10-K 1 dgas-2016630x10k.htm 10-K Document


 
 
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, 2016
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 o 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  o  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  o
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  o
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.    o
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     o
Accelerated filer     x
Non-accelerated filer   o (Do not check if a smaller reporting company)
Smaller reporting company     o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o 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.  $148,491,236.
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 26, 2016, Delta Natural Gas Company, Inc. had outstanding 7,092,263 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, 2016, is incorporated by reference in Part III of this Report.
 
 





TABLE OF CONTENTS
 
 
 
Page Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 

1



PART I

Item 1.     Business

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, “2016”, “2015” and “2014” refers to the respective twelve month periods ending June 30. Delta's NASDAQ symbol is DGAS.

General

Delta distributes or transports natural gas to approximately 36,000 customers. Our distribution and transmission systems are located in central and southeastern Kentucky, and we own and operate an underground natural gas storage field in southeastern Kentucky. We transport natural gas to 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 extract liquids from natural gas in our storage field and on our pipeline systems that are sold at market prices. We have three wholly-owned subsidiaries. Delta Resources, Inc. (“Delta Resources”) buys natural gas and resells it to industrial or large-volume 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 natural gas production properties and undeveloped acreage.

We seek to provide dependable, high-quality service to our customers while steadily enhancing value for our shareholders. Our efforts have been focused on developing a balance of regulated and non-regulated businesses to contribute to our earnings by profitably selling, transporting, 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, transportation 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 managing market risk arising from fluctuations in the prices of natural gas and natural gas liquids.

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 large-volume 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.

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


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Factors that affect our regulated revenues include the rates we charge our customers, economic conditions in our service areas, competition, the cost of natural gas and weather. Our current rate design lessens the impact weather has on our regulated revenues as our rates include both fixed customer charges and volumetric rates which include a weather normalization tariff that adjusts rates due to variations in weather. Market risk arising from fluctuations in the price of natural gas is mitigated through the natural gas cost recovery rate mechanism which permits us to pass through to our regulated customers changes in the price we must pay for our natural 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 2016, 74% 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. Our weather normalization 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, geo-thermal, coal, oil, propane, wood and solar.

Our large-volume regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers. 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 natural gas and/or transportation services. Our large-volume customers who are in close proximity to alternative supplies are 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 natural gas supply at competitive market-based rates.

Some natural gas producers in our service area can access pipeline 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.

Natural Gas Supply

We maintain an active natural 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. Our distribution and transportation system interconnects with interstate pipelines owned by Columbia Gas Transmission Corporation (“Columbia Gas”), Columbia Gulf Transmission Corporation (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”) and Texas Eastern Transmission Corporation (“Texas Eastern”). In our fiscal year ended June 30, 2016, we purchased approximately 99% of our natural gas from interstate sources.

Interstate Natural Gas Supply

Our regulated segment acquires its interstate natural gas supply from natural gas marketers. We currently have commodity requirements agreements with Atmos Energy Marketing (“Atmos”) for our Columbia Gas, Columbia Gulf, Tennessee and 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 prices, NYMEX 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, plus or minus an agreed-to fixed price adjustment per million British Thermal Units of natural 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 30) of the agreement. In our fiscal year ended June 30, 2016, approximately 53% of our regulated natural gas supply was purchased under our agreements with Atmos.


3



Our regulated segment purchases natural gas from 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 Midwest, nor are we required to purchase natural gas 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 Midwest may be terminated upon 30 days prior written notice by either party. In our fiscal year ended June 30, 2016, approximately 46% of our regulated natural gas supply was purchased under our agreement with Midwest.

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

Transportation of Interstate Natural 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, 2019 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. At this time, we expect to renew our agreements with Tennessee. Subject to the terms of Tennessee's Federal Energy Regulatory Commission natural gas tariff, Tennessee is obligated under these agreements to transport up to 19,600 thousand cubic feet (“Mcf”) per day for us. During fiscal 2016, Tennessee transported for us a total of 1,640,000 Mcf, or approximately 43% of our regulated supply requirements, under these agreements. We have natural gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee's storage fields, which we have assigned to Atmos, and we reserve the right to withdraw daily natural gas volumes up to certain specified fixed quantities. These natural 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 2016, Columbia Gas and Columbia Gulf transported for us a total of 329,000 Mcf, or approximately 9% of our regulated natural gas supply, under all of our agreements with them. Our transportation agreements with Columbia Gas continue on a year-to-year basis unless terminated by one of the parties. Our transportation agreement with Columbia Gulf extends through October, 2020 and may be extended by mutual agreement.

Columbia Gulf also transported additional volumes under agreements it has with Midwest to a point of interconnection between Columbia Gulf and us where we purchase the natural gas to inject into our storage field. The amounts transported and sold to us under the agreements Columbia Gulf has with Midwest for fiscal 2016 constituted approximately 46% of our regulated natural 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 natural gas to us that we purchase from Atmos to supply our customers' requirements in specific geographic areas. In our fiscal year ended June 30, 2016, Texas Eastern transported approximately 17,000 Mcf of natural gas to our system, which constituted less than 1% of our natural gas supply.

Kentucky Natural 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 34,000 Mcf from Vinland during fiscal 2016. The price for the natural gas we purchase from Vinland is based on the index price of spot natural gas delivered to Columbia Gas in the relevant region as reported in Platts' Inside FERC's Gas Market Report. Vinland delivers this natural gas to our customer meters directly from its own pipelines. In fiscal 2016, the natural gas we purchased from Vinland constituted less than 1% of our regulated natural gas supply.

Natural Gas in Storage

We own and operate an underground natural gas storage field that we use to store a significant portion of our natural gas supply needs. This storage capability permits us to purchase and store natural gas during the non-heating months and then withdraw and sell the natural gas during the peak usage months. We have a legal obligation to retire wells located at this underground natural gas storage facility. 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.

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Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services, which includes approval of our rates and tariffs. The Kentucky Public Service Commission's 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 distribution and transportation services. The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. Rate base consists primarily of our regulated segment's property, plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes. 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.

Our pipe replacement program tariff allows us to adjust our regulated 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 tariff is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.

Our natural gas cost recovery tariff 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 natural gas cost. Although we are not required to file a general rate case to adjust rates pursuant to the natural gas cost recovery tariff, we are required to make quarterly filings with the Kentucky Public Service Commission. Under and over-recovered natural gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual natural gas costs were incurred.

Our weather normalization provision tariff 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.

Additionally, we have a conservation and efficiency program tariff for our residential customers, which allows us to adjust our rates for activities performed through the program. 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 gross margins on lost sales due to operating 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 seven of the cities we serve, and we continue to operate under the conditions of expired franchises in fifteen 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 natural 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 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 natural 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 natural gas supply at competitive market based rates.

In our fiscal year ended June 30, 2016, approximately 99% 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 for 2016. Atmos provided approximately $5,656,000, $7,127,000 and $5,206,000 of non-regulated revenues during 2016, 2015 and 2014, respectively. Greystone, LLC provided approximately $11,555,000, $17,852,000 and $12,569,000 of non-regulated revenues during 2016, 2015 and 2014. 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 when favorable market conditions arise. Item 2 further describes Enpro's oil and natural gas leases and production properties. Enpro produced a total of 108,000 Mcf of natural gas during 2016 which was approximately 1% of our non-regulated volumes sold.

Natural Gas Liquids

We process a portion of the natural gas in our distribution, transmission and storage system to extract liquids, enhancing the reliability and efficiency of our system. The profitability from the sales of the natural gas liquids is dependent on the amount of liquids extracted, the pricing for any such liquids as determined by a national non-regulated market and the volumes of natural gas liquids sold. In our fiscal year ended June 30, 2016, approximately 1% of our non-regulated revenue was derived from the sale of natural gas liquids.

Natural Gas Supply

      Our non-regulated segment purchases natural gas from Midwest. Our underlying agreement with Midwest does not obligate us to purchase any minimum quantities, nor to purchase natural gas 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 Midwest may be terminated upon 30 days prior written notice by either party. Any purchase agreements to supply our non-regulated sales activities may have longer terms or multiple month purchase commitments. In our fiscal year ended June 30, 2016, 94% of our non-regulated natural gas supply was purchased under our agreement with Midwest.

Additionally, our non-regulated segment purchases natural gas from Atmos as needed. This spot 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 natural gas for one or more months. The price of natural gas under this agreement is based on current market prices. In our fiscal year ended June 30, 2016, approximately 5% of our non-regulated natural gas supply was purchased under our agreement with Atmos.

We also purchase intrastate natural gas from 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. We continue to consider acquisitions of additional production properties which are contiguous to our regulated distribution and transmission system as well as opportunities to process additional volumes of natural gas.


Capital Expenditures

Capital expenditures during 2016 were $6.3 million and for 2017 are estimated to be $8.5 million. Our expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering, production and storage systems, as well as general facilities.


Financing

Our capital expenditures and operating cash requirements are primarily met through the use of internally generated funds. Our short-term bank line of credit is $40 million, all of which was available at June 30, 2016.


6



Our current bank line of credit extends through June 30, 2017 and will be available 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 $52,000,000 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, 2016, we had 148 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 under our “Investor Relations” tab, our Business Code of Conduct and Ethics, Vendor Code of Conduct and Ethics, annual report on Form 10-K, quarterly reports on Form 10-Q, extensible business reporting language (XBRL) interactive data files, 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 Securities and Exchange Commission (“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,
2016
 
2015
 
2014
 
2013
 
2012
 
 
 
 
 
 
 
 
 
 
Average Regulated Customers Served
34,415

 
34,384

 
34,490

 
34,701

 
34,860

 
 
 
 
 
 
 
 
 
 
Operating Revenues ($000) (a)
 
 
 
 
 
 
 
 
 
Regulated revenues
 
 
 
 
 
 
 
 
 
Natural gas sales
35,319

 
46,828

 
51,542

 
41,202

 
37,660

Natural gas transportation
9,225

 
9,366

 
9,163

 
9,037

 
8,375

Other
289

 
356

 
390

 
333

 
324

Total regulated revenues
44,833

 
56,550

 
61,095

 
50,572

 
46,359

 
 
 
 
 
 
 
 
 
 
Non-regulated revenues
22,888

 
33,507

 
38,792

 
34,238

 
31,423

Intersegment eliminations (b)
(3,591
)
 
(3,869
)
 
(4,041
)
 
(4,145
)
 
(3,704
)
 
 
 
 
 
 
 
 
 
 
Total
64,130

 
86,188

 
95,846

 
80,665

 
74,078

 
 
 
 
 
 
 
 
 
 
System Throughput (Million Cu. Ft.) (a)
 
 
 
 
 
 
 
 
 
Regulated
 
 
 
 
 
 
 
 
 
Natural gas sales
2,623

 
3,261

 
3,351

 
3,057

 
2,448

Natural gas transportation
17,413

 
16,855

 
16,423

 
16,783

 
15,949

Total regulated throughput
20,036

 
20,116

 
19,774

 
19,840

 
18,397

 
 
 
 
 
 
 
 
 
 
Non-regulated
7,436

 
7,357

 
7,241

 
7,650

 
6,455

Intersegment eliminations (b)
(7,288
)
 
(7,210
)
 
(7,096
)
 
(7,497
)
 
(6,326
)
 
 
 
 
 
 
 
 
 
 
Total
20,184

 
20,263

 
19,919

 
19,993

 
18,526

 
 
 
 
 
 
 
 
 
 
Average Annual Consumption Per
 
 
 
 
 
 
 
 
 
Average Residential Customer
 
 
 
 
 
 
 
 
 
 (Thousand Cu. Ft.)
47

 
59

 
61

 
56

 
44

 
 
 
 
 
 
 
 
 
 
Lexington, Kentucky Degree Days
 
 
 
 
 
 
 
 
 
Actual
3,765

 
4,964

 
4,855

 
4,667

 
3,977

Percent of 30 year average
83

 
110

 
107

 
104

 
83

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

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Item 1A.   Risk Factors

The risk factors below should be carefully considered.

OUR BUSINESS, EARNINGS AND CASH REQUIREMENTS ARE HIGHLY WEATHER SENSITIVE AND SEASONAL.

Our revenues vary from year-to-year, depending on weather conditions. We estimate that approximately 74% of our annual natural gas sales are temperature sensitive. As a result, mild winter temperatures can decrease the amount of natural gas we sell in any year, which would reduce our revenues and profits. Our weather normalization 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. Deviations from normal weather conditions and the seasonal nature of our business can create fluctuations in earnings and short-term cash requirements.

OUR ABILITY TO MEET CUSTOMERS' NATURAL GAS REQUIREMENTS MAY BE IMPAIRED IF CONTRACTED NATURAL GAS SUPPLIES AND INTERSTATE PIPELINE SERVICES ARE NOT AVAILABLE, ARE NOT DELIVERED IN A TIMELY MANNER OR IF FEDERAL REGULATIONS DECREASE OUR AVAILABLE CAPACITY.

We are responsible for acquiring sufficient natural gas supplies, interstate pipeline capacity and storage capacity to meet
current and future customers' annual and seasonal natural gas requirements. We purchase almost all of our natural gas supply from interstate sources and rely on interstate pipelines to transport natural gas to our system. The Federal Energy Regulatory Commission regulates the transportation 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 interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of natural gas. If we are not able to maintain a reliable and adequate natural gas supply and sufficient pipeline capacity to deliver that supply, we may be unable to meet our customers' requirements resulting in a loss of customers and decrease in profits.

OUR CUSTOMERS ARE ABLE TO BY-PASS OUR DISTRIBUTION AND TRANSMISSION SYSTEMS.

Our large-volume customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers. 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 by-pass us in order to achieve lower prices for their natural gas and/or transportation services. Our large-volume 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-volume customers and thus could result in lower revenues and profits.

THE EFFECTS OF REGULATION ON OUR BUSINESS COULD DECREASE FUTURE PROFITABILITY.

The Kentucky Public Service Commission approves the rates we charge our regulated customers and has historically utilized cost-of-service ratemaking where our base rates are established based on normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. We routinely evaluate our need to file for a general rate increase and in doing so weigh the need to increase rates with the potential risks associated with a rate case. The Kentucky Public Service Commission has ultimate discretion in determining what constitutes a reasonable return and determines what constitutes reasonable rates for our customers and in any proceeding may disallow or limit the recovery of certain costs.
The Kentucky Public Service Commission sets our base rates using a twelve month test period which assumes revenues are generated based on thirty-year average temperatures and normal operating expenses. While the Kentucky Public Service Commission approves our rates, we may not earn our allowed return if we experience warmer than normal temperatures, infrequent or non-recurring expenses, increased expenses above amounts included in the test period or capital (debt and equity) which differs from our rate base.
Additionally, there is a lag from the time a request is made to adjust rates to when the rates are approved and implemented as the Kentucky Public Service Commission reviews the reasonableness of any rate adjustment. Therefore, the need to adjust rates may be identified in one reporting period and the new rates implemented in a subsequent period.

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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 results of operations.
Our tariff provides for recovery of certain costs outside of a rate case which includes costs incurred under our natural gas cost recovery tariff, our pipe replacement program tariff and our conservation and efficiency program. Recovery of costs through these mechanisms is subject to the same risks associated with adjustment to our base rates.
VOLATILITY IN PRICES COULD REDUCE OUR PROFITS.

Significant increases or lack of stability 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 natural gas we sell that is caused by such actions will reduce our revenues and profits. Higher prices also make it more difficult to add new customers. Significant decreases in the price of natural gas will likely cause our non-regulated segment's gross margins to decrease. The price of natural gas liquids is determined by a national non-regulated market, and decreases in the price could result in a decrease in our non-regulated gross margins.

DERIVATIVES LEGISLATION COULD ADVERSELY AFFECT OUR ABILITY TO HEDGE RISKS ASSOCIATED WITH OUR BUSINESS OR OTHERWISE HAVE A MATERIAL AND ADVERSE EFFECT ON OUR FINANCIAL POSITION, RESULTS OF OPERATIONS OR CASH FLOWS.

As part of our risk management strategy, we currently use, and historically have used, forward commodity contracts, which meet the criteria of a derivative. The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) adopted a comprehensive framework for the regulation of over-the-counter swaps (“OTC swaps”). The Dodd-Frank Act divides regulatory authority over swap agreements between the SEC and the Commodity Futures Trading Commission (“CFTC”) and requires that most OTC swaps be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. While the SEC and CFTC have adopted numerous regulations relating to OTC swaps, they are still in the process of rulemaking to address all of the requirements regarding OTC swaps under the Dodd-Frank Act. Current and future legal and regulatory requirements, restrictions and regulations imposed under the Dodd-Frank Act could increase the operational and transactional cost of derivatives contracts and could affect the number and/or creditworthiness of available counterparties. Our inability to enter into derivative contracts at favorable terms, or at all, could increase our operating expenses and our ability to hedge our business risks.

THIRD PARTY RESTRICTIONS ON INTERSTATE AND OTHER PIPELINES DELTA INTERCONNECTS WITH CAN ADVERSELY AFFECT OUR RESULTS OF OPERATIONS OR CASH FLOWS.

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, which could have a negative impact on our financial position, results of operations and cash flows.

FUTURE PROFITABILITY OF THE NON-REGULATED SEGMENT IS DEPENDENT ON FLUCTUATIONS IN NATURAL GAS PRICES AND A FEW INDUSTRIAL AND OTHER LARGE-VOLUME CUSTOMERS.

Our non-regulated customers are primarily industrial and other large-volume customers. Fluctuations in natural gas prices and the natural 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 SYSTEM OR LIQUIDS SALES PRICES COULD REDUCE OUR NON-REGULATED REVENUES.

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 non-regulated market. A reduction in the quantity of liquids present in our system, or reductions in the prices we receive for such liquids sales, 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.

10



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 prices for natural gas, terrorist attacks or the overall financial health of the energy industry. There is no guarantee we could obtain needed capital in the future.

POOR INVESTMENT PERFORMANCE OF OUR DEFINED BENEFIT RETIREMENT PLAN HOLDINGS AND OTHER FACTORS IMPACTING PENSION COSTS COULD UNFAVORABLY IMPACT OUR LIQUIDITY AND RESULTS OF OPERATIONS.

Our cost of providing a non-contributory defined benefit retirement 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. Additionally, investment performance less than our expected return on plan assets increases our pension expense in subsequent years. Both cash funding obligations and increased expense 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 financial position, results of operations or cash flows.

SUBSTANTIAL OPERATIONAL RISKS ARE INVOLVED IN OPERATING A NATURAL GAS DISTRIBUTION, TRANSPORTATION, LIQUIDS EXTRACTION AND STORAGE SYSTEM AND SUCH OPERATIONAL EVENTS 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, leaks, the breakdown or failure of equipment or processes, the performance of pipeline and storage facilities below expected levels of capacity and efficiency, loss of natural gas from storage facilities, measurement issues and catastrophic events such as explosions, fires, earthquakes, floods, landslides or other similar events beyond our control. These risks could result in injury or loss of life, extensive property damage 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 natural gas distribution, transmission, liquids extraction or storage system caused by such events could reduce our revenues and increase our expenses.
        
WE MAY FACE CERTAIN REGULATORY AND FINANCIAL RISKS RELATED TO PIPELINE SAFETY LEGISLATION.

Increased regulatory oversight over pipeline operations and increased investment to inspect pipeline facilities, upgrade pipeline facilities or control the impact of a breach of such facilities at the federal level could require additional operating expenses and capital expenditures to remain in compliance with any increased federal oversight. While we cannot predict with certainty the extent of these expenses and expenditures or when they might become effective, this could result in significant additional compliance costs to us and we may be unable to recover from our customers, through the regulatory process, all or some of these costs and an authorized rate of return on these costs.

HURRICANES, EXTREME WEATHER, WELL-HEAD OR PIPELINE DISASTERS COULD DISRUPT OUR NATURAL GAS SUPPLY AND INCREASE NATURAL GAS PRICES.

Hurricanes, extreme weather, well-head or pipeline 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.
    

11



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. 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. 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. For example, if we default 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 financial position, results of operations or cash flows.

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

Under the terms of our 4.26% Series A Notes, the aggregate amount we may pay in dividends on our common stock and to repurchase our common stock is limited based on our cumulative net income and dividends paid. Consequently, as of June 30, 2016 our Series A Notes permit us to pay up to an additional $23,341,000 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 INFORMATION TECHNOLOGY SYSTEMS, INTERRUPT THE NATURAL GAS SERVICE WE PROVIDE TO OUR CUSTOMERS, COMPROMISE THE SAFETY OF OUR NATURAL GAS DISTRIBUTION, TRANSMISSION, LIQUIDS EXTRACTION AND STORAGE SYSTEMS OR EXPOSE CONFIDENTIAL PERSONAL INFORMATION.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to information 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, liquids extraction 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, a breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer, employee, vendor, investor or other sensitive data could have a material adverse effect on our reputation, operating results and financial condition. We could also be exposed to claims by persons harmed by such a breakdown or breach. 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 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 situations, such as an aging workforce, mismatch of skill sets to complement future needs, or unavailability of a qualified workforce, may lead to increased operational risks and costs. As a result, we may be unable to hire an adequate number of individuals who are knowledgeable about public utilities and the natural gas industry and/or face a lengthy time period associated with skill development and knowledge transfer. 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 and tax laws, 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, results of operations, cash flows or access to capital.


12



WE MAY FACE CERTAIN REGULATORY AND FINANCIAL RISKS RELATED TO CLIMATE CHANGE LEGISLATION.

Future proposals to limit greenhouse gas emissions, measured in carbon dioxide equivalent units, could adversely affect our operating and service costs and demand for our product. In the past, the United States Congress has considered legislative proposals to limit greenhouse gas emissions and the United States Environmental Protection Agency has adopted regulations to limit carbon emissions. Future legislation and the implementation of existing regulations could increase utility costs and prices charged to 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 our financial position, results of operations or 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 2,600 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.

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 southeastern Kentucky. Thirty-five natural gas wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated at 2.1 million Mcf. Also, Enpro owns the natural gas underlying 15,400 additional acres in southeastern Kentucky. These properties have been leased to others for further drilling and development and Enpro reserves the option to participate in any wells drilled and also retains certain working and royalty interests in any production from future wells. We have performed no reserve studies on these properties. Enpro produced a total of 108,000 Mcf of natural gas during fiscal 2016 from all the properties described in this paragraph.

Our assets have no significant encumbrances.


Item 3.   Legal Proceedings

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


Item 4.     Mine Safety Disclosures

None.



13



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 1,381 record holders of our common stock as of August 26, 2016. 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 2016






First

20.75

19.96

.205
Second

21.38

20.26

.205
Third

23.70

20.83

.205
Fourth

28.22

22.11

.205







Fiscal 2015






First

22.58

19.50

.20
Second

21.54

19.50

.20
Third

21.39

19.10

.20
Fourth

20.84

19.39

.20

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.


14



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 and the Russell 3000 Stock Index during the past five fiscal years. Information reflected on the graph assumes an investment of $100 on June 30, 2011 in each of our common shares, the Dow Jones Utilities Index and the Russell 3000 Stock Index. Cumulative total return assumes quarterly reinvestment of dividends. The total shareholder returns shown are not necessarily indicative of future returns.

dgas201563chartx17354a01a03.jpg


2011

2012

2013

2014

2015

2016












Delta
100

142

144

154

147

204












Dow Jones Utilities Index
100

116

122

150

148

200












Russell 3000 Stock Index
100
 
104
 
126
 
158
 
169
 
173

15



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,
2016

2015

2014

2013

2012
 










Summary of Operations ($)










 










Operating revenues
64,130,220


86,188,238

95,845,871

80,664,837

74,078,322
 










Operating income
11,433,992


12,963,861

15,603,439

13,188,679

13,265,228
 










Net income
5,529,378


6,496,081

8,275,128

7,200,776

5,783,998
 










Earnings per common share










Basic and diluted
.78

.92

1.19

1.05

.85
 










Cash dividends declared per common share
.82

.80

.76

.72

.70
 










Weighted Average Number of Common Shares










Basic and Diluted
7,066,925


7,002,694

6,918,725

6,843,455

6,777,186
 
 
 
 
 
 
 
 
 
 
Total Assets ($) (a)
188,879,129


187,711,166

185,934,857

183,832,911

182,791,259
 










Capitalization ($)










 










Common shareholders' equity
77,726,969


77,221,654

74,728,352

70,005,415

66,220,407
 










Long-term debt (a)
50,422,796


51,916,296

53,409,696

54,902,896

56,395,896
 










Total capitalization (a)
128,149,765


129,137,950

128,138,048

124,908,311

122,616,303
 










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


1,500,000

1,500,000

1,500,000

1,500,000
 










Other Items ($)










 










Capital expenditures
6,302,666


9,010,876

8,077,642

7,179,473

7,337,115
 










Property, plant and equipment
241,833,771


236,780,490

229,367,319

223,545,925

217,172,542

(a)
In 2016, we adopted new guidance related to the presentation of debt issuance costs on the consolidated balance sheets. As a result of the adoption, total assets, long-term debt and total capitalization were reclassified to conform to the new presentation, each of which were reduced by $83,704, $90,304, $97,104 and $104,104 for 2015, 2014, 2013 and 2012, respectively. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 for additional information.
(b)
Includes current portion of long-term debt.


16



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

Overview of 2016 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 2016. Our Company has two segments: a regulated segment, and a non-regulated segment. Our regulated segment includes our natural gas distribution and transportation services, which are regulated by the Kentucky Public Service Commission. Our non-regulated segment includes our natural gas marketing activities and the sales of natural gas liquids.

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 and 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 by 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 historical average temperatures.

Our non-regulated segment markets natural gas to large-volume customers. We endeavor to enter sales agreements matching supply with estimated demand while providing an acceptable gross margin. The non-regulated segment produces a portion of its natural gas supply, which is stored and sold when favorable market conditions arise. The non-regulated segment also sells liquids extracted from natural gas.

Consolidated income per common share of $0.78 for 2016 decreased, as compared to our consolidated income of $0.92 for 2015, due to decreased revenue, net of natural gas costs from the sale of natural gas and natural gas liquids by our non-regulated segment (as further discussed in Results of Operations). Our non-regulated segment experienced decreased revenues, net of natural gas costs, due to decreased sales prices resulting from decreased market prices for both natural gas and natural gas liquids. Our regulated segment is not exposed to the same price risk from market prices as our natural gas cost recovery tariff allows us to pass the cost of natural gas through to our regulated customers. However, our regulated segment experienced decreased revenues, net of natural gas costs resulting from a decline in volumes sold due to the weather being 24% warmer than the prior year, which is partially offset by amounts recovered from our residential and small non-residential customers through our weather normalization tariff.

Future Outlook

Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers and our ability to earn our allowed return.  The Kentucky Public Service Commission approves these rates. We monitor our need to file for a general rate increase for our regulated services with the Kentucky Public Service Commission who has historically utilized cost-of-service rate making where our base rates are established to recover based on normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. Rate base consists primarily of our regulated segment's property, plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes. The Kentucky Public Service Commission determines what constitutes reasonable rates for our customers and in any proceeding may disallow or limit the recovery of certain costs and has ultimate discretion determining what constitutes a reasonable return. We may not earn our allowed return if we experience warmer than normal temperatures, infrequent or non-recurring expenses, increased expenses above amounts included in the test period or capital (debt and equity) which differs from our rate base. The regulated segment's largest expense is natural 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-volume 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 will continue to contribute to our consolidated net income in fiscal 2017. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated revenues, net of natural gas costs, related to our natural gas marketing activities. However, if natural gas prices decrease, we would expect a decrease in our non-regulated revenues, net of natural gas costs, related to our natural gas marketing activities. We process a portion of the natural gas in our distribution, transmission and storage system to extract liquids, enhancing the reliability and efficiency of our system. The profitability from the sales of the natural gas liquids is dependent on the amounts of liquids extracted and the prices for any such liquids as determined by a national non-regulated market.

17




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, share-based compensation and changes in working capital. Our sales and cash requirements are seasonal. The largest portion of our sales occurs during the heating months (December - April), 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 extends through June 30, 2017 and permits borrowings up to $40,000,000. There were no borrowings outstanding on the bank line of credit as of June 30, 2016 or June 30, 2015.

Cash and cash equivalents were $18,607,000 at June 30, 2016 compared with $16,924,000 at June 30, 2015 and $13,676,000 at June 30, 2014. These changes in cash and cash equivalents are summarized in the following table:
$(000)
2016
 
2015
 
2014
 
 
 
 
 
 
Provided by operating activities
$
14,738

 
18,746

 
17,340

Used in investing activities
(6,087
)
 
(8,910
)
 
(7,870
)
Used in financing activities
(6,969
)
 
(6,588
)
 
(6,155
)
 
 
 
 
 
 
      Increase in cash and cash equivalents
1,682

 
3,248

 
3,315


In 2016, cash provided by operating activities decreased $4,008,000 (21%) due to a $22,074,000 decrease in cash received from customers partially offset by a $16,192,000 decrease in cash paid for natural gas, as further discussed in Results of Operations. Additionally, cash paid for income taxes decreased $1,249,000 as a result of decreased earnings in the current year.

In 2015, cash provided by operating activities increased $1,406,000 (8%), as compared to 2014, due to decreased cash paid for income taxes as a result of decreased earnings in the current year, which were partially offset by decreased cash received from the sale of natural gas liquids.

Changes in cash used in investing activities result primarily from changes in the level of capital expenditures between years.
    
In 2016 and 2015 there were no significant changes in cash used in financing activities, as compared to 2015 and 2014, respectively.


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, production and storage systems, as well as general facilities. We expect our capital expenditures for fiscal 2017 to be approximately $8.5 million.
    
The following is provided to summarize our contractual cash obligations for indicated periods after June 30, 2016:
 
 
Payments Due by Fiscal Year
$(000)
 
2017

2018 - 2019

2020 - 2021

After 2021

Total
Interest payments (a)
 
2,234


4,171


3,915


16,333


26,653

Long-term debt (b)
 
1,500


3,000


3,000


44,500


52,000

Pension contributions (c)
 
500


1,000


1,000


4,500


7,000

Natural gas purchases (d)
 
612








612

Total contractual obligations (e)
 
4,846


8,171


7,915


65,333


86,265




18



(a)
Our long-term debt, notes payable and customers' deposits all require interest payments. Interest payments are projected based on fiscal 2016 interest payments until the underlying obligation is satisfied.

(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 retirement plan through 2030, as recommended by our actuary.

(d)
As of June 30, 2016, our non-regulated segment had forward purchase contracts for natural gas which had minimum purchase obligations that expire in May, 2017. The remainder of our natural gas purchase contracts are either requirements-based contracts, or contracts with a minimum purchase obligation extending for a time period not exceeding one month.

(e)
We have other long-term liabilities which include deferred income taxes ($43,405,000), regulatory liabilities ($1,138,000), asset retirement obligations ($3,918,000) and deferred compensation ($1,034,000). 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 approves 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 combined with our bank line of credit will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months.

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.

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 obligations immediately due and payable. We have agreed to the following financial covenants:

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

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

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

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

19




The following table shows the required and actual financial covenants under our Series A Notes as of June 30, 2016:
Requirement
 
Actual
 
 
 
 
 
 
Tangible net worth
no less than $25,800,000
 
$
76,850,000

 
Debt to capitalization ratio
no more than 70%
 
40
%
 
Fixed charge coverage ratio
no less than 1.20x
 
7.55x

 
Dividends paid
no more than $48,619,000
 
$
25,278,000

 

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

20



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 to apply regulatory accounting, the regulated segment would 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.

Defined Benefit Retirement Plan

We have a non-contributory, defined benefit retirement plan covering all eligible employees hired prior to May 9, 2008. The net periodic benefit costs (“pension costs”) for our defined benefit retirement 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, 2016, 2015 and 2014, we recorded pension costs for our defined benefit retirement plan of $812,000, $493,000 and $750,000, 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 over the average remaining service period of the active plan participants. As of June 30, 2016, $10,972,000 of accumulated net losses have been deferred for amortization as pension costs into future periods.

Our defined benefit retirement plan's assets are principally comprised of equity and fixed income investments. Differences between actual portfolio returns and expected returns 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 the defined benefit retirement plan's assets was 5.5% for 2016 and was based on our targeted asset allocation assumption for 2016 of approximately 70% equity investments and approximately 30% fixed income investments. Our targeted investment allocation for equity investments includes allocations to domestic, global and real estate markets. For additional diversification, we also invest in absolute return strategy mutual funds, which include both equity and fixed income securities. Our asset allocation is designed

21



to achieve a moderate level of overall portfolio risk in keeping with our desired risk objective. The plan has amended its investment policy to allow for liability driven investments which, over time, will match a portion of the plan's liability with the underlying assets. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.

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 5.5%, discount rate of 3.50%, and various other assumptions, we estimate that our pension costs associated with our defined benefit retirement plan will increase from $812,000 in 2016 to $1,312,000 in 2017. Modifying the expected long-term rate of return on our defined benefit retirement plan assets by .25% would change pension costs for 2017 by approximately $74,000. Increasing the discount rate assumption by .25% would decrease pension costs by approximately $128,000. Decreasing the discount rate assumption by .25% would increase pension costs by approximately $135,000.

Unbilled Revenues and Natural Gas Costs

At each month-end, we estimate the volumes of natural gas that have been used from the date the customer's meter was last read to month-end. This estimate of unbilled usage is based on projected base load (non-weather sensitive) usage for each day unbilled plus projected weather-sensitive usage for each degree day during the unbilled period. Unbilled revenues and natural 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 natural 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 segment, 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 dates and the assumed credit-adjusted risk-free interest rates. 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.

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.


22



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,
·
retirement plan costs and management,
·
contractual obligations and cash requirements,
·
management of natural gas in our system and risks due to potential fluctuation in the price of natural gas and natural gas liquids,
·
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 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 and delivery of natural gas, the sale of natural gas liquids and the provision of natural gas transportation services. Our operating revenues are significantly impacted by the prices we pay for natural gas. Therefore, 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. We define “gross margins” as natural gas sales less the corresponding purchased natural gas expenses, plus transportation, natural gas liquids and other revenues. Gross margin can be derived directly from our Consolidated Statements of Income included in Item 8, as follows:
($000)
2016
 
2015
 
2014
 
 
 
 
 
 
Operating revenues
64,130

 
86,188

 
95,846

Regulated purchased natural gas
(11,704
)
 
(22,729
)
 
(27,215
)
Non-regulated purchased natural gas
(17,621
)
 
(26,713
)
 
(29,059
)
 
 
 
 
 
 
Consolidated gross margins
34,805

 
36,746

 
39,572


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 a non-regulated national market. Therefore, the prices that we pay for natural gas fluctuate with national supply and demand. See Item 7A for discussion of our forward contracts.


23



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)
2016 compared to 2015
 
2015 compared to 2014
 
 
 
 
Increase (decrease) in gross margins
 
 
 
Regulated segment
 
 
 
Natural gas sales
(484
)
 
(228
)
Natural gas transportation
(141
)
 
203

Other
(67
)
 
(34
)
Intersegment elimination (a)
278

 
172

 

 

Total
(414
)
 
113

 

 

Non-regulated segment

 

Natural gas sales
(616
)
 
(1,601
)
Natural gas liquids
(578
)
 
(1,111
)
Other
(55
)
 
(55
)
Intersegment elimination (a)
(278
)
 
(172
)
 

 

Total
(1,527
)
 
(2,939
)
 

 

Decrease in consolidated gross margins
(1,941
)
 
(2,826
)
 
 
 
 
(%)
 
 
 
 
 
 
 
Percentage increase (decrease) in volumes

 

Regulated segment

 

Natural gas sales (Mcf)
(20
)
 
(3
)
Natural gas transportation (Mcf)
3

 
3

 

 

Non-regulated segment

 

Natural gas sales (Mcf)
1

 
2

Natural gas liquids (gallons)
(22
)
 
(1
)
(a)
Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment.

Heating degree days were 83% of the normal thirty-year average temperatures for fiscal 2016, as compared with 110% and 107% of normal temperatures for 2015 and 2014, respectively. A heating degree day is each degree that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location. 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. Normal temperatures are based on historical thirty-year average heating degree days, as calculated from data provided by the National Weather Service for the same geographic location.

In 2016, consolidated gross margins decreased $1,941,000 (5%), as compared to 2015, primarily due to decreased non-regulated gross margins. Non-regulated gross margins decreased as a result of decreased gross margins on natural gas sales and natural gas liquids. Gross margins on non-regulated natural gas sales decreased due to decreased sales prices partially offset by decreased natural gas costs. Gross margins on the sale of natural gas liquids decreased due to a 72% decline in the average sales price. Although our regulated segment experienced decreased volumes sold as a result of warmer weather, this decrease was partially offset by increased rates billed through our weather normalization tariff and our pipe replacement program tariff.


24



In 2015, consolidated gross margins decreased $2,826,000 (7%), as compared to 2014, due to decreased non-regulated gross margins on natural gas sales and decreased sales prices of natural gas liquids. Gross margins on non-regulated natural gas sales decreased due to the prior year sale of our non-regulated segment's production inventory and decreased sales prices, partially offset by an increase in volumes sold. During 2015, we experienced a 46% decline in the average sales price of natural gas liquids. We process a portion of the natural gas in our distribution, transmission and storage system to extract liquids, enhancing the reliability and efficiency of our system. The profitability from the sales of the natural gas liquids is dependent on the amounts of liquids extracted and the prices for any such liquids as determined by a national non-regulated market.

Operating Expenses

In 2016 and 2015, there were no significant changes in operation and maintenance and depreciation and amortization, as compared to 2015 and 2014, respectively.

In 2016, there were no significant changes in taxes other than income taxes, as compared to 2015.    

In 2015, taxes other than income taxes increased $472,000 (20%) primarily due to an increase in property taxes resulting from an increase in the assessed value of our property.

Other Income

In 2016, there were no significant changes in other income, as compared to 2015.

In 2015, other income decreased $176,000 (88%) due to a decrease in the earnings from the supplemental retirement trust and a decrease in interest received on the cash surrender value of our life insurance policies. The decrease in the earnings from the supplemental retirement trust was offset by a decrease in operating expense resulting from a corresponding change in the liability of the trust.

Interest Charges

In 2016 and 2015, there were no significant changes in interest on long-term debt, amortization of debt expense and other interest expense, as compared to 2015 and 2014, respectively.

Income Tax Expense

In 2016 and 2015, income tax expense decreased $515,000 (13%) and $967,000 (20%) due to decreases in net income before income taxes, as compared to 2015 and 2014, respectively. There were no significant changes in our effective tax rate for 2016 and 2015, as compared to 2015 and 2014, respectively.
    
Basic and Diluted Earnings Per Common Share

For 2016 and 2015, our basic and diluted earnings per common share changed, as compared to 2015 and 2014, respectively, 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.

    
Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We purchase our natural gas supply primarily through a combination of requirements contracts with no minimum purchase obligations, monthly spot purchase contracts and forward purchase contracts. The price we pay for natural gas acquired under forward purchase contracts is fixed prior to the delivery of the natural gas. Additionally, we inject some of our natural gas purchases into our underground natural 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 utilize requirements contracts, spot purchase contracts and our underground storage to meet our regulated customers' natural gas requirements, all of which have minimal price risk because we are permitted to pass these natural gas costs on to our regulated customers through our natural gas cost recovery tariff.


25



Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand.  In addition, we are exposed to changes in the market price of natural gas on uncommitted natural gas inventory of our non-regulated segment. The pricing of the natural gas liquids sold by our non-regulated segment is determined in the national non-regulated market.

None of our natural gas contracts are accounted for using the fair value method of accounting. While some of our natural gas purchase and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.  As of June 30, 2016, we had forward purchase contracts through May, 2017 totaling $612,000 which 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, 2016 or June 30, 2015.  As of June 30, 2016 and June 30, 2015, the weighted average interest rate on our bank line of credit was 1.5% and 1.4%, respectively.  During 2016, we did not have any borrowings on our bank line of credit. During 2015, we borrowed and repaid $126,000 from the bank line of credit, having a weighted average interest rate of 1.3%. A one percent (one hundred basis point) increase in our average interest rate would not have had a significant impact on our annual pre-tax net income.


26




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, 2016, 2015 and 2014

 
Consolidated Statements of Cash Flows for the years ended June 30, 2016, 2015 and 2014

 
Consolidated Balance Sheets as of June 30, 2016 and 2015

 
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2016, 2015 and 2014

 
Notes to Consolidated Financial Statements

 
Schedule II - Valuation and Qualifying Accounts for the years ended June 30, 2016, 2015 and 2014

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.





27



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 SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2016 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, 2016 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, 2016 based on the framework in Internal Control - Integrated Framework issued in 2013 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, 2016.

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:


28



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


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

We have audited the internal control over financial reporting of Delta Natural Gas Company, Inc. and subsidiaries (the "Company") as of June 30, 2016, based on criteria established in Internal Control - Integrated Framework (2013) 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, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) 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 of the Company as of and for the year ended June 30, 2016 and our report dated August 26, 2016 expressed an unqualified opinion on those financial statements and the financial statement schedule.


/s/ DELOITTE & TOUCHE LLP

Atlanta, Georgia
August 26, 2016


29



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, which includes our Insider Trading Policy, can be found on our website by going to the following address: http://www.deltagas.com/governance. 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/governance.

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 2016 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2016. 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 2016 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2016. We incorporate that information in this document by reference.


30



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, 2016:

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)
 
 
 
 
 
                            —
 
                        —
 
747,275

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 2016 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2016. 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 2016 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2016. 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 2016 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission no later than 120 days after June 30, 2016. We incorporate that information in this document by reference.


31



PART IV

Item 15. Exhibits and Financial Statement Schedule
(a)
 
Financial Statements, Schedule and Exhibits
 
 
 
 
(1)
Financial Statements
See Index at Item 8
 
 
 
 
(2)
Financial Statement Schedule
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 14, 2015) are incorporated herein by reference to Exhibit 3.1 to Registrant's Form 8-K (File No. 000-8788) dated August 17, 2015.
 
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
Natural 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
Natural 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
Base contract for the Sale and Purchase of Natural Gas, dated May 1, 2005 and Exhibit A, dated May 1, 2010 by and between Atmos Energy Marketing, LLC and Registrant are 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 are incorporated herein by reference to Registrant's Form 10-K (File No. 000-08788) for the period ended June 30, 2013.
 
10.06
Natural 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 is 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 October 29, 2015 (Service Agreement Nos. 37,813, 37,814 and 37,815) and Appendix A to respective Service Agreements, effective November 1, 2015, by and between Columbia Gulf Transmission, LLC and Registrant are incorporated herein by reference to Exhibit 10.01 to Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2015.
 
10.10
FTS-1 Service Agreements, dated October 29, 2015, (Service Agreement Nos. 43,827, 43,828 and 43,829) and Appendix A to respective Service Agreements, effective November, 2010, by and between Columbia Gulf Transmission, LLC and Registrant are incorporated herein by reference to Exhibit 10.02 to Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2015.
 
10.11
Underground Natural 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 Natural 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.

32



 
10.12
Oil and Natural 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
Natural 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
Natural 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 Natural 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
Modification Agreement extending to June 30, 2017 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, 2015.
 
10.26
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.
 
10.27
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.
 
10.28
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.

33



 
10.29
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.
 
10.30
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.
 
10.31
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.
 
10.32
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.
 
10.33
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 Exhibit 10.1, 10.2, 10.3, 10.4 and 10.5, respectively, of Registrant's Form 8-K (File No. 000-08788) dated August 21, 2013.
 
10.34
Form of Notice of Performance Shares Award is incorporated herein by reference to Exhibit 10.03 to Registrant's Form 10-Q (File No. 000-08788) for the period ended September 30, 2015.
 
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
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, 2016, 2015 and 2014;
 
(iii)
Consolidated Statements of Cash Flows for the years ended June 30, 2016, 2015 and 2014;
 
(iv)
Consolidated Balance Sheets as of June 30, 2016 and 2015;
 
(v)
Consolidated Statements of Changes in Shareholders' Equity for the years ended June 30, 2016, 2015 and 2014;
 
(vi)
Notes to Consolidated Financial Statements;
 
(vii)
Schedule II – Valuation and Qualifying Accounts for the years ended June 30, 2016, 2015 and 2014.

34




SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of August, 2016.
 
DELTA NATURAL GAS COMPANY, INC.
 
 
 
By: /s/Glenn R. Jennings
 
Glenn R. Jennings
 
Chairman of the Board, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
(i)   Principal Executive Officer:
 
 
 
 
 
/s/Glenn R. Jennings
Chairman of the Board, President
August 26, 2016
(Glenn R. Jennings)
and Chief Executive Officer
 
 
 
 
(ii)   Principal Financial Officer:
 
 
 
 
 
/s/John B. Brown
Chief Operating Officer,
August 26, 2016
(John B. Brown)
Treasurer and Secretary
 
 
 
 
(iii)    Principal Accounting Officer:
 
 
 
 
 
/s/Matthew D. Wesolosky
Vice President - Controller
August 26, 2016
(Matthew D. Wesolosky)
 
 
 
 
 
(iv)  A Majority of the Board of Directors:
 
 
 
 
 
/s/Glenn R. Jennings
Chairman of the Board, President
August 26, 2016
(Glenn R. Jennings)
and Chief Executive Officer
 
 
 
 
/s/Linda K. Breathitt
Director
August 26, 2016
(Linda K. Breathitt)
 
 
 
 
 
/s/Jacob P. Cline III
Director
August 26, 2016
(Jacob P. Cline, III)
 
 
 
 
 
/s/Sandra C. Gray
Director
August 26, 2016
(Sandra C. Gray)
 
 
 
 
 
/s/Edward J. Holmes
Director
August 26, 2016
(Edward J. Holmes)
 
 
 
 
 
/s/Michael J. Kistner
Director
August 26, 2016
(Michael J. Kistner)
 
 
 
 
 
/s/Fred N. Parker
Director
August 26, 2016
(Fred N. Parker)
 
 
 
 
 
/s/Rodney L. Short
Director
August 26, 2016
(Rodney L. Short)
 
 
 
 
 
/s/Arthur E. Walker, Jr.
Director
August 26, 2016
(Arthur E. Walker, Jr.)
 
 


35



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Delta Natural Gas Company, Inc. and subsidiaries (the "Company") as of June 30, 2016 and 2015, 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, 2016. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and the 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2016, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of June 30, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated August 26, 2016 expressed an unqualified opinion on the Company's internal control over financial reporting.


/s/  DELOITTE & TOUCHE LLP

Atlanta, Georgia
August 26, 2016

 
 

 


36



Delta Natural Gas Company, Inc.

Consolidated Statements of Income

For the Year Ended June 30,
2016
 
2015
 
2014
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
Regulated revenues
$
41,242,094

 
$
52,681,120

 
$
57,054,180

Non-regulated revenues
22,888,126

 
33,507,118

 
38,791,691

Total operating revenues
$
64,130,220

 
$
86,188,238

 
$
95,845,871

 
 
 
 
 
 
Operating Expenses
 
 
 
 
 
Regulated purchased natural gas
$
11,704,178

 
$
22,728,766

 
$
27,215,425

Non-regulated purchased natural gas
17,621,069

 
26,713,424

 
29,059,426

Operation and maintenance
13,989,510

 
14,608,835

 
15,495,537

Depreciation and amortization
6,416,221

 
6,377,743

 
6,147,618

Taxes other than income taxes
2,965,250

 
2,795,609

 
2,324,426

Total operating expenses
$
52,696,228

 
$
73,224,377

 
$
80,242,432

 
 
 
 
 
 
Operating Income
$
11,433,992

 
$
12,963,861

 
$
15,603,439

 
 
 
 
 
 
Other Income
$
4,124

 
$
25,097

 
$
201,462

 
 
 
 
 
 
Interest Charges
 
 
 
 
 
Interest on long-term debt
$
2,245,224

 
$
2,309,124

 
$
2,373,024

Other interest expense
52,533

 
51,538

 
51,563

Amortization of debt expense
233,500

 
240,000

 
246,600

Total interest charges
$
2,531,257

 
$
2,600,662

 
$
2,671,187

 
 
 
 
 
 
 
 
 
 
 
 
Net Income Before Income Taxes
$
8,906,859

 
$
10,388,296

 
$
13,133,714

 
 
 
 
 
 
Income Tax Expense
3,377,481

 
3,892,215
 
4,858,586

 
 
 
 
 
 
Net Income
$
5,529,378

 
$
6,496,081

 
$
8,275,128

 
 
 
 
 
 
Earnings Per Common Share (Note 11)
 
 
 
 
 
Basic and Diluted
$
.78

 
$
.92

 
$
1.19

 
 
 
 
 
 
Dividends Declared Per Common Share
$
.82

 
$
.80

 
$
.76








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
For the Year Ended June 30,
2016
 
2015
 
2014
 
 
 
 
 
 
Cash Flows From Operating Activities
 
 
 
 
 
Net income
$
5,529,378

 
$
6,496,081

 
$
8,275,128

 
 
 
 
 
 
Adjustments to reconcile net income to net
 
 
 
 
 
cash from operating activities
 
 
 
 
 
Depreciation and amortization
6,649,721

 
6,617,743

 
6,420,525

Deferred income taxes and investment
 
 
 
 
 
tax credits
1,193,793

 
1,449,471

 
(515,492
)
Change in cash surrender value of officer's
 
 
 
 
 
life insurance
6,198

 
(19,036
)
 
(67,722
)
Share-based compensation
452,230

 
1,095,051

 
1,111,966

Excess tax deficiency from share-based compensation
(7,581
)
 
(9,574
)
 
(8,967
)
 
 
 
 
 
 
(Increase) decrease in assets
 
 
 
 
 
Accounts receivable
1,091,517

 
871,270

 
2,216,925

Natural gas in storage
1,344,242

 
2,491,337

 
(1,644,186
)
Deferred natural gas cost
(674,077
)
 
724,923

 
3,197,921

Materials and supplies
(4,549
)
 
(12,578
)
 
(288,597
)
Prepayments
(1,226,279
)
 
(363,263
)
 
(1,253,798
)
Other assets
(288,867
)
 
225,771

 
11,556

 
 
 
 
 
 
Increase (decrease) in liabilities
 
 
 
 
 
Accounts payable
(1,181,356
)
 
(1,135,821
)
 
169,226

Accrued taxes
106,856

 
(80,925
)
 
83,528

Asset retirement obligations
(85,068
)
 
375,073

 
(553,612
)
Other liabilities
1,832,112

 
20,658

 
185,805

 
 
 
 
 
 
Net cash provided by operating activities
$
14,738,270

 
$
18,746,181

 
$
17,340,206

 
 
 
 
 
 
Cash Flows From Investing Activities
 
 
 
 
 
Capital expenditures
$
(6,302,666
)
 
$
(9,010,876
)
 
$
(8,077,642
)
Proceeds from sale of property, plant and equipment
275,397

 
161,311

 
268,082

Other
(60,000
)
 
(60,000
)
 
(60,000
)
 
 
 
 
 
 
Net cash used in investing activities
$
(6,087,269
)
 
$
(8,909,565
)
 
$
(7,869,560
)
 
 
 
 
 
 

 



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

38



Delta Natural Gas Company, Inc.
 
Consolidated Statements of Cash Flows (continued)
For the Year Ended June 30,
2016
 
2015
 
2014
 
 
 
 
 
 
Cash Flows From Financing Activities
 
 
 
 
 
Dividends on common shares
$
(5,822,259
)
 
$
(5,639,791
)
 
$
(5,289,911
)
Issuance of common shares
614,518

 
532,712

 
595,249

Excess tax benefit from share-based compensation
2,073

 
18,823

 
39,472

Payment of minimum tax withholdings on share-based compensation

(263,044
)
 

 

Repayment of long-term debt
(1,500,000
)
 
(1,500,000
)
 
(1,500,000
)
Borrowings on bank line of credit

 
126,430

 
691,157

Repayment of bank line of credit

 
(126,430
)
 
(691,157
)
 
 
 
 
 
 
Net cash used in financing activities
$
(6,968,712
)
 
$
(6,588,256
)
 
$
(6,155,190
)
 
 
 
 
 
 
 
 
 
 
 
 
Net Increase in Cash and Cash Equivalents
$
1,682,289

 
$
3,248,360

 
$
3,315,456

 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents,  Beginning of Year
16,924,278

 
13,675,918

 
10,360,462

 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents,  End of Year
$
18,606,567

 
$
16,924,278

 
$
13,675,918

 
 
 
 
 
 
Supplemental Disclosures of Cash Flow Information
 
 
 
 
 
 
 
 
 
 
 
Cash paid during the year for
 
 
 
 
 
Interest
$
2,298,228

 
$
2,369,078

 
$
2,436,435

Income taxes (net of refunds)
$
2,064,005

 
$
3,312,944

 
$
5,819,956

 
 
 
 
 
 
Significant non-cash transactions
 
 
 
 
 
Accrued capital expenditures
$
157,808

 
$
207,169

 
$
328,638






 







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

39



 Delta Natural Gas Company, Inc.

Consolidated Balance Sheets
As of June 30,
2016
 
2015
 
 
 
 
Assets
 
 
 
 
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
18,606,567

 
$
16,924,278

Accounts receivable, less accumulated allowances for doubtful
 
 
 
accounts of $301,000 and $258,000 in 2016 and 2015, respectively
4,741,595

 
5,760,550

Natural gas in storage, at average cost (Note 1)
3,289,920

 
4,634,162

Deferred natural gas costs (Notes 1 and 14)
674,077

 

Materials and supplies, at average cost
544,342

 
543,563

Prepayments
3,051,665

 
3,347,187

 
 
 
 
Total current assets
$
30,908,166

 
$
31,209,740

 
 
 
 
Property, Plant and Equipment
$
241,833,771

 
$
236,780,490

Less - Accumulated provision for depreciation
(104,192,898
)
 
(98,741,351
)
 
 
 
 
Net property, plant and equipment
$
137,640,873

 
$
138,039,139

 
 
 
 
Other Assets
 
 
 
Cash surrender value of  life insurance
 
 
 
(face amount of $954,000 and $951,000 in 2016 and 2015, respectively)
$
414,985

 
$
421,183

Prepaid pension (Note 6)

 
2,145,969

Regulatory assets (Note 1)
18,881,126

 
14,917,823

Other non-current assets
1,033,979

 
977,312

 
 
 
 
Total other assets
$
20,330,090

 
$
18,462,287

 
 
 
 
Total assets
$
188,879,129

 
$
187,711,166















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

40



Delta Natural Gas Company, Inc.

Consolidated Balance Sheets (continued)

As of June 30,
2016
 
2015
 
 
 
 
Liabilities and Shareholders' Equity
 
 
 
 
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
4,200,298

 
$
5,426,395

Current portion of long-term debt (Note 10)
1,500,000

 
1,500,000

Accrued taxes
1,584,675

 
1,472,401

Customers' deposits
618,137

 
600,788

Accrued interest on debt
111,825

 
112,296

Accrued vacation
756,138

 
749,031

Regulatory liability - refundable natural gas costs (Note 1)

 
756

Other liabilities
585,342

 
610,238

 
 
 
 
Total current liabilities
$
9,356,415

 
$
10,471,905

 
 
 
 
Long-Term Debt (Notes 1 and 10)
$
50,422,796

 
$
51,916,296

 
 
 
 
Long-Term Liabilities
 
 
 
Deferred income taxes
$
43,405,098

 
$
42,130,067

Investment tax credits

 
10,800

Regulatory liabilities (Note 1)
1,138,141

 
1,137,758

Accrued Pension
1,833,780

 

Asset retirement obligations (Note 4)
3,917,585

 
3,795,590

Other long-term liabilities
1,078,345

 
1,027,096

 
 
 
 
Total long-term liabilities
$
51,372,949

 
$
48,101,311

 
 
 
 
Commitments and Contingencies (Note 13)
 
 
 
 
 
 
 
Total liabilities
$
111,152,160

 
$
110,489,512

 
 
 
 
Shareholders' Equity
 
 
 
Common shares ($1.00 par value), 20,000,000 shares authorized;
    7,087,762 and 7,026,500 shares outstanding at June 30, 2016
    and June 30, 2015, respectively
$
7,087,762

 
$
7,026,500

Premium on common shares
49,472,542

 
48,735,608

Retained earnings
21,166,665

 
21,459,546