     
                       
           
Charged to
         
   
Balance at
 
Charged to
 
Other
 
Amounts
     
   
Beginning of
 
Costs and
 
Accounts –
 
Charged Off 
 
Balance at
 
Description
 
Period
 
Expenses
 
Recoveries
 
Or Paid
 
End of Period
 
                       
Deducted From the Asset to 
Which it Applies –
Allowance for doubtful 
accounts for the years ended:
                     
                                 
June 30, 2011
 
$
273,000
 
$
67,359
 
$
170,810
 
$
321,169
 
$
190,000
 
June 30, 2010
   
819,000
   
(163,088
)
 
71,866
   
454,778
   
273,000
 
June 30, 2009
   
465,000
   
830,588
   
67,803
   
544,391
   
819,000