PART I
Item 1. Business
General -
Delta Natural Gas Company, Inc. (Nasdaq: DGAS) distributes or transports natural gas to approximately
36,000
customers. Our distribution and transmission pipeline systems are located in central and southeastern Kentucky, and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their natural gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system and sell liquids extracted from natural gas in our storage field and on our pipeline systems. We have three wholly-owned subsidiaries. Delta Resources, Inc. (“Delta Resources”) buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. (“Delgasco”) buys natural gas and resells it to Delta Resources and to customers not on Delta's system. Enpro, Inc. (“Enpro”) owns and operates production properties and undeveloped acreage.
References to “Delta”, “the Company”, “we”, “us” and “our” refer to Delta Natural Gas Company, Inc. and its consolidated subsidiaries, except as otherwise stated. We were incorporated under the laws of the Commonwealth of Kentucky on October 7, 1949.
Unless otherwise stated, “
2013
”, “
2012
” and “
2011
” refers to the respective twelve month periods ending June 30.
We seek to provide dependable, high-quality service to our customers while steadily enhancing value for our shareholders. Our efforts have been focused on developing a balance of regulated and non-regulated businesses to contribute to our earnings by profitably selling, transporting, producing and processing natural gas in our service territory.
We strive to achieve operational excellence through economical, reliable service with an emphasis on responsiveness to customers. We continue to invest in facilities for the distribution, transmission and storage of natural gas. We believe that our responsiveness to customers and the dependability of the service we provide afford us additional opportunities for growth. While we seek those opportunities, we will continue a conservative strategy of minimizing our exposure to market risk arising from fluctuations in the prices of natural gas.
We operate through two segments, a regulated segment and a non-regulated segment.
Our executive offices are located at 3617 Lexington Road, Winchester, Kentucky 40391. Our telephone number is (859) 744-6171. Our website is www.deltagas.com.
Regulated Operations
Distribution and Transportation
Through our regulated segment, we distribute natural gas to our retail customers in
23
predominantly rural counties. In addition, our regulated segment transports natural gas to industrial customers on our system who purchase their natural gas in the open market. Our regulated segment also transports natural gas on behalf of local producers and other customers not on our distribution system.
The economy of our service area is based principally on coal mining, farming and light industry. The communities we serve typically contain populations of less than
20,000
. Our three largest service areas are
Nicholasville, Corbin and Berea, Kentucky
. In Nicholasville we serve approximately
8,000
customers, in Corbin we serve approximately
6,000
customers and in Berea we serve approximately
4,000
customers. Some of the communities we serve continue to expand, resulting in growth opportunities for us. Industrial parks have been developed in our service areas, which could result in additional growth in industrial customers as well.
The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. Their regulation of our business includes approving the rates we are permitted to charge our regulated
customers. The impact of this regulation is further discussed in Note 14 of the Notes to Consolidated Financial Statements, in Item 8. Financial Statements and Supplementary Data and under “Regulatory Matters” in Item 1. Business.
Factors that affect our regulated revenues include the rates we charge our customers, economic conditions in our service areas, competition, our supply cost for the natural gas we purchase for resale and weather. Our current rate design lessens the impact weather has on our regulated revenues as our rates include both a fixed monthly customer charge and a volumetric rate which has a weather normalization provision that adjusts rates due to variations in weather. Market risk arising from fluctuations in the price of gas is mitigated through the gas cost recovery rate mechanism which permits us to pass through to our regulated customers changes in the price we must pay for our gas supply. However, increases in our rates may cause our customers to conserve or to use alternative energy sources.
Our regulated sales are seasonal and temperature-sensitive, since the majority of the natural gas we sell is used for heating. During
2013
,
73%
of the regulated volumes were sold during the heating season (December through April). Variations in the average temperature during the winter impact our volumes sold. The Kentucky Public Service Commission, through a weather normalization provision in our tariff, permits us to adjust the rates we charge our customers in response to winter weather that is warmer or colder than normal temperatures.
We compete with alternate sources of energy for our regulated distribution customers. These alternate sources include electricity, coal, oil, propane, wood and solar.
Our larger regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the natural gas to their plants or facilities. Customers for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers. Customers may undertake such a by-pass in order to seek lower prices for their gas and/or transportation services. Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. Additionally, some of our industrial customers are able to switch to alternative sources of energy. These are competitive concerns that we continue to address by utilizing our non-regulated segment to offer these customers gas supply at competitive market-based rates.
Some natural gas producers in our service area can access pipeline delivery systems other than ours, which generates competition for our transportation services. We continue our efforts to purchase or transport natural gas that is produced in reasonable proximity to our transportation facilities through our regulated segment.
As an active participant in many areas of the natural gas industry, we plan to continue efforts to expand our natural gas transmission and distribution system and customer base. We continue to consider acquisitions of other natural gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas.
Gas Supply
We maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of natural gas for our customers. We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended
June 30, 2013
, we purchased approximately
98%
of our natural gas from interstate sources.
Interstate Gas Supply
Our regulated segment acquires its interstate gas supply from gas marketers. We currently have commodity requirements agreements with Atmos Energy Marketing (“Atmos”) for our Columbia Gas Transmission Corporation (“Columbia Gas”), Columbia Gulf Transmission Corporation (“Columbia Gulf”), Tennessee Gas Pipeline (“Tennessee”) and Texas Eastern Transmission Corporation (“Texas Eastern”) supplied areas. Under these commodity requirements agreements, Atmos is obligated to supply the volumes consumed by our regulated customers in defined sections of our service areas. We are not obligated to purchase any minimum quantities from Atmos or purchase natural gas from them for any period longer than one month at a time. The natural gas we purchase under these agreements is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices. The index-based market prices are determined based on the prices published on the first of each month in Platts' Inside FERC's Gas Market Report for the indices that relate to the pipelines through which the gas will be transported, plus or minus an agreed-to fixed price adjustment per million British Thermal Units of gas purchased. Consequently, the price we pay for interstate natural gas is based on current market prices.
Our agreements with Atmos for the Columbia Gas, Columbia Gulf, Tennessee and Texas Eastern supplied service areas continue year to year unless canceled by either party by written notice at least sixty days prior to the annual anniversary date (April
30) of the agreement. In our fiscal year ended
June 30, 2013
, approximately
61%
of our regulated gas supply was purchased under our agreements with Atmos.
Our regulated segment purchases natural gas from M&B Gas Services ("M&B") and Midwest Energy Services, LLC ("Midwest") for injection into our underground natural gas storage field and to supply a portion of our system. We are not obligated to purchase any minimum quantities from either M&B or Midwest, nor are we required to purchase natural gas from either company for any periods longer than one month at a time. The natural gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices. Our agreement with both M&B and Midwest may be terminated upon 30 days prior written notice by either party. In our fiscal year ended
June 30, 2013
, approximately
23%
and
14%
of our regulated gas supply was purchased under our agreements with M&B and Midwest, respectively.
We also purchase interstate natural gas from other gas marketers as needed at either current market prices, determined by industry publications, or at forward market prices.
Transportation of Interstate Gas Supply
Our interstate natural gas supply is transported to us from market hubs, production fields and storage fields by Tennessee, Columbia Gas, Columbia Gulf and Texas Eastern.
Our agreements with Tennessee currently extend through
October
,
2013
and thereafter automatically renew for subsequent five-year terms unless Delta notifies Tennessee of its intent not to renew the agreements at least one year prior to the expiration of any renewal terms. We intend to renew our agreements with Tennessee. Subject to the terms of Tennessee's Federal Energy Regulatory Commission gas tariff, Tennessee is obligated under these agreements to transport up to
19,600
thousand cubic feet (“Mcf”) per day for us. During fiscal 2013, Tennessee transported for us a total of
884,000
Mcf, or approximately
17%
of our regulated supply requirements, under these agreements. We have gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee's storage fields and we reserve the right to withdraw daily gas volumes up to certain specified fixed quantities. These gas storage agreements renew on the same schedule as our transportation agreements with Tennessee.
Under our agreements with Columbia Gas and Columbia Gulf, Columbia Gas is obligated to transport, including utilization of our defined storage space as required, up to
12,600
Mcf per day for us, and Columbia Gulf is obligated to transport up to a total of
4,300
Mcf per day for us. During fiscal 2013, Columbia Gas and Columbia Gulf transported for us a total of
2,192,000
Mcf, or approximately
43%
of our regulated supply requirements, under all of our agreements with them. Our transportation agreements with Columbia Gas and Columbia Gulf extend through 2015. After 2015, our agreement with Columbia Gas continues on a year-to-year basis unless terminated by one of the parties, but may be extended by mutual agreement.
Columbia Gulf also transported additional volumes under agreements it has with M & B and Midwest to a point of interconnection between Columbia Gulf and us where we purchase the gas to inject into our storage field. The amounts transported and sold to us under the agreements Columbia Gulf has with M & B and Midwest for fiscal
2013
constituted approximately
37%
of our regulated gas supply. We are not a party to any of these separate transportation agreements on Columbia Gulf.
We have no direct agreement with Texas Eastern. However, Atmos has an arrangement with Texas Eastern to transport the gas to us that we purchase from Atmos to supply our customers' requirements in specific geographic areas. In our fiscal year ended
June 30, 2013
, Texas Eastern transported approximately
13,000
Mcf of natural gas to our system, which constituted less than
1%
of our gas supply.
Kentucky Gas Supply
We have an agreement with Vinland Energy Operations LLC ("Vinland") to purchase natural gas on a year-to-year basis unless terminated by one of the parties. We purchased
41,000
Mcf from Vinland during fiscal
2013
. The price for the gas we purchase from Vinland is based on the index price of spot gas delivered to Columbia Gas in the relevant region as reported in Platts' Inside FERC's Gas Market Report. Vinland delivers this gas to our customer meters directly from its own pipelines. In fiscal
2013
, the natural gas we purchased from Vinland constituted approximately
1%
of our regulated gas supply.
Gas in Storage
We own and operate an underground natural gas storage field that we use to store a significant portion of our gas supply needs. This storage capability permits us to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months. We have a legal obligation to retire wells located at this underground natural gas storage facility.
However, since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the wells have an indeterminate life and have therefore not recorded a liability associated with the cost to retire the wells.
Regulatory Matters
The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. Their regulation of our business includes approving the rates we are permitted to charge our regulated customers. We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services. They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return. We do not have any matters pending before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial positions or cash flows.
We have a pipe replacement program which allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to our last rate case which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.
The Kentucky Public Service Commission allows us a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs and any bad debt expense related to gas cost. Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission. Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred.
Additionally, we have a weather normalization clause in our rate tariffs, approved by the Kentucky Public Service Commission, which provides for the adjustment of our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles. These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts.
The Kentucky Public Service Commission also allows us a conservation and efficiency program for our residential customers. Through this program, we perform energy audits, promote conservation awareness and provide rebates on the purchase of certain high efficiency appliances. The program helps to align our interests with our residential customers' interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation. Our rates are adjusted annually to recover the costs incurred under these programs, the reimbursement of margins on lost sales and the incentives provided to us.
In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise. We hold franchises in five of the cities we serve, and we continue to operate under the conditions of expired franchises in four other cities we serve. In the other cities and areas we serve, there are no governmental organizations authorized to grant franchises or the city governments do not require a franchise. We attempt to acquire or reacquire franchises whenever feasible. Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city. To date, the absence of a franchise has not adversely affected our operations.
Non-Regulated Operations
Natural Gas Marketing
Our non-regulated segment includes three wholly-owned subsidiaries. Two of these subsidiaries, Delta Resources and Delgasco, purchase natural gas in the open market, including natural gas from Kentucky producers. We resell this gas to industrial customers on our distribution system and to others not on our system.
Factors that affect our non-regulated revenues include the rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition.
Our larger non-regulated customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Additionally, some
of our industrial customers are able to switch economically to alternative sources of energy. We continue to address these competitive concerns by offering these customers gas supply at competitive market based rates.
In our fiscal year ended
June 30, 2013
, approximately
96%
of our non-regulated revenue was derived from our natural gas marketing activities. In our non-regulated segment, two customers each provided more than 5% of our operating revenues. Seminole Energy provided approximately
$17,866,000
,
$12,450,000
and
$11,461,000
of non-regulated revenues during
2013
,
2012
and
2011
, respectively. Atmos provided approximately
$5,390,000
,
$6,815,000
and
$8,067,000
of non-regulated revenues during
2013
,
2012
and
2011
, respectively. There is no assurance that revenues from these customers will continue at these levels.
Natural Gas Production
Our subsidiary, Enpro, produces natural gas that is sold to Delgasco for resale in the open market. Item 2. Properties further describes Enpro's oil and natural gas leases and production properties. Enpro produced a total of
103,000
Mcf of natural gas during
2013
which was approximately
1%
of the non-regulated volumes sold.
Natural Gas Liquids
In order to improve the operations of our distribution, transmission and storage system, we operate a facility that is designed to extract liquids from the natural gas in our system. We sell these natural gas liquids at a price determined by a national unregulated market. In our fiscal year ended
June 30, 2013
, approximately
4%
of our non-regulated revenue was derived from the sale of natural gas liquids.
Gas Supply
Our non-regulated segment purchases natural gas from M&B and Midwest. Our underlying agreements with M&B and Midwest do not obligate us to purchase any minimum quantities from M&B or Midwest, nor to purchase gas from either company for any periods longer than one month at a time. The gas is priced at index-based market prices or at mutually agreed-to fixed prices based on forward market prices. Our agreements with both M&B and Midwest may be terminated upon 30 days prior written notice by either party. Any purchase agreements for unregulated sales activities may have longer terms or multiple month purchase commitments. In our fiscal year ended
June 30, 2013
,
50%
and
6%
of our non-regulated gas supply was purchased under our agreements with M&B and Midwest, respectively.
Additionally, our non-regulated segment purchases natural gas from Atmos as needed. This spot gas purchasing arrangement is pursuant to an agreement with Atmos containing an “evergreen” clause which permits either party to terminate the agreement by providing not less than sixty days written notice. Our purchases from Atmos under this spot purchase agreement are generally month-to-month. However, we have the option of forward-pricing gas for one or more months. The price of gas under this agreement is based on current market prices. In our fiscal year ended
June 30, 2013
, approximately
43%
of our non-regulated gas supply was purchased under our agreement with Atmos.
We also purchase interstate natural gas from other gas marketers and Kentucky producers as needed at either current market prices, determined by industry publications, or at forward market prices.
We anticipate continuing our non-regulated activities and intend to pursue and increase these activities wherever practicable.
Capital Expenditures
Capital expenditures during
2013
were
$7.2
million and for
2014
are estimated to be
$7.8
million. Our expenditures include system extensions as well as the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities.
Financing
Our capital expenditures and operating cash requirements are met through the use of internally generated funds and a short-term bank line of credit. The current available line of credit is
$40 million
, all of which was available at
June 30, 2013
.
Our current bank line of credit extends through
June 30, 2015
and will be utilized to meet capital expenditure and operating cash requirements. The amounts and types of future long-term debt and equity financings will depend upon our capital needs and market conditions.
We currently have long-term debt of
$56,500,000
in the form of our Series A Notes. The Series A Notes are unsecured, bear interest at
4.26%
per annum and mature on
December 20, 2031
. Accrued interest on the Series A Notes is payable quarterly and we are required to make a
$1,500,000
principal reduction payment on the Series A Notes each December.
Employees
On
June 30, 2013
, we had
150
full-time employees. We consider our relationship with our employees to be satisfactory. Our employees are not represented by unions nor are they subject to any collective bargaining agreements.
Available Information
We make available free of charge on our Internet website http://www.deltagas.com, our Business Code of Conduct and Ethics, annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC also maintains an Internet site http://www.sec.gov that contains reports, proxy and information statements and other information regarding Delta. The public may read and copy any materials the Company files with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. The SEC's phone number is 1-800-732-0330.
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Consolidated Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended June 30,
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
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|
Average Regulated Customers Served
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
29,755
|
|
|
29,929
|
|
|
30,420
|
|
|
30,575
|
|
|
30,881
|
|
Commercial
|
4,906
|
|
|
4,890
|
|
|
4,949
|
|
|
4,957
|
|
|
5,009
|
|
Industrial
|
40
|
|
|
41
|
|
|
44
|
|
|
46
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
34,701
|
|
|
34,860
|
|
|
35,413
|
|
|
35,578
|
|
|
35,939
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
($000)
(a)
|
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|
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|
|
|
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Regulated (b)
|
|
|
|
|
|
|
|
|
|
Residential sales
|
24,342
|
|
|
22,720
|
|
|
25,800
|
|
|
23,783
|
|
|
33,774
|
|
Commercial sales
|
15,849
|
|
|
14,026
|
|
|
16,672
|
|
|
15,894
|
|
|
24,125
|
|
Industrial sales
|
1,011
|
|
|
914
|
|
|
1,199
|
|
|
1,075
|
|
|
1,769
|
|
On-system transportation
|
5,237
|
|
|
4,780
|
|
|
4,830
|
|
|
4,421
|
|
|
4,118
|
|
Off-system transportation
|
3,800
|
|
|
3,595
|
|
|
3,670
|
|
|
3,650
|
|
|
3,786
|
|
Other
|
333
|
|
|
324
|
|
|
303
|
|
|
294
|
|
|
333
|
|
Total regulated revenues
|
50,572
|
|
|
46,359
|
|
|
52,474
|
|
|
49,117
|
|
|
67,905
|
|
|
|
|
|
|
|
|
|
|
|
Non-regulated sales
|
34,238
|
|
|
31,423
|
|
|
34,343
|
|
|
30,746
|
|
|
41,159
|
|
Intersegment eliminations (c)
|
(4,145
|
)
|
|
(3,704
|
)
|
|
(3,777
|
)
|
|
(3,441
|
)
|
|
(3,427
|
)
|
|
|
|
|
|
|
|
|
|
|
Total
|
80,665
|
|
|
74,078
|
|
|
83,040
|
|
|
76,422
|
|
|
105,637
|
|
|
|
|
|
|
|
|
|
|
|
System Throughput
(Million Cu. Ft.)
(a)
|
|
|
|
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
|
|
|
|
Residential sales
|
1,659
|
|
|
1,331
|
|
|
1,737
|
|
|
1,756
|
|
|
1,721
|
|
Commercial sales
|
1,291
|
|
|
1,027
|
|
|
1,310
|
|
|
1,331
|
|
|
1,346
|
|
Industrial sales
|
107
|
|
|
90
|
|
|
120
|
|
|
111
|
|
|
113
|
|
On-system transportation
|
4,988
|
|
|
4,724
|
|
|
4,830
|
|
|
4,533
|
|
|
4,215
|
|
Off-system transportation
|
11,795
|
|
|
11,225
|
|
|
11,531
|
|
|
11,039
|
|
|
11,908
|
|
Total regulated throughput
|
19,840
|
|
|
18,397
|
|
|
19,528
|
|
|
18,770
|
|
|
19,303
|
|
|
|
|
|
|
|
|
|
|
|
Non-regulated sales
|
7,650
|
|
|
6,455
|
|
|
6,010
|
|
|
4,787
|
|
|
4,219
|
|
Intersegment eliminations (c)
|
(7,497
|
)
|
|
(6,326
|
)
|
|
(5,890
|
)
|
|
(4,692
|
)
|
|
(4,135
|
)
|
|
|
|
|
|
|
|
|
|
|
Total
|
19,993
|
|
|
18,526
|
|
|
19,648
|
|
|
18,865
|
|
|
19,387
|
|
|
|
|
|
|
|
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Average Annual Consumption Per
|
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|
|
|
|
|
|
Average Residential Customer
|
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|
|
|
|
|
|
|
|
(Thousand Cu. Ft.)
|
56
|
|
|
44
|
|
|
57
|
|
|
57
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
Lexington, Kentucky Degree Days
|
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|
|
|
|
|
|
|
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Actual
|
4,667
|
|
|
3,797
|
|
|
4,725
|
|
|
4,782
|
|
|
4,651
|
|
Percent of 30 year average
|
104
|
|
|
83
|
|
|
103
|
|
|
104
|
|
|
101
|
|
(a) Additional financial information related to our segments can be found in Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 15 of the Notes to Consolidated Financial Statements.
(b) We implemented new regulated base rates, as approved by the Kentucky Public Service Commission in October, 2010, which were designed to generate additional annual revenue of $3,513,000.
(c) Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates.
Item 1A. Risk Factors
The risk factors below should be carefully considered.
WEATHER CONDITIONS MAY CAUSE OUR REVENUES TO VARY FROM YEAR TO YEAR.
Our revenues vary from year to year, depending on weather conditions. We estimate that approximately
73%
of our annual gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year, which would reduce our revenues and profits. The weather normalization provision in our tariff, approved by the Kentucky Public Service Commission, only partially mitigates this risk. Under our weather normalization provision in our tariff, we adjust our rates for our residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles.
CHANGES IN FEDERAL REGULATIONS COULD REDUCE THE AVAILABILITY OR INCREASE THE COST OF OUR INTERSTATE GAS SUPPLY.
We purchase almost all of our gas supply from interstate sources. For example, in
2013
, approximately
98%
of our gas supply was purchased from interstate sources. The Federal Energy Regulatory Commission regulates the transmission of the natural gas we receive from interstate sources, and it could increase our transportation costs or decrease our available pipeline capacity by changing its regulatory policies. Additionally, federal legislation could restrict or limit drilling which could decrease the supply of available natural gas. A decrease in available pipeline capacity or decrease in natural gas available to us could result in a loss of customers and decrease in profits.
OUR GAS SUPPLY DEPENDS UPON THE AVAILABILITY OF ADEQUATE PIPELINE TRANSPORTATION CAPACITY.
We purchase almost all of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of gas. A decrease in our normal interstate supply of gas could result in a loss of customers and decrease in profits.
OUR CUSTOMERS ARE ABLE TO BY-PASS OUR DISTRIBUTION AND TRANSMISSION SYSTEMS.
Our larger customers can obtain their natural gas supply by purchasing directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers for whom we transport natural gas could by-pass our transportation system to directly connect to interstate pipelines or other transportation providers. Customers may undertake such by-passes in order to achieve lower prices for their gas and/or transportation services. Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. This potential to by-pass our distribution and transportation systems creates a risk of the loss of large customers and thus could result in lower revenues and profits.
ACTIONS BY OUR REGULATORS COULD DECREASE FUTURE PROFITABILITY.
We are regulated by the Kentucky Public Service Commission. Our regulated segment generates a significant portion of our operating revenues. We face the risk that the Kentucky Public Service Commission may fail to grant us adequate and timely rate increases or may take other actions that would cause a reduction in our income from operations, such as limiting our ability to pass on to our customers our increased costs of natural gas. Such regulatory actions would decrease our revenues and our profitability. Additionally, our consolidated financial statements reflect the application of regulatory accounting standards by our regulated segment. Our regulated segment has recognized regulatory assets representing costs incurred in prior periods that are probable of recovery from customers in future rates. Disallowance of such costs in future proceedings before the Kentucky Public Service Commission could require us to write-off regulatory assets, which could have a material impact on our income and consolidated financial statements.
VOLATILITY IN PRICES COULD REDUCE OUR PROFITS.
Significant increases in the price of natural gas will likely cause our regulated retail customers to increase conservation or switch to alternate sources of energy. Any decrease in the volume of gas we sell that is caused by such actions will reduce our revenues and profits. Higher prices also make it more difficult to add new customers. Significant decreases in the price of natural
gas will likely cause our non-regulated segment's gross margins to decrease. The price of natural gas liquids is determined by a national unregulated market, and decreases in the price could result in a decrease in our non-regulated gross margins.
INTERSTATE AND OTHER PIPELINES DELTA INTERCONNECTS WITH CAN IMPOSE RESTRICTIONS ON THEIR PIPELINE.
The pipelines interconnected to Delta's system are owned and operated by third parties who can impose restrictions on the quantity and quality of natural gas they will accept into their pipelines. To the extent natural gas on Delta's system does not conform to these restrictions, Delta could experience a decrease in volumes sold or transported to these pipelines.
FUTURE PROFITABILITY OF THE NON-REGULATED SEGMENT IS DEPENDENT ON A FEW INDUSTRIAL AND OTHER LARGE USE CUSTOMERS.
Our larger non-regulated customers are primarily industrial and other large use customers. Fluctuations in the gas requirements of these customers can have a significant impact on the profitability of the non-regulated segment.
A DECLINE IN THE LIQUIDS PRESENT IN OUR NATURAL GAS SUPPLY COULD REDUCE OUR NON-REGULATED REVENUES.
In order to improve the operations of our distribution, transmission and storage system, we operate a facility that is designed to extract liquids from the natural gas in our system. We are able to sell these liquids at a price determined by a national unregulated market. A reduction in the quantity of liquids present in our gas supply could result in a reduction of the earnings of our non-regulated segment.
WE RELY ON ACCESS TO CAPITAL TO MAINTAIN LIQUIDITY.
To the extent that internally generated cash coupled with short-term borrowings under our bank line of credit is not sufficient for our operating cash requirements and normal capital expenditures, we may need to obtain additional financing. Additionally, market disruptions may increase our cost of borrowing or adversely affect our access to capital markets. Such disruptions could include: economic downturns, the bankruptcy of an unrelated energy company, general capital market conditions, market price for natural gas, terrorist attacks or the overall health of the energy industry. There is no guarantee we could obtain needed capital in the future.
POOR INVESTMENT PERFORMANCE OF PENSION PLAN HOLDINGS AND OTHER FACTORS IMPACTING PENSION PLAN COSTS COULD UNFAVORABLY IMPACT OUR LIQUIDITY AND RESULTS OF OPERATIONS.
Our cost of providing a non-contributory defined benefit pension plan is dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding level of the plan, future government regulation and our required or voluntary contributions made to the plan. Without sustained growth in the pension investments over time to increase the value of the plan assets and depending upon the other factors impacting our costs as listed above, we could be required to fund our plan with additional significant amounts of cash. Such cash funding obligations could have a material impact on our financial position, results of operations or cash flows.
WE ARE EXPOSED TO CREDIT RISKS OF CUSTOMERS AND OTHERS WITH WHOM WE DO BUSINESS.
Adverse economic conditions affecting, or financial difficulties of, customers and others with whom we do business could impair the ability of these customers and others to pay for our services or fulfill their contractual obligations or cause them to delay such payments or obligations. We depend on these customers and others to remit payments on a timely basis. Any delay or default in payment could adversely affect our cash flows, financial position or results of operations.
SUBSTANTIAL OPERATIONAL RISKS ARE INVOLVED IN OPERATING A NATURAL GAS DISTRIBUTION, TRANSPORTATION, LIQUIDS EXTRACTION AND STORAGE SYSTEM AND SUCH OPERATIONAL RISKS COULD REDUCE OUR REVENUES AND INCREASE EXPENSES.
There are substantial risks associated with the operation of a natural gas distribution, transportation, liquids extraction and storage system, such as operational hazards and unforeseen interruptions caused by events beyond our control. These include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of pipeline and storage facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, floods,
landslides or other similar events beyond our control. These risks could result in injury or loss of life, extensive property damage or environmental pollution, which in turn could lead to substantial financial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks. Liabilities incurred that are not fully covered by insurance could adversely affect our results of operations and financial condition. Additionally, interruptions to the operation of our gas distribution, transmission or storage system caused by such an event could reduce our revenues and increase our expenses.
HURRICANES, EXTREME WEATHER OR WELL-HEAD DISASTERS COULD DISRUPT OUR GAS SUPPLY AND INCREASE NATURAL GAS PRICES.
Hurricanes, extreme weather or well-head disasters could damage production or transportation facilities, which could result in decreased supplies of natural gas, increased supply costs for us and higher prices for our customers. Such events could also result in new governmental regulations or rules that limit production or raise production costs.
OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS FINANCIAL AND NEGATIVE COVENANTS AND A PREPAYMENT PENALTY THAT COULD RESTRICT OUR ACTIVITIES.
Our bank line of credit and Series A Notes contain financial covenants. Noncompliance with these covenants can make the obligations immediately due and payable. If we breach any of the financial covenants under these agreements, our debt repayment obligations under the bank line of credit and Series A Notes could be accelerated. In such event, we may not be able to refinance, repay all our indebtedness, pay dividends or have sufficient liquidity to meet our operating and capital expenditure requirements, all of which could result in a material adverse effect on our business, results of operations and financial condition. Furthermore, a default on the performance of any single obligation incurred in connection with our borrowings, or a default on other indebtedness that exceeds $2,500,000, simultaneously creates an event of default with the bank line of credit and the Series A Notes. Additionally, our bank line of credit and Series A Notes contain various negative covenants and a prepayment penalty which create a risk that we may be unable to take advantage of business and financing opportunities as they arise.
OUR LONG-TERM DEBT ARRANGEMENTS LIMIT THE AMOUNT OF DIVIDENDS WE MAY PAY AND OUR REPURCHASE OF STOCK.
Under the terms of our
4.26%
Series A Notes, the aggregate amount we may pay in dividends on our common stock and in repurchase of our common stock may not exceed the sum of
$15,000,000
and our cumulative net income after
September 30, 2011
. Between
September 30, 2011
and
June 30, 2013
, we paid
$8,526,000
in dividends, repurchased no stock and have had cumulative net income of
$13,318,000
. Consequently, as of June 30, 2013 our Series A Notes permitted us to pay up to
$19,792,000
in dividends and for the repurchase of our common stock. However, if we fail to generate sufficient net income in the future, our ability to continue to pay our regular quarterly dividend may be impaired and the value of our common stock would likely decline.
A SECURITY BREACH COULD DISRUPT OUR IT SYSTEMS, INTERRUPT THE NATURAL GAS SERVICE WE PROVIDE TO OUR CUSTOMERS, COMPROMISE THE SAFETY OF OUR NATURAL GAS DISTRIBUTION, TRANSMISSION AND STORAGE SYSTEMS OR EXPOSE CONFIDENTIAL PERSONAL INFORMATION.
Security breaches of our information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to IT system disruptions or shutdowns, result in the interruption of our ability to provide natural gas to our customers or compromise the safety of our distribution, transmission and storage systems. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.
Additionally, the protection of customer, employee, vendor, investor and company data is critical to us. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. There is no guarantee that the procedures that we have implemented to protect against unauthorized access to secured data are adequate to safeguard against all data security breaches.
FAILURE TO ATTRACT AND RETAIN AN APPROPRIATELY QUALIFIED WORKFORCE COULD UNFAVORABLY IMPACT OUR RESULTS OF OPERATIONS.
Certain events, such as an aging workforce, mismatch of skill sets to complement future needs, or unavailability of future resources, may lead to increased operational risks and costs. As a result of these events, we could face lack of resources knowledgeable about the natural gas industry and a lengthy time period associated with skill development and knowledge transfer.
Failure to address this risk may result in increased operational and safety risks as well as increased costs. Even if we have reasonable plans in place to address succession planning and workforce training, we cannot control the future availability of qualified labor. If we are unable to successfully attract and retain an appropriately qualified workforce, our financial position or results of operations could be negatively affected.
NEW LAWS OR REGULATIONS COULD HAVE A NEGATIVE IMPACT ON OUR FINANCIAL POSITION, RESULTS OF OPERATIONS OR CASH FLOWS.
Changes in laws and regulations, including new accounting standards, adoption of International Financial Reporting Standards and tax law, could change the way in which we are required to record revenues, expenses, assets and liabilities. Additionally, governing bodies may choose to re-interpret laws and regulations. These changes could have a negative impact on our financial position, cash flows, results of operations or access to capital.
CLIMATE CHANGE LEGISLATION MAY POSE NEW FINANCIAL OR REGULATORY RISKS.
A number of proposals to limit greenhouse gas emissions are pending at the regional, federal, and international levels. These proposals, if enacted and made applicable to us, may require us to measure and potentially limit greenhouse gas emissions from our utility operations and our customers or purchase allowances for such emissions. While we cannot predict the extent of these limitations or when or if they will become effective, the adoption of such proposals could increase utility costs related to operations, energy efficiency activities and compliance; affect the demand for natural gas; and increase the prices we charge our utility customers.
Unless we are able to timely recover the costs of such impacts from customers through the regulatory process, costs associated with any such regulatory or legislative changes could adversely affect Delta's results of operations, financial condition and cash flows.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Properties
We own our corporate headquarters in Winchester, Kentucky. We own eleven buildings used for field operations in the cities we serve.
We own approximately
2,500
miles of natural gas gathering, transmission, distribution and storage lines. These lines range in size up to twelve inches in diameter.
We hold leases for the storage of natural gas under
8,000
acres located in Bell County, Kentucky. We developed this property for the underground storage of natural gas.
We use all the properties described in the three paragraphs immediately above principally in connection with our regulated segment, as further discussed in Item 1. Business.
Through our wholly-owned subsidiary, Enpro, we produce natural gas as part of the non-regulated segment of our business. Enpro owns interests in oil and natural gas leases on
10,300
acres located in Bell, Knox and Whitley Counties.
Thirty-five
gas wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated at
2.7
million Mcf. Also, Enpro owns the natural gas underlying
15,400
additional acres in Bell, Clay and Knox Counties. These properties have been leased to others for further drilling and development. We have performed no reserve studies on these properties. Enpro produced a total of
103,000
Mcf of natural gas during fiscal
2013
from all the properties described in this paragraph.
A producer plans to conduct further exploration activities on part of Enpro's developed holdings. Enpro reserves the option to participate in wells drilled by this producer and also retains certain working and royalty interests in any production from future wells.
Our assets have no significant encumbrances.
Item 3.
Legal Proceedings
We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.
Item 4.
Mine Safety Disclosures
None.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
(a) Principles of Consolidation
Delta Natural Gas Company, Inc. (“Delta” or “the Company”) distributes or transports natural gas to approximately
36,000
customers. Our distribution and transportation systems are located in central and southeastern Kentucky and we own and operate an underground storage field in southeastern Kentucky. We transport natural gas to our industrial customers who purchase their gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system and sell liquids extracted from natural gas in our storage field and our pipeline systems. We have
three
wholly-owned subsidiaries. Delta Resources, Inc. ("Delta Resources") buys gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. buys gas and resells it to Delta Resources, Inc. and to customers not on Delta's system. Enpro, Inc. owns and operates production properties and undeveloped acreage. All subsidiaries of Delta are included in the consolidated financial statements. Intercompany balances and transactions have been eliminated.
(b) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(c) Cash Equivalents
For the purposes of the Consolidated Statements of Cash Flows, all temporary cash investments with a maturity of three months or less at the date of purchase are considered cash equivalents.
(d) Property, Plant and Equipment
Property, plant and equipment is stated at original cost, which includes materials, labor, labor related costs and an allocation of general and administrative costs. A betterment or replacement of a unit of property is accounted for as an addition of utility plant. Construction work in progress has been included in the rate base for determining customer rates, and therefore an allowance for funds used during construction has not been recorded. The cost of regulated plant retired or disposed of in the normal course of business is deducted from plant accounts and such cost, less salvage value, is charged to the accumulated provision for depreciation.
Property, plant and equipment is comprised of the following major classes of assets:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Regulated segment
|
|
|
|
Distribution, transmission and storage
|
197,251
|
|
|
192,107
|
|
General, miscellaneous and intangibles
|
22,009
|
|
|
21,963
|
|
Construction work in progress
|
1,711
|
|
|
724
|
|
Total regulated segment
|
220,971
|
|
|
214,794
|
|
|
|
|
|
Non-regulated segment
|
2,575
|
|
|
2,379
|
|
Total property, plant and equipment
|
223,546
|
|
|
217,173
|
|
We have a pipe replacement program approved by the Kentucky Public Service Commission, which allows us to adjust rates annually to earn a return on capital expenditures for the replacement of pipe and related facilities incurred subsequent to the test year in our most recent rate case. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.
(e) Depreciation
We determine the provision for depreciation using the straight-line method and by the application of rates to various classes of utility plant. The rates are based upon the estimated service lives of the properties and were equivalent to composite rates of
2.9%
,
2.9%
and
2.6%
of average depreciable plant for
2013
,
2012
and
2011
, respectively. Effective October, 2010 we implemented new depreciation rates approved by the Kentucky Public Service Commission in our 2010 rate case which decreased the remaining depreciable lives of our depreciable assets.
As approved by the Kentucky Public Service Commission, we accrue asset removal costs for certain types of property through depreciation expense with a corresponding increase to regulatory liabilities on the Consolidated Balance Sheet. When depreciable utility plant and equipment is retired any related removal costs incurred are charged against the regulatory liability.
(f) Maintenance
All expenditures for maintenance and repairs of units of property are charged to the appropriate maintenance expense accounts in the month incurred.
(g) Gas Cost Recovery
Our regulated gas rates include a gas cost recovery clause approved by the Kentucky Public Service Commission which provides for a dollar-tracker that matches revenues and gas costs and provides eventual dollar-for-dollar recovery of all gas costs incurred by the regulated segment and recovery of the uncollectible gas cost portion of bad debt expense. We expense gas costs based on the amount of gas costs recovered through revenue. Any differences between actual gas costs and those gas costs billed are deferred and reflected in the computation of future billings to customers using the gas cost recovery mechanism.
(h) Revenue Recognition
We bill our customers on a monthly meter reading cycle. At the end of each month, gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled.
Unbilled revenues and gas costs include the following:
|
|
|
|
|
|
|
(000)
|
2013
|
|
2012
|
|
|
|
|
Unbilled revenues ($)
|
1,435
|
|
|
1,358
|
|
Unbilled gas costs ($)
|
390
|
|
|
392
|
|
Unbilled volumes (Mcf)
|
47
|
|
|
46
|
|
Unbilled revenues are included in accounts receivable and unbilled gas costs are included in deferred gas costs on the accompanying Consolidated Balance Sheets.
(i) Excise Taxes
Certain excise taxes levied by state or local governments are collected by Delta from our customers. These taxes are accounted for on a net basis and therefore are not included as revenues in the accompanying Consolidated Statements of Income.
(j) Revenues and Accounts Receivable
Revenues and accounts receivable arise primarily from sales of natural gas to customers and from transportation services for others. Provisions for doubtful accounts are recorded to reflect the expected net realizable value of accounts receivable. Accounts receivable are charged off when deemed to be uncollectible or when turned over to a collection agency to pursue.
(k) Rate Regulated Basis of Accounting
We account for our regulated segment in accordance with applicable regulatory guidance. The economic effects of regulation can result in a regulated company recovering costs from customers in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this results, costs are deferred as assets on the Consolidated Balance Sheets (“regulatory assets”) and recorded as expenses when such amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for current collection in rates of costs that are expected to be incurred in the future (“regulatory liabilities”). The amounts recorded as regulatory assets and regulatory liabilities are as follows:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Regulatory assets
|
|
|
|
Current assets
|
|
|
|
Deferred gas costs
|
3,923
|
|
|
3,386
|
|
|
|
|
|
Other assets
|
|
|
|
Conservation/efficiency program expenses
|
198
|
|
|
236
|
|
Loss on extinguishment of debt
|
3,389
|
|
|
3,636
|
|
Asset retirement obligations
|
3,788
|
|
|
3,001
|
|
Accrued pension
|
6,369
|
|
|
9,537
|
|
Regulatory case expenses
|
26
|
|
|
108
|
|
Total other assets
|
13,770
|
|
|
16,518
|
|
Total regulatory assets
|
17,693
|
|
|
19,904
|
|
|
|
|
|
Regulatory liabilities
|
|
|
|
Long-term liabilities
|
|
|
|
Accrued cost of removal on long-lived assets
|
328
|
|
|
338
|
|
Regulatory liability for deferred income taxes
|
925
|
|
|
1,043
|
|
Total regulatory liabilities
|
1,253
|
|
|
1,381
|
|
All of our regulatory assets and liabilities have been approved for recovery by the Kentucky Public Service Commission and are currently being recovered or refunded through our regulated gas rates. In addition, the unrecovered balance of the loss on extinguishment of debt is included in rate base and, therefore, earns a return. The weighted average recovery period of regulatory assets not earning a return is
21 years
.
(l) Impairment of Long-Lived Assets
We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the assets, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value of the assets and recording a provision for an impairment loss if the carrying value is greater than the fair value. In the opinion of management, our long-lived assets are appropriately valued in the accompanying consolidated financial statements. There were no impairments of long-lived assets during
2013
,
2012
or
2011
.
(m) Derivatives
Certain of our natural gas purchase and sale contracts qualify as derivatives. All such contracts have been designated as normal purchases and sales and as such are accounted for under the accrual basis and are not recorded at fair value in the accompanying consolidated financial statements.
(n) Marketable Securities
We have a supplemental retirement benefit agreement with Glenn R. Jennings, our Chairman of the Board, President and Chief Executive Officer, that is a non-qualified deferred compensation plan. The agreement establishes an irrevocable rabbi trust, in which the assets of the trust are earmarked to pay benefits under the agreement. We have recognized a liability related to the obligation to pay these benefits to Mr. Jennings. We make discretionary contributions to the trust in order to fully fund the related deferred compensation liability.
The assets of the trust consist of exchange traded mutual funds and are classified as trading securities. The assets are recorded at fair value on the Consolidated Balance Sheets based on observable market prices from active markets. Net realized and unrealized gains and losses are included in earnings each period to effectively offset the corresponding earnings impact associated with the change in the fair value of the deferred compensation liability to which the assets relate.
(o) Fair Value
Fair value is defined as the exchange price in an orderly transaction between market participants to sell an asset or transfer a liability at the measurement date. Fair value focuses on an exit price, which is the price that would be received by us to sell an asset or paid to transfer a liability versus an entry price, which would be the price paid to acquire an asset or received to assume a liability.
We determine fair value based on the following fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels:
|
|
•
|
Level 1 - Observable inputs consisting of quoted prices in active markets for identical assets or liabilities;
|
|
|
•
|
Level 2 - Inputs, other than quoted prices in active markets, that are observable either directly or indirectly; and
|
|
|
•
|
Level 3 - Unobservable inputs which require the reporting entity to develop its own assumptions.
|
Although accounting standards permit entities to elect to measure many financial instruments and certain other items at fair value, we do not currently have any financial assets or financial liabilities for which this provision has been elected. However, in the future, we may elect to measure certain financial instruments at fair value in accordance with these standards.
(p) Gas In Storage
We operate a natural gas underground storage field that we utilize to inject and store natural gas during the non-heating season, and we then withdraw natural gas during the heating season to meet our customers' needs. The potential exists for differences between actual volumes stored versus our perpetual records primarily due to differences in measurement of injections and withdrawals or the risks of gas escaping from the field. We periodically analyze the volumes, pressure and other data relating to the storage field in order to substantiate the gas inventory carried in our perpetual inventory records. The periodic analysis of the storage field data utilizes trends in the underlying data and can require multiple periods of observation to determine if differences exist. The analysis can result in adjustments to our perpetual inventory records. The gas in storage inventory is recorded at average cost.
(2) New Accounting Pronouncements
In May, 2011, the Financial Accounting Standards Board issued guidance on fair value
measurement and disclosure. The guidance was issued as part of a joint effort between the Financial Accounting Standards Board and the International Accounting Standards Board to converge the two sets of standards into a single conceptual framework which would change how fair value measurement guidance is applied in future periods. The guidance, which was adopted as of March 31, 2012, did not have a material impact on our results of operations, financial position or cash flows.
In December, 2011, the Financial Accounting Standards Board issued guidance requiring additional disclosure of the effect or potential effect of rights of setoff associated with an entity's financial instruments and derivative instruments. The guidance will be effective for our quarter ending September 30, 2013 and is not expected to have a have a material impact on our results of operations, financial position or cash flows.
(3) Fair Value Measurements
Our financial assets and liabilities measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in other non-current assets on the Consolidated Balance Sheets. Contributions to the trust are presented in other investing activities on the Consolidated Statements of Cash Flows. The assets of the trust are recorded at fair value and consist of exchange traded mutual funds. The mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy. The fair value of the trust assets are as follows:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Trust assets
|
|
|
|
Money market
|
9
|
|
|
6
|
|
U.S. equity securities
|
486
|
|
|
364
|
|
U.S. fixed income securities
|
244
|
|
|
220
|
|
|
739
|
|
|
590
|
|
The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value. The fair value of the assets in our defined benefit retirement plan are disclosed in Note 6 of the Notes to Consolidated Financial Statements.
Our Series A Notes, presented as current portion of long-term debt and long-term debt on the Consolidated Balance Sheets, are stated at historical cost. Fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate. The credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date. The fair value of our long-term debt is categorized as Level 2 in the fair value hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
($000)
|
Amount
|
|
Value
|
|
Amount
|
|
Value
|
|
|
|
|
|
|
|
|
4.26% Series A Notes
|
56,500
|
|
|
55,150
|
|
|
58,000
|
|
|
59,027
|
|
(4) Asset Retirement Obligations
Legal obligations
As of June 30,
2013
and
2012
, we have accrued liabilities and related assets, net of accumulated depreciation, relative to the legal obligation to retire certain gas wells, storage tanks, mains and services. In 2012, our asset retirement obligations increased to reflect revisions to the estimated cost to retire certain mains and services. For asset retirement obligations related to regulated assets, accretion of the liability and depreciation of the asset retirement costs are recorded as regulatory assets, pursuant to regulatory accounting standards, as we recover the cost of removing our regulated assets through our depreciation rates.
The following is a summary of our asset retirement obligations as shown as asset retirement obligations on the accompanying Consolidated Balance Sheets:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Balance, beginning of year
|
3,824
|
|
|
2,561
|
|
Liabilities incurred
|
20
|
|
|
16
|
|
Liabilities settled
|
(616
|
)
|
|
(552
|
)
|
Accretion
|
267
|
|
|
207
|
|
Revisions in estimated cash flows
|
52
|
|
|
1,592
|
|
Balance, end of year
|
3,547
|
|
|
3,824
|
|
We have an additional asset retirement obligation related to the retirement of wells located at our underground natural gas storage facility. Since we expect to utilize the storage facility as long as we provide natural gas to our customers, we have determined the underlying asset has an indeterminate life. Therefore, we have not recorded a liability associated with the cost to retire the wells.
Non-legal obligations
In accordance with established regulatory practices, we accrue costs of removal on long-lived assets through depreciation expense to the extent recovery of such costs is granted by our regulator even though such costs do not represent legal obligations. In accordance with regulatory accounting standards, $
328,000
and $
338,000
of such accrued cost of removal was recorded as a regulatory liability on the accompanying Consolidated Balance Sheets as of June 30,
2013
and
2012
, respectively.
(5) Income Taxes
We provide for income taxes on temporary differences resulting from the use of alternative methods of income and expense recognition for financial and tax reporting purposes. The differences result primarily from the use of accelerated tax depreciation methods for certain properties versus the straight-line depreciation method for financial reporting purposes, differences in recognition of purchased gas costs and certain accruals which are not currently deductible for income tax purposes. Investment tax credits were deferred for certain periods prior to fiscal 1987 and are being amortized to income over the estimated useful lives of the applicable properties. We utilize the asset and liability method for accounting for income taxes, which requires that deferred income tax assets and liabilities be computed using tax rates that will be in effect when the book and tax temporary differences reverse. Changes in tax rates applied to accumulated deferred income taxes are not immediately recognized in operating results because of ratemaking treatment. A regulatory liability has been established to recognize the regulatory obligation to refund these excess deferred taxes through customer rates. The current portion of the net accumulated deferred income tax liability is shown as current liabilities and the long-term portion is included in long-term liabilities on the accompanying Consolidated Balance Sheets. The temporary differences which gave rise to the net accumulated deferred income tax liability for the periods are as follows:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Deferred Tax Liabilities
|
|
|
|
Current
|
|
|
|
Deferred gas cost
|
(1,459
|
)
|
|
(1,170
|
)
|
Prepaid expenses
|
(304
|
)
|
|
(319
|
)
|
|
(1,763
|
)
|
|
(1,489
|
)
|
|
|
|
|
Non-Current
|
|
|
|
Accelerated depreciation
|
(36,004
|
)
|
|
(34,955
|
)
|
Other
|
(1,040
|
)
|
|
(1,077
|
)
|
Pension
|
(908
|
)
|
|
—
|
|
Regulatory assets - asset retirement obligations
|
(736
|
)
|
|
(640
|
)
|
Regulatory assets - loss on extinguishment of debt
|
(1,287
|
)
|
|
(1,380
|
)
|
Regulatory assets - unrecognized accrued pension
|
(2,418
|
)
|
|
(3,620
|
)
|
Regulatory liabilities
|
(1,268
|
)
|
|
(1,268
|
)
|
|
(43,661
|
)
|
|
(42,940
|
)
|
Total deferred tax liabilities
|
(45,424
|
)
|
|
(44,429
|
)
|
|
|
|
|
Deferred Tax Assets
|
|
|
|
Current
|
|
|
|
Accrued employee benefits
|
313
|
|
|
238
|
|
Bad debt reserve
|
58
|
|
|
57
|
|
Other
|
53
|
|
|
63
|
|
|
424
|
|
|
358
|
|
|
|
|
|
Non-Current
|
|
|
|
Accrued employee benefits
|
855
|
|
|
653
|
|
Asset retirement obligations
|
1,284
|
|
|
1,389
|
|
Investment tax credits
|
25
|
|
|
38
|
|
Other
|
81
|
|
|
505
|
|
Pension
|
—
|
|
|
886
|
|
Regulatory liabilities
|
1,610
|
|
|
1,650
|
|
Section 263 (a) capitalized costs
|
182
|
|
|
87
|
|
|
4,037
|
|
|
5,208
|
|
|
|
|
|
Total deferred tax assets
|
4,461
|
|
|
5,566
|
|
Net accumulated deferred income tax liability
|
(40,963
|
)
|
|
(38,863
|
)
|
The components of the income tax provision are comprised of the following for the years ended June 30:
|
|
|
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
Federal
|
1,940
|
|
|
525
|
|
|
956
|
|
State
|
390
|
|
|
220
|
|
|
276
|
|
Total
|
2,330
|
|
|
745
|
|
|
1,232
|
|
Deferred
|
1,939
|
|
|
2,513
|
|
|
2,528
|
|
Income tax expense
|
4,269
|
|
|
3,258
|
|
|
3,760
|
|
Reconciliation of the statutory federal income tax rate to the effective income tax rate is shown in the table below:
|
|
|
|
|
|
|
|
|
|
(%)
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
Statutory federal income tax rate
|
34.0
|
|
|
34.0
|
|
|
34.0
|
|
State income taxes, net of federal benefit
|
4.0
|
|
|
4.0
|
|
|
4.0
|
|
Amortization of investment tax credits
|
(0.2
|
)
|
|
(0.3
|
)
|
|
(0.3
|
)
|
Other differences, net
|
(0.6
|
)
|
|
(1.7
|
)
|
|
(0.6
|
)
|
Effective income tax rate
|
37.2
|
|
|
36.0
|
|
|
37.1
|
|
We recognize the income tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The liability for unrecognized tax benefits expected to be recognized within the next twelve months has partially offset our prepaid income taxes and been presented in prepayments on the Consolidated Balance Sheets. The liability for unrecognized tax benefits not expected to be recognized within the next twelve months has been presented in other long-term liabilities on the Consolidated Balance Sheets. Interest and penalties on tax uncertainties are classified in income tax expense in the Consolidated Statements of Income.
The amount of unrecognized tax benefits, net of tax, which, if recognized, would impact the effective tax rate was
$31,000
and
$38,000
as of
June 30, 2013
and
2012
, respectively. As of
June 30, 2013
, we have accrued interest of $
9,000
on unrecognized tax positions. We recognized interest income of
$1,000
on unrecognized tax positions in the
2013
Consolidated Statements of Income. We accrued
$3,000
of interest in the
2012
Consolidated Statements of Income.
The following is a tabular reconciliation of our unrecognized tax benefits:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Balance, beginning of year
|
200
|
|
|
266
|
|
Gross increases - tax positions in prior period
|
—
|
|
|
131
|
|
Gross decreases - tax positions in prior period
|
(99
|
)
|
|
(197
|
)
|
Balance, end of year
|
101
|
|
|
200
|
|
We file income tax returns in the federal and Kentucky jurisdictions. Tax years previous to
June 30, 2011
and
June 30, 2010
are no longer subject to examination for federal and Kentucky income taxes, respectively.
(6) Employee Benefit Plans
(a) Defined Benefit Retirement Plan
We have a trusteed, noncontributory, defined benefit retirement plan covering all eligible employees hired prior to May 9, 2008. Retirement income is based on the number of years of service and annual rates of compensation. The Company has historically made annual contributions equal to the amounts necessary to fund the plan adequately.
Generally accepted accounting principles (“GAAP”) require employers who sponsor defined benefit plans to recognize the funded status of a defined benefit pension plan on the balance sheet and to recognize through comprehensive income the changes in the funded status in the year in which the changes occur. However, regulatory accounting standards provide that regulated entities can defer recoverable costs that would otherwise be charged to expense or equity by non-regulated entities. Current cost-of-service ratemaking in Kentucky allows recovery of net periodic benefit cost as determined under GAAP. The Kentucky Public Service Commission has been clear and consistent with its historical treatment of such rate recovery; therefore, we have recorded a regulatory asset representing the probable recovery of the portion of the change in funded status of the defined benefit plan that is expected to be recognized in future net periodic benefit cost. The regulatory asset is adjusted annually as prior service cost and actuarial losses are recognized in net periodic benefit cost.
Our obligations and the funded status of our plan, measured at
June 30, 2013
and
June 30, 2012
, respectively, are as follows:
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
|
|
|
Change in Benefit Obligation
|
|
|
|
Benefit obligation at beginning of year
|
23,278
|
|
|
17,915
|
|
Service cost
|
1,116
|
|
|
921
|
|
Interest cost
|
913
|
|
|
921
|
|
Actuarial (gain)/loss
|
(1,271
|
)
|
|
3,994
|
|
Benefits paid
|
(515
|
)
|
|
(473
|
)
|
Benefit obligation at end of year
|
23,521
|
|
|
23,278
|
|
|
|
|
|
Change in Plan Assets
|
|
|
|
Fair value of plan assets at beginning of year
|
20,971
|
|
|
21,056
|
|
Actual return on plan assets
|
2,945
|
|
|
(112
|
)
|
Employer contributions
|
2,800
|
|
|
500
|
|
Benefits paid
|
(515
|
)
|
|
(473
|
)
|
Fair value of plan assets at end of year
|
26,201
|
|
|
20,971
|
|
|
|
|
|
|
|
Recognized Amounts
|
|
|
|
Projected benefit obligation
|
(23,521
|
)
|
|
(23,278
|
)
|
Plan assets at fair value
|
26,201
|
|
|
20,971
|
|
Funded status
|
2,680
|
|
|
(2,307
|
)
|
|
|
|
|
|
|
Net amount recognized as prepaid (accrued) benefit costs on the Consolidated Balance Sheets
|
2,680
|
|
|
(2,307
|
)
|
|
|
|
|
|
|
|
Items Not Yet Recognized as a Component of Net Periodic Benefit Costs
|
|
|
|
Prior service cost
|
(403
|
)
|
|
(489
|
)
|
Net loss
|
6,772
|
|
|
10,026
|
|
Amounts recognized as regulatory assets
|
6,369
|
|
|
9,537
|
|
The accumulated benefit obligation was
$20,508,000
and
$20,125,000
for
2013
and
2012
, respectively.
|
|
|
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
Service cost
|
1,116
|
|
|
921
|
|
|
939
|
|
Interest cost
|
913
|
|
|
921
|
|
|
854
|
|
Expected return on plan assets
|
(1,578
|
)
|
|
(1,474
|
)
|
|
(1,079
|
)
|
Amortization of unrecognized net loss
|
615
|
|
|
200
|
|
|
501
|
|
Amortization of prior service cost
|
(86
|
)
|
|
(87
|
)
|
|
(86
|
)
|
Net periodic benefit cost
|
980
|
|
|
481
|
|
|
1,129
|
|
|
|
|
|
|
|
Weighted-Average % Assumptions Used to
Determine Benefit Obligations
|
|
|
|
|
|
Discount rate
|
4.5
|
|
|
4.0
|
|
|
5.25
|
|
Rate of compensation increase
|
4.0
|
|
|
4.0
|
|
|
4.0
|
|
|
|
|
|
|
|
Weighted-Average % Assumptions Used to
Determine Net Periodic Benefit Cost
|
|
|
|
|
|
Discount rate
|
4.0
|
|
|
5.25
|
|
|
5.25
|
|
Expected long-term return on plan assets
|
7.0
|
|
|
7.0
|
|
|
7.0
|
|
Rate of compensation increase
|
4.0
|
|
|
4.0
|
|
|
4.0
|
|
Plan Assets
Our target investment allocations have been developed using an asset allocation model which weighs risk versus return of various investment indices to create a target asset allocation to maximize return subject to a moderate amount of portfolio risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolios contain a diversified blend of equity and fixed income investments. Our target investment allocations are approximately
70%
equity investments and
30%
fixed income investments. Our equity investment target allocations are heavily weighted toward domestic equity securities, with allocations to domestic real estate securities, inflation indexed securities and foreign equity securities for the purposes of diversification. Fixed income securities primarily include U.S. government obligations and corporate debt securities. We regularly review our asset allocation and periodically rebalance our investments to our targeted allocation as appropriate.
The assets of the plan are comprised of investments in mutual funds. In June, 2013, upon changing investment advisors for our defined benefit plan, we adopted a new asset allocation model which resulted in changes to our target allocation for plan assets and the reallocation of our investment in the common collective trusts to exchange traded mutual funds. Each individual mutual fund or common collective trust has been selected based on its investment strategy, which approximates a specific asset class within our target allocation.
|
|
|
|
|
|
|
|
Target
|
|
Actual Allocation
|
(%)
|
Allocation
|
|
2013
|
|
2012
|
Asset Class (a)
|
|
|
|
|
|
Cash
|
—
|
|
3
|
|
—
|
|
|
|
|
|
|
Equity Securities
|
|
|
|
|
|
U.S. Equity Securities
|
32
|
|
53
|
|
48
|
Foreign Equity Securities
|
19
|
|
11
|
|
13
|
Domestic Real Estate
|
7
|
|
6
|
|
13
|
Inflation Indexed Securities
|
13
|
|
—
|
|
—
|
|
71
|
|
70
|
|
74
|
|
|
|
|
|
|
Fixed Income Securities
|
29
|
|
27
|
|
26
|
|
100
|
|
100
|
|
100
|
(a)
Each mutual fund and common collective trust has been categorized based on its primary investment strategy.
The mutual funds are categorized as Level 1 in the fair value hierarchy as the fair value of the mutual funds is determined based on the quoted market price of each fund. The common/collective trusts are categorized as Level 2 in the fair value hierarchy. The fair value of the common/collective trusts were determined based on the net asset value as published by the respective fund manager multiplied by the number of units held in the trust. For our investments in the common/collective trusts, there were no restrictions on our ability to sell these investments. The respective level within the fair value hierarchy is determined as described in Note 1 of the Notes to Consolidated Financial Statements. The following represents the fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
($000)
|
2013
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
Asset Class (a)
|
|
|
|
|
|
|
|
Cash
|
778
|
|
|
778
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Exchange Traded Mutual Funds
|
|
|
|
|
|
|
|
|
U.S. Equity Securities
|
14,191
|
|
|
14,191
|
|
|
—
|
|
|
—
|
|
Fixed Income Securities
|
6,969
|
|
|
6,969
|
|
|
—
|
|
|
—
|
|
Foreign Equity Securities
|
2,756
|
|
|
2,756
|
|
|
—
|
|
|
—
|
|
Domestic Real Estate Securities
|
1,507
|
|
|
1,507
|
|
|
—
|
|
|
—
|
|
|
25,423
|
|
|
25,423
|
|
|
—
|
|
|
—
|
|
Total
|
26,201
|
|
|
26,201
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($000)
|
2012
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
Asset Class (a)
|
|
|
|
|
|
|
|
Cash
|
31
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Exchange Traded Mutual Funds
|
|
|
|
|
|
|
|
U.S. Equity Securities
|
696
|
|
|
696
|
|
|
—
|
|
|
—
|
|
Fixed Income Securities
|
1,115
|
|
|
1,115
|
|
|
—
|
|
|
—
|
|
Foreign Equity Securities
|
1,062
|
|
|
1,062
|
|
|
—
|
|
|
—
|
|
Domestic Real Estate Securities
|
2,737
|
|
|
2,737
|
|
|
—
|
|
|
—
|
|
|
5,610
|
|
|
5,610
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Common Collective Trusts
|
|
|
|
|
|
|
|
Short-Term Income Fund
|
148
|
|
|
—
|
|
|
148
|
|
|
—
|
|
U.S. Fixed Income Fund
|
2,202
|
|
|
—
|
|
|
2,202
|
|
|
—
|
|
Global Equity Growth Fund
|
2,472
|
|
|
—
|
|
|
2,472
|
|
|
—
|
|
Global Equity Value Fund
|
1,136
|
|
|
—
|
|
|
1,136
|
|
|
—
|
|
U.S. Equity Index Fund
|
2,098
|
|
|
—
|
|
|
2,098
|
|
|
—
|
|
Foreign Equity Index Fund
|
1,694
|
|
|
—
|
|
|
1,694
|
|
|
—
|
|
Blended Fund (b)
|
5,580
|
|
|
—
|
|
|
5,580
|
|
|
—
|
|
|
15,330
|
|
|
—
|
|
|
15,330
|
|
|
—
|
|
Total
|
20,971
|
|
|
5,641
|
|
|
15,330
|
|
|
—
|
|
(a) Each mutual fund and common collective trust has been categorized based on its primary investment
strategy.
(b) The blended fund is a combination of the U.S. equity securities (
65%
) and U.S. fixed income securities (
35%
).
We determined the expected long-term rate of return for plan assets with input from plan actuaries and investment consultants based upon many factors including asset allocations, historical asset returns and expected future market conditions. The discount rates used by the Company for valuing pension liabilities are based on a review of high quality corporate bond yields with maturities approximating the remaining life of the projected benefit obligations.
We made
$2,800,000
of discretionary contributions to the defined benefit plan in fiscal
2013
. We expect to contribute
$500,000
to the defined benefit plan in fiscal
2014
.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
|
|
|
|
|
($000)
|
|
|
|
|
|
2014
|
931
|
|
|
2015
|
2,599
|
|
|
2016
|
898
|
|
|
2017
|
1,029
|
|
|
2018
|
1,551
|
|
|
2019 - 2023
|
7,051
|
|
|
Effective May 9, 2008, any employees hired on and after that date were not eligible to participate in our defined benefit plan. Freezing the defined benefit plan for new entrants did not impact the level of benefits for existing participants.
We do not provide postretirement or postemployment benefits other than the pension plan for retired employees.
(b) Employee Savings Plan
We have an Employee Savings Plan (“Savings Plan”) under which eligible employees may elect to contribute a portion of their annual compensation up to the maximum amount permitted by law. The Company matches 100% of the employee's contribution up to a maximum company contribution of 4% of the employee's annual compensation. Employees hired after May 9, 2008, who are not eligible to participate in the defined benefit retirement plan, annually receive an additional 4% non-elective contribution into their Savings Plan account. Company contributions are discretionary and subject to change with approval from our Board of Directors. For
2013
,
2012
and
2011
, Delta's Savings Plan expense was
$313,000
,
$325,000
and
$301,000
, respectively.
(c) Supplemental Retirement Agreement
We sponsor a nonqualified defined contribution supplemental retirement agreement for Glenn R. Jennings, Delta's Chairman of the Board, President and Chief Executive Officer. Delta contributes
$60,000
annually into an irrevocable trust until Mr. Jennings' retirement. At retirement, the trustee will make annual payments of
$100,000
to Mr. Jennings until the trust is depleted. As of June 30,
2013
and
2012
, the irrevocable trust assets are
$739,000
and
$590,000
, respectively. These amounts are included in other non-current assets on the accompanying Consolidated Balance Sheets. Liabilities, in corresponding amounts, are included in other long-term liabilities on the accompanying Consolidated Balance Sheets.
(7) Dividend Reinvestment and Stock Purchase Plan
Our Dividend Reinvestment and Stock Purchase Plan (“Reinvestment Plan”) provides that shareholders of record can reinvest dividends and also make limited additional investments of up to
$50,000
per year in shares of common stock of the Company. Under the Reinvestment Plan we issued
28,436
,
38,929
and
44,632
shares in
2013
,
2012
and
2011
, respectively. We registered
400,000
shares for issuance under the Reinvestment Plan in
2006
, and as of
June 30, 2013
there were
122,000
shares available for issuance.
(8) Risk Management and Derivative Instruments
To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk. We purchase our gas supply through a combination of spot market natural gas purchases and forward natural gas purchases. We mitigate price risk by efforts to balance supply and demand. None of our natural gas contracts are accounted for using the fair value method of accounting. While some of our natural gas purchase contracts and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.
(9) Notes Payable
The current bank line of credit with Branch Banking and Trust Company permits borrowings up to
$40,000,000
, all of which was available as of
June 30, 2013
and
June 30, 2012
. We did not borrow from the bank line of credit during 2013. The maximum amount borrowed during 2012 was
$6,491,000
. The bank line of credit extends through
June 30, 2015
. The interest rate on the used line of credit is the London Interbank Offered Rate plus
1.15%
. The annual cost of the unused bank line of credit is
.125%
. We were in compliance with the covenants of our bank line of credit (as further discussed in Note 10 of the Notes to Consolidated Financial Statements) during all periods presented in the Consolidated Financial Statements.
(10) Long-Term Debt
In December, 2011, we refinanced and redeemed our 5.75% Insured Quarterly Notes (
$38,450,000
) and 7% Debentures (
$19,410,000
) from the proceeds of a private debt financing. Under the Note Purchase and Private Shelf Agreement we issued
$58,000,000
of Series A Notes, for which the purchasers paid 100% of the face principal amount. Unamortized debt expense of
$1,896,000
related to the 5.75% Insured Quarterly Notes and 7% Debentures was reclassified from unamortized debt expense to regulatory assets on the accompanying Consolidated Balance Sheet. The
$1,896,000
regulatory asset representing the loss on extinguishment of the 5.75% Insured Quarterly Notes and 7% Debentures, combined with
$1,872,000
of unamortized loss on extinguishment of debt recognized from prior refinancings, will be amortized over the life of the 4.26% Series A Notes consistent with treatment approved by the Kentucky Public Service Commission.
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. The following table summarizes the contractual maturities of our Series A Notes by fiscal year:
|
|
|
|
($000)
|
|
2014
|
1,500
|
|
2015
|
1,500
|
|
2016
|
1,500
|
|
2017
|
1,500
|
|
Thereafter
|
50,500
|
|
Total long-term debt
|
56,500
|
|
|
|
Any additional prepayment of principal by the Company may be subject to a prepayment premium which varies depending on the yields of United States Treasury securities with a maturity equal to the remaining average life of the Series A Notes.
We amortize debt issuance expenses over the life of the related debt using the effective interest method. At
June 30, 2013
and
2012
, the unamortized balance was
$3,486,000
and
$3,740,000
, respectively. Loss on extinguishment of debt of
$3,389,000
and
$3,636,000
included in the above has been deferred as a regulatory asset and is being amortized over the term of the related debt consistent with regulatory accounting as further discussed in Note 1 of the Notes to Consolidated Financial Statements.
With our bank line of credit and Series A Notes, we have agreed to certain financial covenants. Noncompliance with these covenants can make the obligation immediately due and payable. We have agreed to the following financial covenants:
|
|
•
|
The Company must at all times maintain a tangible net worth of at least
$25,800,000
.
|
|
|
•
|
The Company must at the end of each fiscal quarter maintain a total debt to capitalization ratio of no more than
70%
. The total debt to capitalization ratio is calculated as the ratio of (i) the Company's total debt to (ii) the sum of the Company's shareholders' equity plus total debt.
|
|
|
•
|
The Company must maintain a fixed charge coverage ratio for the twelve months ending each quarter of not less than
1.20
x. 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.
|
As of
June 30, 2013
, we were in compliance with all financial covenants.
The following table shows the required and actual financial covenants under our Series A Notes as of
June 30, 2013
:
|
|
|
|
|
|
|
|
|
Requirement
|
|
Actual
|
|
|
|
|
|
|
Tangible net worth
|
no less than $25,800,000
|
|
$
|
68,674,245
|
|
|
Debt to capitalization ratio
|
no more than 70%
|
|
45
|
%
|
|
Fixed charge coverage ratio
|
no less than 1.20x
|
|
7.75
|
|
x
|
Dividends paid
|
no more than $28,318,000
|
|
$
|
8,526,000
|
|
|
Our 4.26% Series A Notes restrict us from:
|
|
•
|
with limited exceptions, granting or permitting liens on or security interests in our properties,
|
|
|
•
|
selling a subsidiary, except in limited circumstances,
|
|
|
•
|
incurring secured debt, or permitting a subsidiary to incur debt or issue preferred stock to any third party, in an aggregate amount that exceeds 10% of our tangible net worth,
|
|
|
•
|
changing the general nature of our business,
|
|
|
•
|
merging with another company, unless (i) we are the survivor of the merger or the survivor of the merger is another domestic company that assumes the 4.26% Series A Notes, (ii) there is no event of default under the 4.26% Series A Notes and (iii) the continuing company has a tangible net worth at least as high as our tangible net worth immediately prior to such merger, or
|
|
|
•
|
selling or transferring assets, other than (i) the sale of inventory in the ordinary course of business, (ii) the transfer of obsolete equipment and (iii) the transfer of other assets in any 12 month period where such assets constitute no more than 5% of the value of our tangible assets and, over any period of time, the cumulative value of all assets transferred may not exceed 15% of our tangible assets.
|
Without the consent of the bank that has extended to us our bank line of credit or terminating our bank line of credit, we may not:.
|
|
•
|
merge with another entity,
|
|
|
•
|
sell a material portion of our assets other than in the ordinary course of business,
|
|
|
•
|
issue stock which in the aggregate exceeds thirty-five percent (35%) of our outstanding shares of common stock, or
|
|
|
•
|
permit any person or group of related persons to hold more than twenty percent (20%) of the Company's outstanding shares of stock.
|
Furthermore, the agreement governing our 4.26% Series A Notes contains a cross-default provision which provides that we will be in default under the 4.26% Series A Notes if we are in default on any other outstanding indebtedness that exceeds $2,500,000. Similarly, the loan agreement governing the bank line of credit contains a cross-default provision which provides that we will be in default under the bank line of credit if we are in default under our 4.26% Series A Notes and fail to cure the default within ten days of notice from the bank. We were in compliance with the covenants under our bank line of credit and 4.26% Series A Notes for all periods presented in the Consolidated Financial Statements.
(11) Earnings per Share
The following table sets forth the computation of basic and diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
2011
|
Numerator - Basic and Diluted
|
|
|
|
|
|
Net income ($000)
|
7,201
|
|
|
5,784
|
|
|
6,365
|
|
Dividends paid ($000)
|
(4,951
|
)
|
|
(4,762
|
)
|
|
(4,562
|
)
|
|
|
|
|
|
|
Undistributed earnings ($000)
|
2,250
|
|
|
1,022
|
|
|
1,803
|
|
Percentage allocated to common shares (a)
|
99.4
|
%
|
|
99.6
|
%
|
|
99.9
|
%
|
|
|
|
|
|
|
Undistributed earnings allocated to common shares ($000)
|
2,238
|
|
|
1,018
|
|
|
1,801
|
|
Dividends paid on common shares outstanding ($000)
|
4,930
|
|
|
4,747
|
|
|
4,557
|
|
|
|
|
|
|
|
Net income available to common shares ($000)
|
7,168
|
|
|
5,765
|
|
|
6,358
|
|
|
|
|
|
|
|
Denominator
|
Basic - weighted average common shares
|
6,843,455
|
|
|
6,777,186
|
|
|
6,707,224
|
|
|
|
|
|
|
|
|
|
|
Incremental unvested non-participating shares (b)
|
—
|
|
|
—
|
|
|
5,580
|
|
|
|
|
|
|
|
Diluted - weighted-average common shares
|
6,843,455
|
|
|
6,777,186
|
|
|
6,712,804
|
|
|
|
|
|
|
|
Per common share net income ($)
|
|
|
|
|
|
Basic
|
1.05
|
|
|
0.85
|
|
|
0.95
|
|
Diluted
|
1.05
|
|
|
0.85
|
|
|
0.95
|
|
|
|
|
|
|
|
|
|
|
|
(a) Percentage allocated to common shares - weighted average
|
|
|
|
|
|
Common shares outstanding
|
6,843,455
|
|
|
6,777,186
|
|
|
6,707,224
|
|
Unvested participating shares (c)
|
38,417
|
|
|
28,082
|
|
|
8,000
|
|
Total
|
6,881,872
|
|
|
6,805,268
|
|
|
6,715,224
|
|
Percentage allocated to common shares
|
99.4
|
%
|
|
99.6
|
%
|
|
99.9
|
%
|
(b) Under our Incentive Compensation Plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 17 of the Notes to Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end, as further discussed in (c). The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. There were no antidilutive shares in 2013, 2012 and 2011.
(c) Certain awards under our shareholder approved incentive compensation plan, as further discussed in Note 17 of the Notes to Consolidated Financial Statements, provide the recipients of the awards all the rights of a shareholder of Delta including a right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. There were no antidilutive shares in 2013, 2012 and 2011. There were
68,000
and
48,000
unvested participating shares outstanding as of June 30, 2013 and 2012, respectively.
(12) Operating Leases
We have no non-cancellable operating leases. Our operating leases relate primarily to well and compressor station site leases and are cancellable at our option. Rental expense under operating leases was
$71,000
,
$70,000
and
$72,000
for the years ended June 30,
2013
,
2012
and
2011
, respectively.
(13) Commitments and Contingencies
We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in control agreements with our other four officers. The agreements expire or may be terminated at various times. The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company. In the event all of these agreements were exercised in the form of lump sum payments, approximately
$4.2 million
would be paid in addition to continuation of specified benefits for up to five years. Additionally, upon a change in control, all unvested shares awarded under our Incentive Compensation Plan, as further discussed in Note 17 of the Notes to Consolidated Financial Statements, would immediately vest.
Our June 30, 2012 Consolidated Balance Sheet includes
$3,055,000
of accrued taxes and
$877,000
of interest related to an assessment of a license tax levied on the gross receipts of Delta Resources' customers over the period of July, 2005 through September, 2011. The assessment was resolved in February, 2013 and the previously accrued interest was reversed. Delta Resources billed its customers
$2,546,000
which represents their proportionate share of the assessment, as Delta Resources has a contractual right to seek reimbursement from its customers. As of June 30,
2013
, the net receivable from Delta Resources' customers was
$1,016,000
. We will continue to pursue collection of the taxes from these customers and to monitor the amount of the receivable to be realized.
On the Consolidated Balance Sheets, the receivable from Delta Resources' customers is included in accounts receivable. On the June 30, 2012 Consolidated Balance Sheet, the liability for taxes was included in accrued taxes, and the liability for interest was included in accrued interest on debt. In the Consolidated Statements of Income, the change in the interest accrued is included in other interest (income) expense.
We are not a party to any material pending legal proceedings.
We have entered into forward purchase agreements beginning in
July, 2013
and expiring at various dates through
December, 2013
. These agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements. These agreements are established in the normal course of business to ensure adequate gas supply to meet our customers' gas requirements. These agreements have aggregate remaining minimum purchase obligations of
$328,000
for our fiscal year ending June 30,
2014
.
(14) Regulatory Matters
The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services. Their regulation of our business includes setting the rates we are permitted to charge our regulated customers. We monitor our need to file requests with them for a general rate increase for our natural gas and transportation services. They have historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of gas costs, and a reasonable rate of return. Our regulated rates were most recently adjusted in our
2010
rate case and became effective in
October, 2010
. In this case, the Kentucky Public Service Commission approved increased base rates to provide an additional
$3,513,000
in annual revenues based upon a
10.4%
allowed return on common equity and a
$1,770,000
increase in annual depreciation expense. A majority of the increase was allocated to our fixed monthly customer charge as opposed to the volumetric rate, and therefore the increase in revenues is less dependent on customer usage and occurs more evenly throughout the year. We do not have any matters before the Kentucky Public Service Commission that would have a material impact on our results of operations, financial position or cash flows.
We have a pipe replacement program which allows us to adjust rates annually to earn a return on capital expenditures incurred subsequent to our last rate case which are associated with the replacement of pipe and related facilities. The pipe replacement program is designed to additionally recover the costs associated with the mandatory retirement or relocation of facilities.
The Kentucky Public Service Commission allows us a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs and any bad debt expense related to gas cost. Although we are not required to file a general rate case to adjust rates pursuant to the gas cost recovery clause, we are required to make quarterly filings with the Kentucky Public Service Commission. Under and over-recovered gas costs are collected or refunded through adjustments to customer bills beginning three months after the end of the quarter in which the actual gas costs were incurred.
Additionally, we have a weather normalization provision in our tariffs, approved by the Kentucky Public Service Commission, which allows us to adjust our rates to residential and small non-residential customers to reflect variations from thirty year average weather for our December through April billing cycles. These adjustments to customer bills are made on a real time basis such that there is no lag in collecting from or refunding to customers the related dollar amounts.
The Kentucky Public Service Commission allows us a conservation and efficiency program for our residential customers. The program provides for us to perform energy audits, promote conservation awareness and provide rebates on the purchase of certain high-efficiency appliances. The program helps to align our interests with our residential customer's interests by reimbursing us for the margins on lost sales due to the program and providing incentives for us to promote customer conservation. Our rates are adjusted annually to recover the costs incurred under these programs, the reimbursement of margins on lost sales and the incentives provided to us.
In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on such franchise. We hold franchises in
five
of the cities we serve, and we continue to operate under the conditions of expired franchises in
four
other cities we serve. In the other cities and areas we serve, the areas served do not have governmental organizations authorized to grant franchises or the city governments do not require a franchise. We attempt to acquire or reacquire franchises whenever feasible. Without a franchise, a city could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city. To date, the absence of a franchise has not adversely affected our operations.
(15) Segment Information
Our Company has two reportable segments: (i) a regulated natural gas distribution and transmission segment and (ii) a non-regulated segment that participates in related ventures, consisting of natural gas marketing, natural gas production and sales of natural gas liquids. Virtually all of the revenues recorded under both segments come from the sale or transportation of natural gas, or related sales of natural gas liquids. The regulated segment serves residential, commercial and industrial customers in the single geographic area of central and southeastern Kentucky. Price risk for the regulated segment is mitigated through our gas cost recovery clause, approved quarterly by the Kentucky Public Service Commission. Price risk for the non-regulated segment is mitigated by efforts to balance supply and demand. However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict our demand. In addition, we are exposed to price risk resulting from changes in the market price of natural gas, natural gas liquids and uncommitted natural gas inventory of our non-regulated companies.
In our non-regulated segment, two customers each provided more than 5% of our operating revenues. Our largest customer provided approximately
$17,866,000
,
$12,450,000
and
$11,461,000
of non-regulated revenues during
2013
,
2012
and
2011
, respectively. Our second largest customer provided approximately
$5,390,000
,
$6,815,000
and
$8,067,000
of non-regulated revenues during
2013
,
2012
and
2011
, respectively. There is no assurance that revenues from these customers will continue at these levels.
In
2013
, we purchased approximately
98%
of our natural gas from Atmos Energy Marketing, M & B Gas Services and Midwest Energy Services. In 2012 and 2011, we purchased approximately
99%
of our natural gas from Atmos Energy Marketing and M & B Gas Services.
The reportable segments follow the accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements. Intersegment revenues and expenses represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates. Operating expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown in the following table:
|
|
|
|
|
|
|
|
|
|
($000)
|
2013
|
|
2012
|
|
2011
|
Operating Revenues
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
External customers
|
46,427
|
|
|
42,655
|
|
|
48,697
|
|
Intersegment
|
4,145
|
|
|
3,704
|
|
|
3,777
|
|
Total regulated
|
50,572
|
|
|
46,359
|
|
|
52,474
|
|
Non-regulated
|
|
|
|
|
|
External customers
|
34,238
|
|
|
31,423
|
|
|
34,343
|
|
Eliminations for intersegment
|
(4,145
|
)
|
|
(3,704
|
)
|
|
(3,777
|
)
|
Total operating revenues
|
80,665
|
|
|
74,078
|
|
|
83,040
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
Regulated
|
|
|
|
|
|
Purchased gas
|
17,825
|
|
|
15,703
|
|
|
21,078
|
|
Depreciation and amortization
|
6,023
|
|
|
5,871
|
|
|
5,037
|
|
Other
|
14,701
|
|
|
13,909
|
|
|
14,318
|
|
Total regulated
|
38,549
|
|
|
35,483
|
|
|
40,433
|
|
Non-regulated
|
|
|
|
|
|
Purchased gas
|
26,011
|
|
|
23,380
|
|
|
26,762
|
|
Depreciation and amortization
|
70
|
|
|
53
|
|
|
120
|
|
Other
|
6,990
|
|
|
5,601
|
|
|
5,440
|
|
Total non-regulated
|
33,071
|
|
|
29,034
|
|
|
32,322
|
|
Eliminations for intersegment
|
(4,145
|
)
|
|
(3,704
|
)
|
|
(3,777
|
)
|
Total operating expenses
|
67,476
|
|
|
60,813
|
|
|
68,978
|
|
|
|
|
|
|
|
Other Income and Deductions, Net
|
|
|
|
|
|
Regulated
|
151
|
|
|
77
|
|
|
153
|
|
Non-regulated
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
Total other income and deductions
|
151
|
|
|
75
|
|
|
152
|
|
|
|
|
|
|
|
Interest Charges
|
|
|
|
|
|
Regulated
|
2,688
|
|
|
3,366
|
|
|
4,029
|
|
Non-regulated
|
(818
|
)
|
|
932
|
|
|
60
|
|
Total interest charges
|
1,870
|
|
|
4,298
|
|
|
4,089
|
|
|
|
|
|
|
|
Income Tax Expense
|
|
|
|
|
|
Regulated
|
3,676
|
|
|
2,772
|
|
|
3,012
|
|
Non-regulated
|
593
|
|
|
486
|
|
|
748
|
|
Total income tax expense
|
4,269
|
|
|
3,258
|
|
|
3,760
|
|
|
|
|
|
|
|
Net Income
|
|
|
|
|
|
Regulated
|
5,970
|
|
|
4,990
|
|
|
5,153
|
|
Non-regulated
|
1,231
|
|
|
794
|
|
|
1,212
|
|
Total net income
|
7,201
|
|
|
5,784
|
|
|
6,365
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
Regulated
|
177,662
|
|
|
174,454
|
|
|
168,997
|
|
Non-regulated
|
6,268
|
|
|
8,441
|
|
|
5,899
|
|
Total assets
|
183,930
|
|
|
182,895
|
|
|
174,896
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
|
|
|
|
Regulated
|
6,983
|
|
|
7,163
|
|
|
8,120
|
|
Non-regulated
|
196
|
|
|
174
|
|
|
3
|
|
Total capital expenditures
|
7,179
|
|
|
7,337
|
|
|
8,123
|
|
(16) Insurance Proceeds
In September, 2011, we received
$300,000
of insurance proceeds relating to a gas inventory adjustment recorded in fiscal 2009 for the Company's underground storage field. These proceeds are included in operation and maintenance in the 2012 Consolidated Statement of Income.
(17) Share-Based Compensation
We have a shareholder approved incentive compensation plan (the “Plan”) that provides for compensation payable in shares of our common stock. The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining our employees, officers and outside directors who shall be eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan.
The number of shares of our common stock which may be issued pursuant to the Plan may not exceed in the aggregate
1,000,000
shares. As of
June 30, 2013
,
850,000
shares of common stock were available for issuance under the Plan. Shares of common stock may be issued from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market.
Compensation expense for share-based compensation is recorded in the non-regulated segment and included in operation and maintenance expense in the Consolidated Statements of Income based on the fair value of the awards at the grant date and is amortized over the requisite service period. Fair value is the closing price of our common shares at the grant date. The grant date is the date at which our commitment to issue the share-based awards arises, which is generally when the award is approved and the terms of the awards are communicated to the employee or director. We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met. Our share-based compensation expense was
$922,000
,
$712,000
and
$527,000
for
2013
,
2012
and
2011
, respectively.
Tax benefits of
$26,000
and
$22,000
were recognized as a premium on common shares on our
2013
and
2012
Consolidated Balance Sheets, respectively, which decreased our taxes payable as the deduction for income tax purposes exceeds the compensation expense recognized for share-based compensation. The excess tax benefits can be utilized to offset tax deficiencies related to share-based compensation in subsequent periods.
Stock Awards
In
2013
and
2012
, common stock was awarded to virtually all Delta employees and directors having grant date fair values of
$264,000
(
12,000
shares) and
$337,000
(
22,000
shares), respectively. The recipients vested in the awards shortly after the awards were granted, but during the time between the grant dates and the vesting dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.
Performance Shares
In
2013
and
2012
, performance shares were awarded to the Company's executive officers having grant date fair values of
$844,000
(
39,000
shares) and
$552,000
(
36,000
shares), respectively. The performance share awards vest only if the performance objectives of the awards are met, which are based on the Company's earnings per common share for the fiscal year in which the performance shares are awarded, before any cash bonuses or share-based compensation. Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest equally over a three-year period beginning each August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period. The recipients of the awards also become vested as a result of certain events such as death or disability of the holders. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards. Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.
As of June 30,
2013
the performance objectives for the performance shares awarded in 2013 have been satisfied and subject to further limitations of the plan, up to
39,000
unvested shares will be issued to the recipients, subject to a service condition whereby a recipient of
the award shall vest in one-third increments each year beginning August 31, 2013 and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period.
The performance objectives for the performance shares awarded in 2012 were met and
27,000
unvested shares were issued on August 31,
2012
, of which
18,000
shares remain unvested as of June 30,
2013
.
For
2013
and
2012
, compensation expense related to the performance shares was
$658,000
and
$375,000
, respectively. Compensation expense of
$431,000
is expected to be recognized between 2014 and 2016 for the unvested shares.
Our performance shares have graded vesting schedules, and each separate annual vesting tranche is treated as a separate award for expense recognition. Compensation expense is amortized over the vesting period of the individual awards based on the probable outcome of meeting the performance objectives.
Since the performance condition has been satisfied, the holder of performance shares will have both dividend participation rights and voting rights during the remaining term of the awards. The holder becomes vested as a result of certain events such as death or disability of the holder. Subject to the satisfaction of the performance condition, the weighted average expected remaining vesting period at June 30,
2013
is
1.6
years.
The following summarizes the activity for performance shares:
|
|
|
|
|
|
|
|
|
Performance shares
|
|
Number of shares
|
|
Weighted-average grant date fair value
|
|
|
|
|
Unvested shares at June 30, 2011
|
32,000
|
|
|
$
|
14.67
|
|
Granted (1)
|
36,000
|
|
|
$
|
15.32
|
|
Vested
|
(10,666
|
)
|
|
(14.67
|
)
|
Forfeited (2)
|
(9,000
|
)
|
|
(15.32
|
)
|
Unvested shares at June 30, 2012
|
48,334
|
|
|
$
|
15.03
|
|
Granted (1)
|
39,000
|
|
|
$
|
21.63
|
|
Vested
|
(19,666
|
)
|
|
(14.96
|
)
|
Unvested shares at June 30, 2013
|
67,668
|
|
|
$
|
18.85
|
|
|
|
(1)
|
Represents the maximum number of shares which could be issued based on achieving the performance criteria.
|
|
|
(2)
|
Represents the number of shares awarded but not earned based on the actual performance criteria achieved.
|
(18) Quarterly Financial Data (Unaudited)
The quarterly data reflects, in the opinion of management, all normal recurring adjustments necessary to present fairly the results for the interim periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
Operating
Revenues
|
|
Operating
Income
|
|
Net Income
(Loss)
|
|
Basic Earnings (Loss) per Common Share
|
|
Diluted Earnings (Loss) per Common Share
|
Fiscal 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
$
|
11,452,315
|
|
|
$
|
415,946
|
|
|
$
|
(158,903
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.02
|
)
|
December 31
|
|
22,106,691
|
|
|
4,967,855
|
|
|
3,249,376
|
|
|
0.47
|
|
|
0.47
|
|
March 31
|
|
31,133,349
|
|
|
7,323,064
|
|
|
4,242,677
|
|
|
0.62
|
|
|
0.62
|
|
June 30
|
|
15,972,482
|
|
|
481,814
|
|
|
(132,374
|
)
|
|
(0.02
|
)
|
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30
|
|
$
|
12,896,327
|
|
|
$
|
566,101
|
|
|
$
|
(797,126
|
)
|
|
$
|
(0.12
|
)
|
|
$
|
(0.12
|
)
|
December 31
|
|
22,526,345
|
|
|
4,984,294
|
|
|
2,512,238
|
|
|
0.37
|
|
|
0.37
|
|
March 31
|
|
26,716,070
|
|
|
6,971,971
|
|
|
3,925,295
|
|
|
0.58
|
|
|
0.58
|
|
June 30
|
|
11,939,580
|
|
|
742,862
|
|
|
143,591
|
|
|
0.02
|
|
|
0.02
|
|
(19) Subsequent Events
In August,
2013
,
17,000
shares of common stock was awarded to virtually all Delta employees and directors having a grant date fair value of
$350,000
. Additionally, in August,
2013
, performance shares were awarded to the Company's executive officers. The performance share awards vest only if the performance objective of the awards is met, which is based on the Company's fiscal 2014 audited earnings per share, before any cash bonuses or share-based compensation. Subject to further limitations described in the Plan, all performance shares paid shall be in the form of unvested shares, which contain a service condition whereby recipients of the awards shall vest in one-third increments each year beginning on August 31,
2014
, and annually each August 31 thereafter until fully vested as long as the recipient is an employee throughout each such service period. The maximum number of shares which could be issued under the performance awards is
39,000
, having a grant date fair value of
$801,000
.