10-K 1 dgas-2013630x10k.htm 10-K DGAS-2013.6.30-10K


 
 
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, 2013
o
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.   T
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.  $133,911,811.
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, 2013, Delta Natural Gas Company, Inc. had outstanding 6,864,611 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, 2013, is incorporated by reference in Part III of this Report.
 
 





TABLE OF CONTENTS
 
 
 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 

1



PART I

Item 1.     Business

General -

Delta Natural Gas Company, Inc. (Nasdaq: DGAS) distributes or transports natural gas to approximately 36,000 customers. Our distribution and transmission pipeline systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system and sell liquids extracted from natural gas in our storage field and on our pipeline systems. We have three wholly-owned subsidiaries. Delta Resources, Inc. (“Delta Resources”) buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. (“Delgasco”) buys natural gas and resells it to Delta Resources and to customers not on Delta's system. Enpro, Inc. (“Enpro”) owns and operates production properties and undeveloped acreage.

References to “Delta”, “the Company”, “we”, “us” and “our” refer to Delta Natural Gas Company, Inc. and its consolidated subsidiaries, except as otherwise stated. We were incorporated under the laws of the Commonwealth of Kentucky on October 7, 1949.

Unless otherwise stated, “2013”, “2012” and “2011” refers to the respective twelve month periods ending June 30.

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, producing and processing 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, we will continue a conservative strategy of minimizing our exposure to market risk arising from fluctuations in the prices of natural 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 natural gas to industrial customers on our system who purchase their natural gas in the open market. Our regulated segment also transports natural 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 retail natural gas distribution and transportation services. Their regulation of our business includes approving the rates we are permitted to charge our regulated

2



customers. The impact of this regulation is further discussed in Note 14 of the Notes to Consolidated Financial Statements, in Item 8. Financial Statements and Supplementary Data and under “Regulatory Matters” in Item 1. Business.

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 weather has on our regulated revenues as our rates include both a fixed monthly customer charge and a volumetric rate which has a weather normalization provision that adjusts rates due to variations in weather. Market risk arising from fluctuations in the price of gas is mitigated through the gas cost recovery rate mechanism which 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 natural gas we sell is used for heating. During 2013, 73% 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, wood and solar.

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 natural 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 seek 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. 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 natural gas transmission and distribution system and customer base. We continue to consider acquisitions of other natural 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 natural gas for our customers. We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2013, we purchased approximately 98% 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. We are not obligated to purchase any minimum quantities from Atmos or purchase natural gas from them for any period longer than one month at a time. The natural 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 each month in Platts' Inside FERC's Gas Market Report for 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 natural 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 canceled by either party by written notice at least sixty days prior to the annual anniversary date (April

3



30) of the agreement. In our fiscal year ended June 30, 2013, approximately 61% of our regulated gas supply was purchased under our agreements with Atmos.

Our regulated segment purchases natural gas from M&B Gas Services ("M&B") and Midwest Energy Services, LLC ("Midwest") 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 either M&B or Midwest, nor are we required to purchase natural gas from either company for any periods longer than one month at a time. The natural gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices. Our agreement with both M&B and Midwest may be terminated upon 30 days prior written notice by either party. In our fiscal year ended June 30, 2013, approximately 23% and 14% of our regulated gas supply was purchased under our agreements with M&B and Midwest, respectively.

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 currently extend through October, 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. We intend to renew our agreements with Tennessee. 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 2013, Tennessee transported for us a total of 884,000 Mcf, or approximately 17% of our regulated supply requirements, under these agreements. 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 2013, Columbia Gas and Columbia Gulf transported for us a total of 2,192,000 Mcf, or approximately 43% 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, but may be extended by mutual agreement.

Columbia Gulf also transported additional volumes under agreements it has with M & B and Midwest 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 agreements Columbia Gulf has with M & B and Midwest for fiscal 2013 constituted approximately 37% 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 Atmos to supply our customers' requirements in specific geographic areas. In our fiscal year ended June 30, 2013, 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 41,000 Mcf from Vinland during fiscal 2013. 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 Platts' Inside FERC's Gas Market Report. Vinland delivers this gas to our customer meters directly from its own pipelines. In fiscal 2013, the natural gas we purchased from Vinland constituted approximately 1% of our regulated gas supply.

Gas in Storage

We own and operate an underground natural gas storage field that we use to store a significant portion of our 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. We have a legal obligation to retire wells located at this underground natural gas storage facility.

4



However, since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the wells have an indeterminate life and have therefore not recorded a liability associated with the cost to retire the wells.

Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. Their regulation of our business includes approving the rates we are permitted to charge our regulated customers. We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services. They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return. We do not have any matters pending before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial positions or cash flows.

We have a pipe replacement program which allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to our last rate case which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.

The 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 and any bad debt expense related to gas cost. 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.

Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which provides for the adjustment of 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. Through this program, we 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 customers' 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, the reimbursement of margins on lost sales and the incentives provided to us.

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, there are no 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 not adversely affected our operations.


Non-Regulated Operations

Natural Gas Marketing

Our non-regulated segment includes 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.

Factors that affect our non-regulated revenues include the 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

5



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.

In our fiscal year ended June 30, 2013, approximately 96% of our non-regulated revenue was derived from our natural gas marketing activities. In our non-regulated segment, two customers each provided more than 5% of our operating revenues. Seminole Energy provided approximately $17,866,000, $12,450,000 and $11,461,000 of non-regulated revenues during 2013, 2012 and 2011, respectively. Atmos provided approximately $5,390,000, $6,815,000 and $8,067,000 of non-regulated revenues during 2013, 2012 and 2011, respectively. There is no assurance that revenues from these customers will continue at these levels.

Natural Gas Production

Our subsidiary, Enpro, produces natural gas that is sold to Delgasco for resale in the open market. Item 2. Properties further describes Enpro's oil and natural gas leases and production properties. Enpro produced a total of 103,000 Mcf of natural gas during 2013 which was approximately 1% of the non-regulated volumes sold.

Natural Gas Liquids

In order to improve the operations of our distribution, transmission and storage system, we operate a facility that is designed to extract liquids from the natural gas in our system. We sell these natural gas liquids at a price determined by a national unregulated market. In our fiscal year ended June 30, 2013, approximately 4% of our non-regulated revenue was derived from the sale of natural gas liquids.

Gas Supply

      Our non-regulated segment purchases natural gas from M&B and Midwest. Our underlying agreements with M&B and Midwest do not obligate us to purchase any minimum quantities from M&B or Midwest, nor to purchase gas from either company 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 agreements with both M&B and Midwest 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, 2013, 50% and 6% of our non-regulated gas supply was purchased under our agreements with M&B and Midwest, respectively.

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, 2013, approximately 43% 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.

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


Capital Expenditures

Capital expenditures during 2013 were $7.2 million and for 2014 are estimated to be $7.8 million. Our expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities.


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, 2013.


6



Our current bank line of credit extends through June 30, 2015 and will be utilized to meet capital expenditure 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.

We currently have long-term debt of $56,500,000 in the form of our Series A Notes. The Series A Notes are unsecured, bear interest at 4.26% per annum and mature on December 20, 2031. Accrued interest on the Series A Notes is payable quarterly and we are required to make a $1,500,000 principal reduction payment on the Series A Notes each December.
 

Employees

On June 30, 2013, we had 150 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,
2013
 
2012
 
2011
 
2010
 
2009
 
 
 
 
 
 
 
 
 
 
Average Regulated Customers Served
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
29,755

 
29,929

 
30,420

 
30,575

 
30,881

Commercial
4,906

 
4,890

 
4,949

 
4,957

 
5,009

Industrial
40

 
41

 
44

 
46

 
49

 
 
 
 
 
 
 
 
 
 
Total
34,701

 
34,860

 
35,413

 
35,578

 
35,939

 
 
 
 
 
 
 
 
 
 
Operating Revenues ($000) (a)
 
 
 
 
 
 
 
 
 
Regulated (b)
 
 
 
 
 
 
 
 
 
Residential sales
24,342

 
22,720

 
25,800

 
23,783

 
33,774

Commercial sales
15,849

 
14,026

 
16,672

 
15,894

 
24,125

Industrial sales
1,011

 
914

 
1,199

 
1,075

 
1,769

On-system transportation
5,237

 
4,780

 
4,830

 
4,421

 
4,118

Off-system transportation
3,800

 
3,595

 
3,670

 
3,650

 
3,786

Other
333

 
324

 
303

 
294

 
333

Total regulated revenues
50,572

 
46,359

 
52,474

 
49,117

 
67,905

 
 
 
 
 
 
 
 
 
 
Non-regulated sales
34,238

 
31,423

 
34,343

 
30,746

 
41,159

Intersegment eliminations (c)
(4,145
)
 
(3,704
)
 
(3,777
)
 
(3,441
)
 
(3,427
)
 
 
 
 
 
 
 
 
 
 
Total
80,665

 
74,078

 
83,040

 
76,422

 
105,637

 
 
 
 
 
 
 
 
 
 
System Throughput (Million Cu. Ft.) (a)
 
 
 
 
 
 
 
 
 
Regulated
 
 
 
 
 
 
 
 
 
Residential sales
1,659

 
1,331

 
1,737

 
1,756

 
1,721

Commercial sales
1,291

 
1,027

 
1,310

 
1,331

 
1,346

Industrial sales
107

 
90

 
120

 
111

 
113

On-system transportation
4,988

 
4,724

 
4,830

 
4,533

 
4,215

Off-system transportation
11,795

 
11,225

 
11,531

 
11,039

 
11,908

Total regulated throughput
19,840

 
18,397

 
19,528

 
18,770

 
19,303

 
 
 
 
 
 
 
 
 
 
Non-regulated sales
7,650

 
6,455

 
6,010

 
4,787

 
4,219

Intersegment eliminations (c)
(7,497
)
 
(6,326
)
 
(5,890
)
 
(4,692
)
 
(4,135
)
 
 
 
 
 
 
 
 
 
 
Total
19,993

 
18,526

 
19,648

 
18,865

 
19,387

 
 
 
 
 
 
 
 
 
 
Average Annual Consumption Per
 
 
 
 
 
 
 
 
 
Average Residential Customer
 
 
 
 
 
 
 
 
 
 (Thousand Cu. Ft.)
56

 
44

 
57

 
57

 
56

 
 
 
 
 
 
 
 
 
 
Lexington, Kentucky Degree Days
 
 
 
 
 
 
 
 
 
Actual
4,667

 
3,797

 
4,725

 
4,782

 
4,651

Percent of 30 year average
104

 
83

 
103

 
104

 
101

(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, 2010, which were designed to generate additional annual revenue of $3,513,000.
(c)  Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates.

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 73% 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 2013, approximately 98% 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. A decrease in available pipeline capacity or decrease in natural gas available to us could result in a loss of customers and decrease in profits.

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. A decrease in our normal interstate supply of gas could result in a loss of customers and decrease in profits.

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.

ACTIONS BY OUR REGULATORS COULD DECREASE FUTURE PROFITABILITY.

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. Additionally, our consolidated financial statements reflect the application of regulatory accounting standards by our regulated segment. Our regulated segment has recognized regulatory assets representing costs incurred in prior periods that are probable of recovery from customers in future rates. Disallowance of such costs in future proceedings before the Kentucky Public Service Commission could require us to write-off regulatory assets, which could have a material impact on our income and consolidated financial statements.

VOLATILITY IN PRICES COULD REDUCE OUR PROFITS.

Significant increases in the price of natural gas will likely cause our regulated retail customers to increase conservation 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

9



gas will likely cause our non-regulated segment's gross margins to decrease. The price of natural gas liquids is determined by a national unregulated market, and decreases in the price could result in a decrease in our non-regulated gross margins.

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.

A DECLINE IN THE LIQUIDS PRESENT IN OUR NATURAL GAS SUPPLY COULD REDUCE OUR NON-REGULATED REVENUES.

In order to improve the operations of our distribution, transmission and storage system, we operate a facility that is designed to extract liquids from the natural gas in our system. We are able to sell these liquids at a price determined by a national unregulated market. A reduction in the quantity of liquids present in our gas supply could result in a reduction of the earnings of our non-regulated segment.

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. 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. There is no guarantee we could obtain needed capital in the future.

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 level of the plan, 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, TRANSPORTATION, LIQUIDS EXTRACTION 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, liquids extraction 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,

10



landslides or other similar events beyond our control. These risks could result in injury or loss of life, extensive property damage or 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, 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.

OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS FINANCIAL AND NEGATIVE COVENANTS AND A PREPAYMENT PENALTY THAT COULD RESTRICT OUR ACTIVITIES.

Our bank line of credit and Series A Notes contain financial covenants. Noncompliance with these covenants can make the obligations immediately due and payable. If we breach any of the financial covenants under these agreements, our debt repayment obligations under the bank line of credit and Series A Notes could be accelerated. In such event, we may not be able to refinance, repay all our indebtedness, pay dividends or have sufficient liquidity to meet our operating and capital expenditure requirements, all of which could result in a material adverse effect on our business, results of operations and financial condition. Furthermore, a default on the performance of any single obligation incurred in connection with our borrowings, or a default on other indebtedness that exceeds $2,500,000, simultaneously creates an event of default with the bank line of credit and the Series A Notes. Additionally, our bank line of credit and Series A Notes contain various negative covenants and a prepayment penalty which create a risk that we may be unable to take advantage of business and financing opportunities as they arise.

OUR LONG-TERM DEBT ARRANGEMENTS LIMIT THE AMOUNT OF DIVIDENDS WE MAY PAY AND OUR REPURCHASE OF STOCK.

Under the terms of our 4.26% Series A Notes, the aggregate amount we may pay in dividends on our common stock and in repurchase of our common stock may not exceed the sum of $15,000,000 and our cumulative net income after September 30, 2011. Between September 30, 2011 and June 30, 2013, we paid $8,526,000 in dividends, repurchased no stock and have had cumulative net income of $13,318,000. Consequently, as of June 30, 2013 our Series A Notes permitted us to pay up to $19,792,000 in dividends and for the repurchase of our common stock. However, if we fail to generate sufficient net income in the future, our ability to continue to pay our regular quarterly dividend may be impaired and the value of our common stock would likely decline.

A SECURITY BREACH COULD DISRUPT OUR IT SYSTEMS, INTERRUPT THE NATURAL GAS SERVICE WE PROVIDE TO OUR CUSTOMERS, COMPROMISE THE SAFETY OF OUR NATURAL GAS DISTRIBUTION, TRANSMISSION AND STORAGE SYSTEMS OR EXPOSE CONFIDENTIAL PERSONAL INFORMATION.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to IT system disruptions or shutdowns, result in the interruption of our ability to provide natural gas to our customers or compromise the safety of our distribution, transmission and storage systems. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

Additionally, the protection of customer, employee, vendor, investor and company data is critical to us. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. There is no guarantee that the procedures that we have implemented to protect against unauthorized access to secured data are adequate to safeguard against all data security breaches.

FAILURE TO ATTRACT AND RETAIN AN APPROPRIATELY QUALIFIED WORKFORCE COULD UNFAVORABLY IMPACT OUR RESULTS OF OPERATIONS.

Certain events, such as an aging workforce, mismatch of skill sets to complement future needs, or unavailability of future resources, may lead to increased operational risks and costs. As a result of these events, we could face lack of resources knowledgeable about the natural gas industry and a lengthy time period associated with skill development and knowledge transfer.

11



Failure to address this risk may result in increased operational and safety risks as well as increased costs. Even if we have reasonable plans in place to address succession planning and workforce training, we cannot control the future availability of qualified labor. If we are unable to successfully attract and retain an appropriately qualified workforce, our financial position or results of operations could be negatively affected.

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, adoption of International Financial Reporting 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 the costs of 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.


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 2.7 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 103,000 Mcf of natural gas during fiscal 2013 from all the properties described in this paragraph.

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

12




Our assets have no significant encumbrances.


Item 3.   Legal Proceedings

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


Item 4.     Mine Safety Disclosures

None.

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 our Series A Notes 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 1,537 record holders of our common stock as of August 27, 2013. 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 2013






First

24.82

18.41

0.18
Second

22.16

17.08

0.18
Third

22.08

18.88

0.18
Fourth

24.18

19.99

0.18







Fiscal 2012






First

16.98

14.51

0.175
Second

17.24

14.12

0.175
Third

19.61

16.72

0.175
Fourth

23.15

18.83

0.175

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 returns (equal to dividends plus stock price appreciation) among our common shares, the Dow Jones Utilities Index, the Russell 3000 Stock 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, 2008 in each of our common shares, the Dow Jones Utilities Index, the Russell 3000 Stock Index and the Standard & Poor's 500 Stock Index. Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.



2008

2009

2010

2011

2012

2013












Delta
100

91

121

140

199

201












Dow Jones Utilities Index
100

72

75

95

110

116












Standard & Poor's 500 Stock Index
100

74

84

110

116

140
 
 
 
 
 
 
 
 
 
 
 
 
Russell 3000 Stock Index
100
 
73
 
85
 
112
 
117
 
142

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.
For the Years Ended June 30,
2013

2012

2011

2010

2009
 










Summary of Operations ($)










 










Operating revenues (a)
80,664,837


74,078,322

83,040,251

76,422,068

105,636,824
 










Operating income (a)(b)(c)
13,188,679


13,265,228

14,061,794

12,904,494

12,793,200
 










Net income (a)(b)(c)
7,200,776


5,783,998

6,364,895

5,651,817

5,210,729
 










Earnings per common share (a)(b)(c)










Basic and diluted
1.05


0.85

0.95

0.85

0.79
 










Cash dividends declared per common share
0.72


0.70

0.68

0.65

0.64
 










Weighted Average Number of Common Shares










Basic
6,843,455


6,777,186

6,707,224

6,652,320

6,612,052
Diluted
6,843,455


6,777,186

6,712,804

6,652,320

6,612,052
 










Total Assets ($)
183,930,015


182,895,363

174,896,239

168,632,420

162,505,295
 










Capitalization ($)










 










Common shareholders' equity
70,005,415


66,220,407

63,767,184

60,760,170

58,999,182
 










Long-term debt
55,000,000


56,500,000

56,751,006

57,112,000

57,599,000
 










Total capitalization
125,005,415


122,720,407

120,518,190

117,872,170

116,598,182
 










Short-Term Debt ($) (d)
1,500,000


1,500,000

1,200,000

1,200,000

4,853,103
 










Other Items ($)










 










Capital expenditures
7,179,473


7,337,115

8,123,479

5,275,194

8,422,433
 










Total property, plant and equipment
223,545,925


217,172,542

211,409,336

204,248,520

199,254,216

(a)
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.
(b)
We recorded a non-recurring $1,350,000 gas in storage inventory adjustment at December 31, 2008.
(c)
In 2012, $877,000 of interest expense was accrued relating to a tax assessment. In 2013, the assessment was resolved and the previously accrued interest was reversed.
(d)
Includes current portion of long-term debt.

15



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

Overview of 2013 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 2013. Our Company has two segments: (i) a regulated natural gas distribution and transmission segment, and (ii) a non-regulated segment which participates in related activities, consisting of natural gas marketing, natural gas production and the sale of liquids extracted from natural gas.

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 markets natural gas to large-use customers both on and off our regulated system. We endeavor to enter sales agreements matching supply with estimated demand while providing an acceptable gross margin. The non-regulated segment also produces natural gas and sells liquids extracted from natural gas.

Consolidated earnings per common share for 2013 increased $0.20 per common share as compared to 2012. We experienced a winter that was significantly colder than the preceding year resulting in increased volumes of natural gas sold as well as increased volumes transported by our regulated segment. Also, decreased interest expense resulting from the resolution of a tax assessment issued to Delta Resources (as further discussed in Note 13 of the Notes to Consolidated Financial Statements) had a positive impact on earnings. Other factors which influenced our 2013 consolidated earnings per common share are further discussed in the Results of Operations.

Future Outlook

Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers. The Kentucky Public Service Commission sets these rates, and we monitor our need to file rate cases with the Kentucky Public Service Commission for a general rate increase for our regulated services. The regulated segment's largest expense is gas supply, which we are permitted to pass through to our customers. We manage 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 and natural gas liquids, 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 2014. 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. The profitability of selling natural gas liquids is dependent on the amount of liquids extracted and the pricing for any such liquids is determined by a national unregulated market.


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, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit. The current bank line of credit with Branch Banking and Trust Company

16



permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of June 30, 2013 or June 30, 2012 and we did not draw on this bank line of credit during 2013.

Cash and cash equivalents were $10,360,000 at June 30, 2013 compared with $9,741,000 at June 30, 2012 and $7,340,000 at June 30, 2011. These changes in cash and cash equivalents are summarized in the following table:
$(000)
2013
 
2012
 
2011
 
 
 
 
 
 
Provided by operating activities
13,557

 
13,514

 
14,467

Used in investing activities
(7,108
)
 
(7,012
)
 
(7,520
)
Used in financing activities
(5,829
)
 
(4,102
)
 
(4,246
)
 
 
 
 
 
 
      Increase in cash and cash equivalents
620

 
2,400

 
2,701


In 2013, there was not a significant change in cash provided by operating activities as compared to 2012.

In 2012, there was not a significant change in cash provided by operating activities as compared to 2011.

Changes in cash used in investing activities result primarily from changes in the level of capital expenditures between years.
    
In 2013, cash used in financing activities increased $1,727,000 (42%), as compared to 2012, due to a $1,500,000 repayment on our 4.26% Series A Notes.

In 2012, there was not a significant change in cash used in financing activities as compared to 2011.

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 2014 to be approximately $7.8 million.
    
The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2013:
 
 
Payments Due by Fiscal Year
$(000)
 
2014

2015 - 2016

2017 - 2018

After 2018

Total
Interest payments (a)
 
2,428


4,554


4,299


22,302


33,583

Long-term debt (b)
 
1,500


3,000


3,000


49,000


56,500

Pension contributions (c)
 
500


1,000


1,000


4,500


7,000

Gas purchases (d)
 
328








328

Total contractual obligations (e)
 
4,756


8,554


8,299


75,802


97,411


(a)
Our long-term debt, notes payable, customers' deposits and unrecognized tax positions all require interest payments. Interest payments are projected based on fiscal 2013 interest payments until the underlying obligation is satisfied. As of June 30, 2013, we have also accrued $9,000 of interest related to uncertain tax positions. These amounts have 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.

(c)
This represents currently projected contributions to the defined benefit plan through 2026, as recommended by our actuary.

(d)
As of June 30, 2013, we had three contracts which had minimum purchase obligations. These contracts have various terms with the last contract expiring December, 2013. 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.

17




(e)
We have other long-term liabilities which include deferred income taxes ($39,624,000), regulatory liabilities ($1,253,000), asset retirement obligations ($3,547,000) and deferred compensation ($739,000). 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

Our ability to maintain liquidity, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated rates we charge our customers. The Kentucky Public Service Commission sets these rates and we monitor our need to file for rate increases for our regulated segment. Our regulated base rates were most recently adjusted in our 2010 rate case and became effective in October, 2010. We expect that cash provided by operations will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months and the foreseeable future.

To the extent that internally generated cash is not sufficient to satisfy seasonal operating and capital expenditure requirements and to pay dividends, we rely on our bank line of credit. Our current available bank line of credit with Branch Banking and Trust Company extends through June 30, 2015 and permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit during 2013 as we did not draw upon this bank line of credit during 2013.

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

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031.  We are required to make an annual $1,500,000 principal payment on the Series A Notes each December.  Any refinance of the Series A Notes, or any additional prepayments of principal, may be subject to a prepayment penalty.

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

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

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

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

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

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

18




The following table shows the required and actual financial covenants under our Series A Notes as of June 30, 2013:
Requirement
 
Actual
 
 
 
 
 
 
Tangible net worth
no less than $25,800,000
 
$
68,674,245

 
Debt to capitalization ratio
no more than 70%
 
45
%
 
Fixed charge coverage ratio
no less than 1.20x
 
7.75

x
Dividends paid
no more than $28,318,000
 
$
8,526,000

 

Our 4.26% Series A Notes restrict us from:

with limited exceptions, granting or permitting liens on or security interests in our properties,

selling a subsidiary, except in limited circumstances,

incurring secured debt, or permitting a subsidiary to incur debt or issue preferred stock to any third party, in an aggregate amount that exceeds 10% of our tangible net worth,

changing the general nature of our business,

merging with another company, unless (i) we are the survivor of the merger or the survivor of the merger is another domestic company that assumes the 4.26% Series A Notes, (ii) there is no event of default under the 4.26% Series A Notes and (iii) the continuing company has a tangible net worth at least as high as our tangible net worth immediately prior to such merger, or

selling or transferring assets, other than (i) the sale of inventory in the ordinary course of business, (ii) the transfer of obsolete equipment and (iii) the transfer of other assets in any 12 month period where such assets constitute no more than 5% of the value of our tangible assets and, over any period of time, the cumulative value of all assets transferred may not exceed 15% of our tangible assets.

Without the consent of the bank that has extended to us our bank line of credit or 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 stock.

Furthermore, the agreement governing our 4.26% Series A Notes contains a cross-default provision which provides that we will be in default under the 4.26% Series A Notes if we are in default on any other outstanding indebtedness that exceeds $2,500,000. Similarly, the loan agreement governing the bank line of credit contains a cross-default provision which provides that we will be in default under the bank line of credit if we are in default under our 4.26% Series A Notes and fail to cure the default within ten days of notice from the bank. We were in compliance with the covenants under our bank line of credit and 4.26% Series A Notes for all periods presented in the Consolidated Financial Statements.


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

19



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.

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 is appropriate. 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 the Kentucky Public Service Commission 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. The net periodic benefit costs (“pension costs”) for our defined benefit plan as described in Note 6 of the Notes to Consolidated Financial Statements are dependent upon numerous factors resulting from actual plan experience and assumptions concerning future experience. These costs, 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. For the years ended June 30, 2013, 2012 and 2011, we recorded pension costs for our defined benefit pension plan of $980,000, $481,000 and $1,129,000, respectively.

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. As of June 30, 2013, $6,369,000 of net losses have been deferred for amortization as pension costs into future periods.

Our pension plan assets are principally comprised of equity and fixed income investments. Differences between actual portfolio returns and expected returns will 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 pension costs in future periods.

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 2013 and was based on our targeted asset allocation assumption for 2013 of approximately 70% equity investments and approximately 30% 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




The funded status of our plan reflects investment gains or losses in the year in which they occur based on the market value of assets at the measurement date.

Based on an assumed long-term rate of return of 6%, discount rate of 4.5%, and various other assumptions, we estimate that our pension costs associated with our defined benefit pension plan will decrease from $980,000 in 2013 to $750,000 in 2014. Modifying the expected long-term rate of return on our pension plan assets by .25% would change pension costs for 2014 by approximately $65,000. Increasing the discount rate assumption by .25% would decrease pension costs by approximately $82,000. Decreasing the discount rate assumption by .25% would increase pension costs by approximately $86,000.

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 non-collection on accounts receivable is partially mitigated by our ability to recover the portion of bad debt expense that relates to the customers' gas cost through our gas cost recovery mechanism.

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. Additionally, we specifically review significant account balances for collectibility. 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 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 is 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 accrete for the change in their present value, and the initial capitalized costs depreciate over the useful lives of the related assets. For asset retirement obligations attributable to assets of our regulated operations, the accretion and depreciation 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, marketing and natural gas liquids activities,
·
acquisition of service franchises from local governments,
·
pension plan 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 and other contingencies,
·
regulatory and legislative matters, and
·
dividends.

Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. 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, among others, 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. We define “gross margins” as gas sales less the corresponding purchased gas expenses, plus transportation, natural gas liquids and other revenues. We view gross margins as an important performance measure of the core profitability of our operations and believe investors benefit from having access to the same financial measures that our management uses. Gross margin can be derived directly from our Consolidated Statements of Income as follows:
($000)
2013
 
2012
 
2011
 
 
 
 
 
 
Operating revenues (a)
80,665

 
74,078

 
83,040

Regulated purchased gas (a)
(17,825
)
 
(15,703
)
 
(21,077
)
Non-regulated purchased gas (a)
(26,011
)
 
(23,380
)
 
(26,762
)
 
 
 
 
 
 
Consolidated gross margins
36,829

 
34,995

 
35,201

(a)
amounts 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.

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 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)
2013 compared to 2012
 
2012 compared to 2011
 
 
 
 
Increase (decrease) in gross margins
 
 
 
Regulated segment
 
 
 
Natural gas sales
1,420

 
(641
)
On-system transportation
457

 
(50
)
Off-system transportation
205

 
(75
)
Other
9

 
25

Intersegment elimination (a)
(441
)
 
73

 

 

Total
1,650

 
(668
)
 

 

Non-regulated segment

 

Natural gas sales
(256
)
 
(784
)
Natural gas liquids
41

 
1,360

Other
(42
)
 
(41
)
Intersegment elimination (a)
441

 
(73
)
 

 

Total
184

 
462

 

 

Increase (decrease) in consolidated gross margins
1,834

 
(206
)
 

 
 
Percentage increase (decrease) in volumes

 

Regulated segment

 

Natural gas sales (Mcf)
25

 
(23
)
On-system transportation (Mcf)
6

 
(2
)
Off-system transportation (Mcf)
5

 
(3
)
 

 

Non-regulated segment

 

Natural gas sales (Mcf)
19

 
7

Natural gas liquids (gallons)
34

 
100

(a)
Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment.

Heating degree days were 104% of normal thirty year average temperatures for fiscal 2013, as compared with 83% and 103% of normal temperatures for 2012 and 2011, respectively. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to estimate the demand for natural gas.  A heating degree day is the equivalent for each degree

23



that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location.  Normal degree days are based on the historical thirty year average National Weather Service data for the same geographic location.

In 2013, consolidated gross margins increased $1,834,000 (5%), as compared to 2012, due to increased regulated and non-regulated gross margins of $1,650,000 and $184,000, respectively. Regulated gross margins increased due to a 25% increase in volumes sold to our regulated customers as a result of colder weather and an increase in volumes transported as a result of an increase in our transportation customers' gas requirements. Partially offsetting these increases are decreased rates billed through our weather normalization tariff.

In 2012, consolidated gross margins decreased $206,000 (1%), as compared to 2011, due to decreased regulated gross margins of $668,000 (2%) partially offset by increased non-regulated gross margins of $462,000 (6%). Regulated gross margins decreased due to a 23% decline in volumes sold as a result of warmer weather as compared to 2011. Partially offsetting this decrease are increased rates billed through our weather normalization tariff. Non-regulated gross margins increased due to the sale of liquids extracted from natural gas, as we completed the installation of a facility to extract liquids from the natural gas in our system in order to improve the operations of our distribution, transmission and storage systems. The increase was partially offset by decreases in gross margins from non-regulated natural gas sales due to a decline in sales prices.

Operation and Maintenance

In 2013, operation and maintenance increased $1,556,000 (11%) due to a $1,230,000 increase in labor and employee benefits resulting from an increase in pension expense and share-based compensation and a $369,000 increase in uncollectible expense.

In 2012, there were no significant changes in operation and maintenance, as compared to 2011.

Depreciation and Amortization

In 2013, there were no significant changes in depreciation and amortization, as compared to 2012.    

In 2012, depreciation and amortization increased $767,000 (15%), as compared to 2011, due to increased depreciation rates approved by the Kentucky Public Service Commission in October 2010 as part of our 2010 rate case, and increased depreciable plant.

Taxes Other Than Income Taxes

In 2013, there were no significant changes in taxes other than income taxes, as compared to 2012.    

In 2012, taxes other than income taxes increased $238,000 (12%), as compared to 2011, due to increased property tax expense resulting from both higher assessed values and rates assessed by taxing jurisdictions.

Interest on Long-Term Debt

In 2013 and 2012, interest on long-term debt decreased $546,000 (18%) and $601,000 (17%), respectively, as a result of refinancing our 5.75% Insured Quarterly Notes and 7% Debentures (as further discussed in Note 10 of the Notes to Consolidated Financial Statements).

Other Interest (Income) Expense

In 2013, other interest (income) expense decreased $1,807,000 (183%) due to a decrease in interest accrued for a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 13 of the Notes to Consolidated Financial Statements).

In 2012, other interest (income) expense increased $868,000 (742%) due to interest accrued relating to a tax assessment issued to Delta Resources by the Kentucky Department of Revenue (as further discussed in Note 13 of the Notes to Consolidated Financial Statements).


24



Income Tax Expense

In 2013, income tax expense increased $1,011,000 (31%) due to an increase in net income before income taxes. There were no significant changes in our effective tax rate for 2013, as compared to 2012.

In 2012, income tax expense decreased $502,000 (13%), as compared to 2011, due to a decrease in net income before income taxes. There were no significant changes in our effective tax rate for 2012, as compared to 2011.

Basic and Diluted Earnings Per Common Share

For 2013 and 2012, our basic and diluted earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our dividend reinvestment and stock purchase plan as well as those awarded through our incentive compensation plan. Our computation of basic and diluted earnings per share is set forth in Note 11 of the Notes to Consolidated Financial Statements.

Under our Incentive Compensation Plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 17 of the Notes to Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end. The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive.

Certain unvested awards under our shareholder approved incentive compensation plan, as further discussed in Note 17 of the Notes to Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta Natural Gas Company, Inc. including a right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. There were 68,000 and 48,000 unvested participating shares outstanding as of June 30, 2013 and 2012, respectively. There were no antidilutive shares in 2013 and 2012.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We purchase our natural 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 natural gas purchase contracts, however, is fixed prior to the delivery of the gas. Additionally, we inject some of our natural gas purchases into a gas storage facility in the non-heating months and withdraw this natural gas from storage for delivery to customers during the heating months.  For our regulated segment, 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 natural gas on uncommitted natural gas inventory 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.  As of June 30, 2013, we had forward purchase contracts totaling $328,000 that have various terms with the last contract expiring in December, 2013.  These forward purchase contracts are at a fixed price and not impacted by changes in the market price of natural gas.

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, 2013 or June 30, 2012.  The weighted average interest rate on our bank line of credit was 1.3% and 1.4% as of June 30, 2013 and June 30, 2012, respectively.  We did not have any borrowings on our bank line of credit during 2013.


25



Item 8.      Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE
PAGE
 
 
Report of Independent Registered Public Accounting Firm
 
 
Consolidated Statements of Income for the years ended June 30, 2013, 2012 and 2011

 
Consolidated Statements of Cash Flows for the years ended June 30, 2013, 2012 and 2011

 
Consolidated Balance Sheets as of June 30, 2013 and 2012

 
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2013, 2012 and 2011

 
Notes to Consolidated Financial Statements

 
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2013, 2012 and 2011

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.





26



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

None.

Item 9A.   Controls and Procedures

Disclosure 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, 2013 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.

Changes in Internal Control over Financial Reporting

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 year ended June 30, 2013 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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.

Management's Annual Report on Internal Control over Financial Reporting

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, 2013 based on the framework in Internal Control - Integrated Framework issued in 1992 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, 2013.

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.

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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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 Management's Annual Report on Internal Control over Financial Reporting. 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, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) 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, 2013 of the Company and our report dated August 27, 2013 expressed an unqualified opinion on those financial statements and financial statement schedule.


/s/ DELOITTE & TOUCHE LLP

Indianapolis, Indiana
August 27, 2013


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 as well as Corporate Governance Guidelines. 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 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2013. 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”, “Corporate Governance and Compensation Committee Interlocks and Insider Participation”, “Compensation Discussion and Analysis”, “Compensation Risks”, “Corporate Governance and Compensation Committee Report”, “Summary Compensation Table”, “Grants of Plan Based Awards”, “Outstanding Equity Awards at Fiscal Year-End”, “Retirement Benefits”, “Potential Payments Upon Termination Or Change in Control” and “Termination Table” in our definitive Proxy Statement for the 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2013. 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 our shareholder approved incentive compensation plan, we have the ability to grant stock, 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, 2013:

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)
 
 
 
 
 
                            —
 
                        —
 
849,790

The other information required by this Item is contained under the captions “Security Ownership of Certain Beneficial Owners” and "Security Ownership of Management" in our definitive Proxy Statement for the 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2013. 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 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2013. 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 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2013. 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.
 
3.1
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.
 
3.2
Registrant's Amended and Restated By-Laws (dated August 20, 2013) are incorporated herein by reference to Exhibit 3.1 to Registrant's Form 8-K (File No. 000-8788) dated August 21, 2013.
 
4
Note Purchase and Private Shelf Agreement dated December 8, 2011 in respect of 4.26% Senior Notes, Series A, due December 20, 2031, is incorporated herein by reference to Exhibit 10.01 to Registrant's Form 8-K (File No. 000-08788) dated December 13, 2011.
 
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, 2010, by and between Atmos Energy Marketing, LLC and Registrant is incorporated herein by reference to Exhibit 10.04 to Registrant's Form 10-K (File No. 000-08788) for the period ended June 30, 2012.
 
10.05
Base contracts for the Sale and Purchase of Natural Gas, dated May 1, 2013, by and between Midwest Energy L.L.C. and Registrant is filed herewith.
 
10.06
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.
 
10.07
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.
 
10.08
Amendment, dated July 22, 2010, of agreement to transport natural gas between Nami Resources Company, L.L.C. and Registrant incorporated herein by reference to Exhibit 10(f) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
 
10.09
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 incorporated herein by reference to Exhibit 10(g) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
 
10.10
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 incorporated herein by reference to Exhibit 10(h) to Registrant's Form 10-K (File No. 000-08788), for the period ended June 30, 2010.
 
10.11
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




 
10.12
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.
 
10.13
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.
 
10.14
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.
 
10.15
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.
 
10.16
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.
 
10.17
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.
 
10.18
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.
 
10.19
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.
 
10.20
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.
 
10.21
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.
 
10.22
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.
 
10.23
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.
 
10.24
Modification Agreement extending to June 30, 2015 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, 2013.
 
10.25
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.
 
10.26
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.
 
10.27
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.
 
10.28
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



 
10.29
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.
 
10.30
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 and Post-Effective Amendment No. 1 to Registrant's S-3 (Reg. No. 333-130301) dated August 29, 2012.
 
10.31
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.
 
10.32
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. 000-08788) dated August 20, 2010.
 
10.33
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. 000-08788) dated August 16, 2011.
 
10.34
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 Exhibit 10.1, 10.2, 10.3, 10.4 and 10.5 of Registrant's Form 8-K (File No. 000-08788) dated August 21, 2012.
 
10.35
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 Exhibit 10.1, 10.2, 10.3, 10.4 and 10.5 of Registrant's Form 8-K (File No. 000-08788) dated August 21, 2013.
 
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.
 
101.INS
XBRL Instance Document
 
101.SCH
XBRL Taxonomy Extension Schema
 
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
 
101.DEF
XBRL Taxonomy Extension Definition Database
 
101.LAB
XBRL Taxonomy Extension Label Linkbase
 
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
 
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL):
 
(i)
Document and Entity Information;
 
(ii)
Consolidated Statements of Income for the years ended June 30, 2013, 2012 and 2011;
 
(iii)
Consolidated Statements of Cash Flows for the years ended June 30, 2013, 2012 and 2011;
 
(iv)
Consolidated Balance Sheets as of June 30, 2013 and 2012;
 
(v)
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2013, 2012 and 2011;
 
(vi)
Notes to Consolidated Financial Statements;
 
(vii)
Schedule II – Valuation and Qualifying Accounts for the years ended June 30, 2013, 2012 and 2011.
 
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospects for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability.  We also make available on our web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

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 27th day of August, 2013.
 
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 27, 2013
(Glenn R. Jennings)
and Chief Executive Officer
 
 
 
 
(ii)      Principal Financial Officer:
 
 
 
 
 
/s/John B. Brown
Chief Financial Officer,
August 27, 2013
(John B. Brown)
Treasurer and Secretary
 
 
 
 
(iii)        Principal Accounting Officer:
 
 
 
 
 
/s/Matthew D. Wesolosky
Vice President - Controller
August 27, 2013
(Matthew D. Wesolosky)
 
 
 
 
 
(iv)      A Majority of the Board of Directors:
 
 
 
 
 
/s/Glenn R. Jennings
Chairman of the Board, President
August 27, 2013
(Glenn R. Jennings)
and Chief Executive Officer
 
 
 
 
/s/Sandra C. Gray
Director
August 27, 2013
(Sandra C. Gray)
 
 
 
 
 
/s/Edward J. Holmes
Director
August 27, 2013
(Edward J. Holmes)
 
 
 
 
 
/s/Michael J. Kistner
Director
August 27, 2013
(Michael J. Kistner)
 
 
 
 
 
/s/Lewis N. Melton
Director
August 27, 2013
(Lewis N. Melton)
 
 
 
 
 
/s/Arthur E. Walker, Jr.
Director
August 27, 2013
(Arthur E. Walker, Jr.)
 
 
 
 
 
/s/Michael R. Whitley
Director
August 27, 2013
(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, 2013 and 2012, 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, 2013. 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 Delta Natural Gas Company, Inc. and subsidiaries as of June 30, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2013, 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, present 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, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated August 27, 2013 expressed an unqualified opinion on the Company's internal control over financial reporting.


/s/  DELOITTE & TOUCHE LLP

Indianapolis, Indiana
August 27, 2013

 
 

 


35



Delta Natural Gas Company, Inc.

Consolidated Statements of Income

For the Year Ended June 30,
2013
 
2012
 
2011
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
Regulated revenues
$
46,427,203

 
$
42,655,378

 
$
48,697,530

Non-regulated revenues
34,237,634

 
31,422,944

 
34,342,721

Total operating revenues
$
80,664,837

 
$
74,078,322

 
$
83,040,251

 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
Regulated purchased gas
$
17,825,487

 
$
15,703,114

 
$
21,077,548

Non-regulated purchased gas
26,011,164

 
23,380,426

 
26,761,726

Operation and maintenance
15,208,162

 
13,651,689

 
14,065,725

Depreciation and amortization
6,092,651

 
5,923,775

 
5,156,973

Taxes other than income taxes
2,338,694

 
2,154,090

 
1,916,485

Total operating expenses
$
67,476,158

 
$
60,813,094

 
$
68,978,457

 
 
 
 
 
 
Operating Income
$
13,188,679

 
$
13,265,228

 
$
14,061,794

 
 
 
 
 
 
Other Income and Deductions, Net
$
150,816

 
$
75,170

 
$
151,506

 
 
 
 
 
 
Interest Charges
 
 
 
 
 
Interest on long-term debt
$
2,438,325

 
$
2,984,413

 
$
3,584,772

Other interest (income) expense
(822,190
)
 
984,612

 
116,763

Amortization of debt expense
253,800

 
329,231

 
387,263

Total interest charges
$
1,869,935

 
$
4,298,256

 
$
4,088,798

 
 
 
 
 
 
 
 
 
 
 
 
Net Income Before Income Taxes
$
11,469,560

 
$
9,042,142

 
$
10,124,502

 
 
 
 
 
 
Income Tax Expense
$
4,268,784

 
$
3,258,144

 
$
3,759,607

 
 
 
 
 
 
Net Income
$
7,200,776

 
$
5,783,998

 
$
6,364,895

 
 
 
 
 
 
Earnings Per Common Share (Note 11)
 
 
 
 
 
Basic
$
1.05

 
$
0.85

 
$
0.95

Diluted
$
1.05

 
$
0.85

 
$
0.95

 
 
 
 
 
 
Dividends Declared Per Common Share
$
0.72

 
$
0.70

 
$
0.68







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 Year Ended June 30,
2013
 
2012
 
2011
 
 
 
 
 
 
Cash Flows From Operating Activities
 
 
 
 
 
Net income
$
7,200,776

 
$
5,783,998

 
$
6,364,895

 
 
 
 
 
 
Adjustments to reconcile net income to net
 
 
 
 
 
cash from operating activities
 
 
 
 
 
Depreciation and amortization
6,428,051

 
6,334,647

 
5,640,916

Deferred income taxes and investment
 
 
 
 
 
tax credits
1,959,741

 
2,513,400

 
2,536,234

Change in cash surrender value of officer's
 
 
 
 
 
life insurance
(27,300
)
 
153

 
(58,744
)
Share-based compensation
921,709

 
712,144

 
526,859

Excess tax deficiency from share-based compensation
(8,946
)
 

 

 
 
 
 
 
 
(Increase) decrease in assets
 
 
 
 
 
Accounts receivable
(841,574
)
 
(1,407,711
)
 
(1,833,298
)
Gas in storage
1,451,494

 
(121,547
)
 
(605,529
)
Deferred gas cost
(536,552
)
 
(7,581
)
 
(81,799
)
Materials and supplies
9,256

 
(51,724
)
 
20,629

Prepayments
893,490

 
(2,606,809
)
 
1,874,828

Other assets
(177,919
)
 
(548,470
)
 
(34,260
)
 
 
 
 
 
 
Increase (decrease) in liabilities
 
 
 
 
 
Accounts payable
2,725,470

 
(3,518,540
)
 
1,936,487

Accrued taxes
(2,757,561
)
 
2,695,526

 
122,358

Asset retirement obligations
(493,946
)
 
1,085,920

 
(1,351,841
)
Other liabilities
(3,189,770
)
 
2,650,640

 
(591,014
)
 
 
 
 
 
 
Net cash provided by operating activities
$
13,556,419

 
$
13,514,046

 
$
14,466,721

 
 
 
 
 
 
Cash Flows From Investing Activities
 
 
 
 
 
Capital expenditures
$
(7,179,473
)
 
$
(7,337,115
)
 
$
(8,123,479
)
Proceeds from sale of property, plant and equipment
131,545

 
183,678

 
171,641

Other
(60,000
)
 
141,530

 
431,897

Net cash used in investing activities
$
(7,107,928
)
 
$
(7,011,907
)
 
$
(7,519,941
)
 
 
 
 
 
 

 




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 Year Ended June 30,
2013
 
2012
 
2011
 
 
 
 
 
 
Cash Flows From Financing Activities
 
 
 
 
 
Dividends on common shares
$
(4,951,002
)
 
$
(4,762,257
)
 
$
(4,562,284
)
Issuance of common shares
587,359

 
697,775

 
677,544

Debt issuance costs

 
(107,904
)
 

Issuance of long-term debt

 
58,000,000

 

Excess tax benefit from share-based compensation
35,112

 
21,563

 

Repayment of long-term debt
(1,500,000
)
 
(57,951,006
)
 
(360,993
)
Borrowings on bank line of credit

 
17,697,829

 
17,824,196

Repayment of bank line of credit

 
(17,697,829
)
 
(17,824,196
)
 
 
 
 
 
 
Net cash used in financing activities
$
(5,828,531
)
 
$
(4,101,829
)
 
$
(4,245,733
)
 
 
 
 
 
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
$
619,960

 
$
2,400,310

 
$
2,701,047

 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents,  Beginning of Year
9,740,502

 
7,340,192

 
4,639,145

 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents,  End of Year
$
10,360,462

 
$
9,740,502

 
$
7,340,192

 
 
 
 
 
 
Supplemental Disclosures of Cash Flow Information
 
 
 
 
 
 
 
 
 
 
 
Cash paid during the year for
 
 
 
 
 
Interest
$
2,509,962

 
$
3,795,590

 
$
3,702,692

Income taxes (net of refunds)
$
1,573,321

 
$
1,011,138

 
$
(124,861
)
 
 
 
 
 
 
Significant non-cash transactions
 
 
 
 
 
Accrued capital expenditures
$
301,679

 
$
336,543

 
$
340,670

Loss on extinguishment of debt recognized as a
regulatory asset (Note 10)
$

 
$
1,896,000

 
$







 



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,
2013
 
2012
 
 
 
 
Assets
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
10,360,462

 
$
9,740,502

Accounts receivable, less accumulated allowances for doubtful
8,700,982

 
8,028,937

accounts of $536,000 and $157,000 in 2013 and 2012,
 
 
 
respectively
 
 
 
Gas in storage, at average cost (Notes 1 and 16)
5,481,313

 
6,932,807

Deferred gas costs (Notes 1 and 14)
3,922,844

 
3,386,292

Materials and supplies, at average cost
561,270

 
557,118

Prepayments
1,987,855

 
2,393,674

 
 
 
 
Total current assets
$
31,014,726

 
$
31,039,330

 
 
 
 
Property, Plant and Equipment
$
223,545,925

 
$
217,172,542

Less - Accumulated provision for depreciation
(88,429,625
)
 
(82,835,542
)
 
 
 
 
Net property, plant and equipment
$
135,116,300

 
$
134,337,000

 
 
 
 
Other Assets
 
 
 
Cash surrender value of  life insurance