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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2004.
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 0-8788.
DELTA NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
Kentucky 61-0458329
(State of Incorporation) (IRS Employer Identification Number)
3617 Lexington Road 40391
Winchester, KY 40391 (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: 859-744-6171
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name on Each Exchange on Which Registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock $1 Par Value
(Title of class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X| No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K |X|
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes |X| No [ ]
State the aggregate market value of the voting and non-voting common equity held
by non affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity, as of
the last business day of the registrant's most recent completed second fiscal
quarter. $ 76,329,704
As of August 26, 2004, Delta Natural Gas Company, Inc. had outstanding 3,207,945
shares of common stock $1 par value.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's definitive proxy statement to be filed with the Commission not
later than 120 days after June 30, 2004, is incorporated by reference in Part
III of this Report.
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TABLE OF CONTENTS
Page Number
PART I
Item 1. Business 1
Item 2. Properties 8
Item 3. Legal Proceedings 8
Item 4. Submission of Matters to a Vote of
Security Holders 8
PART II
Item 5. Market for Registrant's Common Equity, Related
Stockholder Matters and Issuer Purchases of
Equity Securities 8
Item 6. Selected Financial Data 10
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 11
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 20
Item 8. Financial Statements and Supplementary Data 20
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 21
Item 9A. Controls and Procedures 21
Item 9B. Other Information 21
PART III
Item 10. Directors and Executive Officers of the Registrant 21
Item 11. Executive Compensation 21
Item 12. Security Ownership of Certain Beneficial
Owners and Management and Related
Stockholder Matters 21
Item 13. Certain Relationships and Related Transactions 21
Item 14. Principal Accountant Fees and Services 22
PART IV
Item 15. Exhibits and Financial Statement Schedules 23
Signatures 25
PART I
Item 1. Business
General
We sell natural gas to approximately 40,000 retail customers on our
distribution system in central and southeastern Kentucky. Additionally, 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 we produce a relatively small
amount of natural gas and oil from our southeastern Kentucky wells.
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 producing, selling and transporting gas in our
service territory.
We strive to achieve operational excellence through economical, reliable
service and our emphasis on responsiveness to customers. We continue to invest
in facilities for the transmission, distribution and storage of natural gas. We
believe that our responsiveness to customers and the dependability of the
service we provide afford us additional opportunities for growth. While we seek
those opportunities, our strategy will continue to entail a conservative
approach that seeks to minimize our exposure to market risk arising from
fluctuations in the prices of gas.
We operate through two segments, a regulated segment and an unregulated
segment. See Note 13 of the Notes to Consolidated Financial Statements. Through
our regulated segment, we sell natural gas to our retail customers in 23
predominantly rural communities. In addition, our regulated segment transports
gas to industrial customers on our system who purchase gas in the open market.
Our regulated segment also transports gas on behalf of local producers and other
customers not on our distribution system. Our results of operations and
financial condition have been strengthened by regulatory developments in recent
years, including a weather normalization provision which has reduced
fluctuations in our earnings due to variations in weather and a gas cost
recovery clause.
We operate our unregulated segment through three wholly-owned subsidiaries.
Two of these subsidiaries, Delta Resources, Inc. and Delgasco, Inc., purchase
natural gas on the national market and from Kentucky producers. We resell this
gas to industrial customers on our distribution system and to others not on our
system. Our third subsidiary that is part of the unregulated segment, Enpro,
Inc., produces natural gas and oil that is sold on the unregulated market.
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.
Distribution and Transmission of Natural Gas
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.
The communities we serve continue to expand, resulting in growth
opportunities for us. Industrial parks have been built in our service areas,
resulting in some new industrial customers.
Factors that affect our revenues include rates we charge our customers, our
supply cost for the natural gas we purchase for resale, economic conditions in
our service areas, weather and competition.
Although the rules of the Kentucky Public Service Commission permit us to
pass through to our customers changes in the price we must pay for our gas
supply, increases in our rates to customers may cause our customers to conserve
or to use alternative energy sources.
Our retail sales are seasonal and temperature-sensitive, since the majority
of the gas we sell is used for heating. Variations in the average temperature
during the winter impact our revenues year-to-year. Kentucky Public Service
Commission regulations, however, provide for 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 retail customers. These
alternate sources include electricity, coal, oil, propane and wood. Our
unregulated subsidiaries, which sell gas to industrial customers and others,
compete with natural gas producers and natural gas marketers for those
customers.
Our larger customers can obtain their natural gas supply by purchasing
their natural gas directly from interstate suppliers, local producers or
marketers and arranging for alternate transportation of the gas to their plants
or facilities. Customers may undertake such a by-pass of our distribution system
in order to achieve lower prices for their gas service. Our larger customers who
are in close proximity to alternative supplies would be most likely to consider
taking this action. Additionally, some of our industrial customers are able to
switch economically to alternative sources of energy. These are competitive
concerns that we continue to address.
Some natural gas producers in our service area can access pipeline delivery
systems other than ours, which generates competition for our transportation
function. We continue our efforts to purchase or transport natural gas that is
produced in reasonable proximity to our transportation facilities.
As an active participant in many areas of the natural gas industry, we plan
to continue efforts to expand our gas distribution system and customer base. We
continue to consider acquisitions of other gas systems, some of which are
contiguous to our existing service areas, as well as expansion within our
existing service areas.
We anticipate continuing activity in gas production and transportation and
plan to pursue and increase these activities wherever practicable. We continue
to consider the construction, expansion or acquisition of additional
transmission, storage and gathering facilities to provide for increased
transportation, enhanced supply and system flexibility.
Gas Supply
We purchase our natural gas from a combination of interstate and Kentucky
sources. In our fiscal year ended June 30, 2004, we purchased approximately 99%
of our natural gas from interstate sources.
Interstate Gas Supply
We acquire our interstate gas supply from gas marketers. We currently have
commodity requirements agreements for our Columbia Gas Transmission, Columbia
Gulf Transmission and Tennessee Gas Pipeline supplied areas with Atmos Energy
Marketing (formerly known as Woodward Marketing, L.L.C). Under these commodity
requirements agreements, the gas marketer is obligated to supply the volumes
consumed by our regulated customers in defined sections of our service areas.
The gas we purchase under these agreements is priced at index-based market
prices or at mutually agreed to fixed prices. The index-based market prices are
determined based on the prices published on the first of the month in Platts'
Inside FERC's Gas Market Report in the indices that relate to the pipelines
through which the gas will be transported, plus or minus an agreed-to fixed
price adjustment per million British Thermal Units of gas sold. Consequently,
the price we pay for interstate gas is based on current market prices.
Our agreement with Atmos Energy Marketing for the Tennessee Gas Pipeline
supplied service areas is for a term that expires on April 30, 2005, and shall
continue year to year thereafter unless cancelled by either party by written
notice at least sixty (60) days prior to the annual anniversary date of the
agreement. Our agreement with Atmos, under which we purchase the natural gas
transported for us by Columbia Gas Transmission Corporation and Columbia Gulf
Transmission Corporation, became effective May 1, 2003 and replaced the supply
agreement with Dynegy Marketing and Trade which expired April 30, 2003. The term
for the Atmos supply for our Columbia Gas Transmission contract extends through
April 30, 2006.
We also purchase additional interstate natural gas from Atmos, as needed,
in addition to our commodity requirements agreements with Atmos. This spot gas
purchasing arrangement is pursuant to an agreement with Atmos that expires on
March 31, 2005. Delta's purchases from Atmos under this spot purchase agreement
are generally month-to-month. However, Delta does have the option of
forward-pricing gas for one or more months for the upcoming winter season. The
price of gas under this agreement is based on current market prices, determined
in a similar manner as under the commodity requirements contract with Atmos,
with an agreed-to fixed price adjustment per Million British Thermal Units
purchased. In our fiscal year ended June 30, 2004, approximately 41% of Delta's
gas supply was purchased under our agreements with Atmos.
Delta purchases gas from M & B Gas Services, Inc. for injection into our
underground natural gas storage field and to supply our southern system. We are
not obligated to purchase any minimum quantities from M & B nor to purchase gas
from M & B for any periods longer than one month at a time. The gas is priced at
index-based market prices or at mutually agreed to fixed prices. Our agreement
with M & B may be terminated upon 30 days' prior written notice by either party.
Any purchase agreements for unregulated sales activities may have longer terms
or multiple month purchase commitments. In our fiscal year ended June 30, 2004,
approximately 58% of Delta's gas supply was purchased under our agreement with M
& B.
We also purchase interstate natural gas from other gas marketers as needed
at either current market prices, determined by industry publications, or at
forward market prices.
Transportation of Interstate Gas Supply
Our interstate natural gas supply is transported to us from production and
storage fields by Tennessee Gas Pipeline Company, Columbia Gas Transmission
Corporation, Columbia Gulf Transmission Corporation and Texas Eastern
Transmission Corporation.
Our agreements with Tennessee Gas Pipeline extend through 2008 and
thereafter automatically renew for subsequent five-year terms unless terminated
by one of the parties. Tennessee is obligated under these agreements to
transport up to 19,600 thousand cubic feet ("Mcf") per day for us. During fiscal
2004, Tennessee transported a total of 1,454,000 Mcf for us under these
contracts. Annually, approximately 30% of Delta's supply requirements flow
through Tennessee Gas Pipeline to our points of receipt under our transportation
agreements with Tennessee. We have gas storage agreements with Tennessee under
the terms of which we reserve a defined storage space in Tennessee's production
area storage fields and its market area storage fields, and we reserve the right
to withdraw up to fixed daily volumes. These gas storage agreements terminate 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 2004 Columbia
Gas and Columbia Gulf transported for us a total of 542,000 Mcf, or
approximately 11% of Delta's supply requirements, under all of our agreements
with them.
All of our transport agreements with Columbia Gas and Columbia Gulf extend
through 2008 and thereafter continue on a year-to-year basis until terminated by
one of the parties.
Columbia Gulf also transported additional volumes under agreements it has
with M & B to a point of interconnection between Columbia Gulf and us where we
purchase the gas to inject into our storage field, as discussed below. The
amounts transported and sold to us under the agreement between Columbia Gulf and
this gas marketer for fiscal 2004 constituted approximately 58% of Delta's 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 Transmission Corporation.
However, Atmos Energy Marketing has an arrangement with Texas Eastern to
transport the gas to us that we purchase from that marketer. Consequently, Texas
Eastern transports a small percentage of our interstate gas supply. In our
fiscal year ended June 30, 2004, Texas Eastern transported approximately 11,000
Mcf of natural gas to our system, which constituted less than 1% of our gas
supply.
Kentucky Gas Supply
We have an agreement with Columbia Natural Resources to purchase natural
gas through October 31, 2005, and thereafter it will renew for additional terms
of one year each until terminated by one of the parties. We purchased 55,000 Mcf
from Columbia Natural Resources during fiscal 2004. The price for the gas we
purchase from Columbia Natural Resources is based on the index price of spot gas
delivered to Columbia Gas in the relevant region as reported in Platt's Inside
FERC's Gas Market Report, plus a fixed adjustment per million British Thermal
units of gas purchased. Columbia Natural Resources delivers this gas to our
customers directly from its own pipelines.
We own and operate an underground natural gas storage field that we use to
store a significant portion of our winter gas supply needs. The storage gas is
delivered during the summer injection season by Columbia Gulf on behalf of M & B
to an interconnection point between Columbia Gulf and us where we purchase and
receive the gas and flow it to our storage field. M & B arranges transportation
of the gas through the Columbia Gulf system to us. 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. During fiscal 2004, we
withdrew 1,725,000 Mcf from this storage field.
We continue to seek additional gas supplies from available sources. We will
continue to maintain an active gas supply management program that emphasizes
long-term reliability and the pursuit of cost-effective sources of gas for our
customers.
Regulatory Matters
The Kentucky Public Service Commission exercises regulatory authority over
our retail natural gas distribution and our transportation services. The
Kentucky Public Service Commission regulation of our business includes setting
the rates we are permitted to charge our retail customers and our transportation
customers.
We monitor our need to file requests with the Kentucky Public Service
Commission for a general rate increase for our retail gas and transportation
services. Through these general rate cases, we are able to adjust the sales
prices of our retail gas we sell to and transport for our customers.
On April 5, 2004, we filed a general rate case with the Kentucky Public
Service Commission. This filing requested an annual increase in revenues of
$4,277,000, an increase of 7.4%. In accordance with normal practices, the
Commission suspended the proposed rates until October 4, 2004 and a hearing was
held on August 18, 2004. We cannot predict the outcome of this proceeding.
The Kentucky Public Service Commission has also approved a gas cost
recovery clause, which permits us to adjust the rates charged to our customers
to reflect changes in our natural gas supply costs. Although we are not required
to file a general rate case to adjust rates pursuant to the gas cost recovery
clause, we are required to make quarterly filings with the Kentucky Public
Service Commission.
During July, 2001, the Kentucky Public Service Commission required an
independent audit of our gas procurement activities and the gas procurement
activities of four other Kentucky gas distribution companies as part of its
investigation of increases in wholesale natural gas prices and their impact on
customers. The Kentucky Public Service Commission indicated that Kentucky
distributors had generally developed sound planning and procurement procedures
for meeting their customers' natural gas requirements and that these procedures
had provided customers with reliable supplies of natural gas at reasonable
costs. The Kentucky Public Service Commission noted the events of the 2000-2001
heating season, including changes in natural gas wholesale markets. It required
the auditors to evaluate distributors' gas planning and procurement strategies
in light of the recent more volatile wholesale markets, with a primary focus on
a balanced portfolio of gas supply that balances cost issues, price risk and
reliability. The auditors were selected by the Kentucky Public Service
Commission. The final audit report, dated November 15, 2002, contains 16
procedural and reporting-related recommendations in the areas of gas supply
planning, organization, staffing, controls, gas supply management, gas
transportation, gas balancing, response to regulatory change and affiliate
relations. The report also addresses several general areas for the five gas
distribution companies involved in the audit, including Kentucky natural gas
price issues, hedging, gas cost recovery mechanisms, budget billing,
uncollectible accounts and forecasting. We believe that implementation of the
recommendations will not result in a significant impact on our financial
position or results of operations. We are required to file periodic reports as
to the status of our implementation of the recommendations. On July 26, 2004,
the Kentucky Public Service Commission notified us that fourteen of the sixteen
recommendations are considered completed. Our next progress report is to be
filed by October 22, 2004.
In addition to regulation by the Kentucky Public Service Commission, we may
obtain non-exclusive franchises from the cities and communities 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 a local franchise. We hold
franchises in four of the cities and seven of the communities we serve. In the
other cities and communities we serve, either our franchises have expired, the
communities do not have governmental organizations authorized to grant
franchises, or the local governments have not required or do not want to offer a
franchise. We attempt to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government 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 or community. To date, the absence of
a franchise has caused no adverse effect on our operations.
Capital Expenditures
Capital expenditures during 2004 were $9.0 million and for 2005 are
estimated to be $4.8 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 line of credit. The
current available line of credit is $40 million, of which $4.7 million had been
borrowed at June 30, 2004.
During February, 2003, we completed the sale of the aggregate principal
amount of $20,000,000 of 7.00% Debentures due 2023. We used the net proceeds to
redeem our 8.30% Debentures outstanding in the aggregate principal amount of
$14,806,000 and to pay down our short-term notes payable.
During May, 2003, we issued and sold through underwriters 600,000 shares of
our common stock. The net proceeds of $12,493,000 from the sale of the stock
were used to pay down our short-term notes payable.
Present plans are to utilize the short-term line of credit to help meet
planned capital expenditures and operating cash requirements. The amounts and
types of future long-term debt and equity financings will depend upon our
capital needs and market conditions.
During 2004 the requirements of the Employee Stock Purchase Plan (see Note
4(c) of the Notes to Consolidated Financial Statements) were met through the
issuance of 4,504 shares of common stock resulting in an increase of $106,000 in
Delta's common shareholders' equity. Our expenses under the stock plan were
$59,000, $53,000 and $52,000 for the three years ended June 30, 2004, 2003 and
2002, respectively. The Dividend Reinvestment and Stock Purchase Plan (see Note
5 of the Notes to Consolidated Financial Statements) resulted in the issuance of
29,129 shares of common stock providing an increase of $699,000 in Delta's
common shareholders' equity.
Employees
On June 30, 2004, we had 156 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 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.
Consolidated Statistics
For the Years Ended June 30, 2004 2003 2002 2001 2000
---- ---- ---- - ---- ----
Average Retail Customers Served
Residential 33,570 33,757 33,624 33,691 33,251
Commercial 5,298 5,290 5,235 5,227 5,110
Industrial 61 63 62 65 66
-------- ------- -------- ------- --------
Total 38,929 39,110 38,921 38,983 38,427
====== ======== ======= ======= ======
Operating Revenues ($000)
Residential sales 28,737 26,749 23,203 28,088 19,672
Commercial sales 18,719 16,916 13,832 17,040 10,952
Industrial sales 1,731 1,607 1,141 2,046 1,104
------- ------- ------- ------- -------
Total regulated sales 49,187 45,272 38,176 47,174 31,728
On-system transportation 3,854 3,873 3,826 3,895 4,056
Off-system transportation 2,104 1,560 1,220 814 522
Non-regulated sales 27,091 20,611 17,191 49,492 18,103
Other 205 195 198 248 190
Eliminations for intersegment (3,247) (3,131) (4,741) (30,853) (8,672)
-------- -------- -------- ------- --------
Total 79,194 68,380 55,870 70,770 45,927
====== ======= ======= ======= ======
System Throughput (Million Cu. Ft.)
Residential sales 2,202 2,416 2,133 2,614 2,266
Commercial sales 1,529 1,627 1,389 1,666 1,397
Industrial sales 164 181 142 249 174
------ ------ ------ ------ --------
Total regulated sales 3,895 4,224 3,664 4,529 3,837
On-system transportation 5,166 5,299 4,865 4,769 4,704
Off-system transportation 7,190 4,215 2,793 1,767
5,396
Non-regulated sales 3,958 3,591 3,858 4,851 4,939
Eliminations for intersegment (3,918) (3,523) (3,641) (4,666) (4,415)
--------- -------- -------- -------- ---------
Total 16,291 14,987 12,961 12,276 10,832
====== ======= ======= ======= ======
Average Annual Consumption Per
Average Residential Customer
(Thousand Cu. Ft.) 66 72 63 78 68
Lexington, Kentucky Degree Days
Actual 4,493 4,914 4,137 4,961 4,162
Percent of 30 year average 96.3 105.8 89.1 106.8 89.6
Item 2. Properties
We own our corporate headquarters in Winchester, Kentucky. We own ten
buildings used for field operations in the cities we serve. Also, we own a
building in Laurel County, Kentucky used for training and equipment and
materials storage.
We own approximately 2,400 miles of natural gas gathering, transmission,
distribution, storage and service 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 natural gas distribution,
transmission and storage segment. See Note 13 of the Notes to Consolidated
Financial Statements for a description of Delta's two business segments.
Through our wholly-owned subsidiary, Enpro, we produce oil and gas as part
of the unregulated segment of our business.
Enpro owns interests in oil and gas leases on 11,000 acres located in Bell,
Knox and Whitley Counties. Forty gas wells and five oil wells are producing from
these properties. The remaining proved, developed natural gas reserves on these
properties are estimated at 3.2 million Mcf. Oil production from the property
has not been significant. Also, Enpro owns the oil and gas underlying 15,400
additional acres in Bell, Clay and Knox Counties. These properties are currently
non-producing, and we have performed no reserve studies on these properties.
Enpro produced a total of 215,000 Mcf of natural gas during fiscal 2004 from all
the properties described in this paragraph..
A producer is conducting exploration activities on part of Enpro's
developed holdings. Enpro reserved the option to participate in wells drilled by
this producer and also retained certain working and royalty interests in any
production from future wells.
Our assets have no significant encumbrances.
Item 3. Legal Proceedings
We are not a party to any legal proceedings that are expected to have a
material impact on our financial condition or our results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of 2004.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
We have paid cash dividends on our common stock each year since 1964. The
frequency and amount of future dividends will depend upon our earnings,
financial requirements and other relevant factors, including limitations imposed
by the indenture for our Debentures.
Our common stock is traded on the Nasdaq National Market System and trades
under the symbol "DGAS". There were 2,145 record holders of our common stock as
of June 30, 2004. The accompanying table sets forth, for the periods indicated,
the high and low sales prices for the common stock on the Nasdaq National Market
System and the cash dividends declared per share.
Range of Stock Prices($) Dividends
Quarter High Low Per Share($)
- ------- ---- --- ------------
Fiscal 2004
First 23.90 22.45 .295
Second 24.03 22.80 .295
Third 27.78 23.56 .295
Fourth 27.65 23.00 .295
Fiscal 2003
First 21.97 18.50 .295
Second 21.99 19.50 .295
Third 23.99 21.24 .295
Fourth 24.10 21.00 .295
The closing sale prices shown above reflect prices between dealers and does
not include markups or markdowns or commissions and may not necessarily
represent actual transactions.
In July, 2002, 2003 and 2004, we distributed 4,728, 4,504 and 4,826 shares,
respectively, of our common stock to our employees under our Employee Stock
Purchase Plan (see Note 4(c) of the Notes to Consolidated Financial Statements).
We received cash consideration for one half of those shares of $52,000, $53,000
and $59,000, respectively, while one-half of the shares were provided to our
employees without cash consideration as a part of our compensation and benefits
for our employees. We have discontinued our Employee Stock Purchase Plan for
fiscal 2005.
We offered and sold our securities through our Employee Stock Purchase Plan
pursuant to the exemption from registration provided by Rule 147 under the
Securities Act of 1933. This exemption is available since we are incorporated
and doing business in Kentucky and all our eligible employees are residents of
Kentucky. Our Employee Stock Purchase Plan was authorized by our Board of
Directors but was not required to be submitted to our shareholders for approval.
Also, in June of 2002 and 2003, we awarded, respectively, a total of 800
and 900 shares of our common stock to our directors (100 shares per eligible
director per year). We received no cash consideration for the shares, which were
provided to our directors as a part of their compensation. This transaction may
not have involved a "sale" of securities under the Securities Act of 1933, and
in any event, the securities were qualified for an exemption from registration
provided by Rule 147 under the Securities Act of 1933. This exemption is
available since we are incorporated and doing business in Kentucky and all
participating directors are residents of Kentucky.
No underwriters were engaged in connection with any of the foregoing
transactions, and thus no underwriter discounts or commissions were paid in
connection with any of the foregoing.
Item 6. Selected Financial Data
For the Years Ended June 30,
2004 2003 2002 2001 2000
---- ----- ---- ----- ----
Summary of Operations ($)
Operating revenues 79,193,614 68,380,263 55,870,219 70,770,156 45,926,775
Operating income 8,173,304 8,526,366 8,401,452 8,721,719 8,176,722
Net income 3,838,059 3,850,607 3,636,713 3,635,895 3,464,857
Basic and diluted earnings
per common share 1.20 1.46 1.45 1.47 1.42
Dividends declared
per common share 1.18 1.18 1.16 1.14 1.14
Average Number of Common
Shares Outstanding
(basic and diluted) 3,185,158 2,641,829 2,513,804 2,477,983 2,433,397
Total Assets ($) 138,372,129 133,287,316 127,141,327 124,179,138 112,918,919
Capitalization ($)
Common shareholders'
equity (a) 48,830,161 45,892,597 34,182,277 32,754,560 31,297,418
Long-term debt (a) 53,049,000 53,373,000 48,600,000 49,258,902 50,723,795
-- ---------- ---------- ---------- ---------- ----------
Total capitalization 101,879,161 99,265,597 82,782,277 82,013,462 82,021,213
=========== ========== ========== ========== ==========
Short-Term Debt ($)(a)(b) 6,388,180 2,681,099 21,105,000 19,250,000 11,375,000
Other Items ($)
Capital expenditures 8,959,153 8,839,091 9,748,304 7,069,713 8,795,653
Total plant, before accumulated
depreciation 170,337,427 163,745,044 156,305,063 147,792,390 141,986,856
- ---------------------
(a) During February, 2003, we issued $20,000,000 aggregate principal amount of
7.00% Debentures due 2023. The net proceeds of the offering were
$19,181,000. We used the net proceeds to redeem $14,806,000 aggregate
principal amount of our 8.30% Debentures due 2026 and to pay down our
short-term notes payable. During May, 2003, we used the net proceeds of
$12,493,000 from our sale of 600,000 shares of common stock to pay down our
short-term notes payable.
(b) Includes current portion of long-term debt.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Overview of 2004 and Future Outlook
Overview
The following is a discussion of the segments in which we compete, the
corporate strategy for the conduct of our business within these segments and
significant events that have occurred during 2004. Our Company has two segments:
(i) a regulated natural gas distribution, transmission and storage segment, and
(ii) a non-regulated segment which participates in related ventures, consisting
of natural gas marketing and production.
Earnings from the regulated segment are primarily influenced by sales
volumes, the rates we charge our customers and the expenses we incur. In order
for us to achieve our strategy of maintaining reasonable long-term earnings,
cash flow and stock value, we must successfully manage each of these factors.
Sales volumes are temperature-sensitive. Our regulated sales volumes in any
period reflect the impact of weather, with colder temperatures generally
resulting in increased sales volumes. The impact of unusual winter temperatures
on our revenues is reduced given our ability to adjust our winter rates for
residential and small non-residential customers in response to unusual winter
temperatures. The Kentucky Public Service Commission sets the rates we are
permitted to charge our customers in the regulated segment. We monitor our need
to file requests with the Kentucky Public Service Commission for a general rate
increase for our retail gas and transportation services. Through these general
rate cases, we seek approval from the Kentucky Public Service Commission to
adjust the rates we charge our customers. The regulated segment's largest
expense is gas supply, which we are permitted to pass through to our customers.
We control remaining expenses through budgeting, approval and review.
Weather was warmer in 2004 than 2003, resulting in decreased retail and
on-system transportation volumes. Rates charged our customers only changed
during 2004 to reflect increases in gas costs through the gas cost recovery
clause and to reflect warmer winter weather through the weather normalization
tariff. Gas supply expense increased in response to the increase in natural gas
prices as determined in the unregulated national market.
Our non-regulated segment markets natural gas to large-use customers both
on and off Delta's regulated system. We endeavor to enter sales agreements when
we can match estimated demand with a supply that provides an acceptable margin.
Net income per share declined primarily due to the increase in the number
of our common shares outstanding resulting from our Dividend Reinvestment Plan
and Stock Purchase Plan and Employee Stock Purchase Plan, and our May, 2003
Common Stock offering of 600,000 shares.
Future Outlook
In 2005 and beyond, our success will be dependent, in part, on our ability
to maintain a reasonable rate of return in our regulated segment. In April 2004,
we filed a request for increased base rates with the Kentucky Public Service
Commission. This general rate case requested an annual revenue increase of 7.4%,
although we cannot predict the outcome of this proceeding. A hearing at the
Kentucky Public Service Commission was held on August 18, 2004 and we expect to
implement new rates in October of 2004.
We expect our non-regulated segment to continue to contribute to
consolidated net income in 2005.
Liquidity and Capital Resources
Sources and Uses of Cash
Operating activities provide our primary source of cash. Cash provided by
operating activities consists of net income adjusted for non-cash items,
including depreciation, depletion, amortization, deferred income taxes and
changes in working capital.
Our ability to maintain liquidity depends on our short-term line of bank
credit, shown as notes payable on the accompanying balance sheet. Notes payable
increased to $4,738,000 at June 30, 2004, compared with $1,031,000 at June 30,
2003. This $3,707,000 increase reflects the fact that we generate internally
only a portion of the cash necessary for our capital expenditure requirements.
We made capital expenditures of $8,959,000, $8,839,000 and $9,748,000 during the
fiscal years ended 2004, 2003 and 2002, respectively. We finance the balance of
our capital expenditures on an interim basis through this short-term line of
bank credit. We periodically repay our short-term borrowings under our line of
credit by using the net proceeds from the sale of long-term debt and equity
securities.
Long-term debt decreased to $53,049,000 at June 30, 2004, compared with
$53,373,000 at June 30, 2003. This $324,000 decrease resulted from provisions in
the Debentures allowing limited redemptions to be made to certain holders and/or
their beneficiaries.
Cash and Cash Equivalents decreased to $169,000 at June 30, 2004, compared
with $1,420,000 at June 30, 2003. This $1,251,000 decrease in cash and cash
equivalents for the year ended June 30, 2004 is compared with the $1,195,000 and
$61,000 increases in cash and cash equivalents for the years ended June 30, 2003
and June 30, 2002, respectively, in the following table:
($000)
2004 2003 2002
---- ---- ----
Provided by operating activities $ 7,276 $ 15,186 $ 10,838
Used in investing activities (8,959) (8,839) (9,748)
Provided by (used in) financing
activities 432 (5,152) (1,029)
----------- ----------- --------
Increase (decrease) in cash and
cash equivalents $ (1,251) $ 1,195 $ 61
========= ========== =========
For the year ended June 30, 2004, we had a $1,251,000 decrease in cash and
cash equivalents compared to a $1,195,000 increase in cash and cash equivalents
for the year ended June 30, 2003. This additional $2,446,000 of cash used
resulted primarily from increased cash needs of $7,712,000 for gas stored
underground, gas accounts payable and deferred gas cost due to the increase in
volumes stored and the increase of gas prices between periods. In addition, we
used $1,561,000 more cash for trade payables. These increased cash needs were
partially met with $1,478,000 of increased customer payments on accounts
receivable and the $5,584,000 increase in cash provided by financing activities.
For the year ended June 30, 2003, we had a $1,195,000 increase in cash and
cash equivalents compared to a $61,000 increase in cash and cash equivalents for
the year ended June 30, 2002. This additional $1,134,000 of cash provided
resulted primarily from reduced cash use of $6,723,000 for gas stored
underground, gas accounts payable and deferred gas cost due primarily to a
higher gas payable balance for June 30, 2003. $909,000 less was used for capital
expenditures and $880,000 more income taxes were deferred. These increases in
cash provided were offset with $3,450,000 of decreased customer payments on
accounts receivable and the $4,123,000 increase in cash used in financing
activities.
Cash Requirements
Our capital expenditures drive our continued need for capital. Our capital
expenditures for fiscal 2005 are expected to be $4.8 million, a $4.2 million
decrease from fiscal 2004 capital expenditures. The major reason for this
decrease is the completion in 2004 of certain multi-year transmission line and
storage improvement projects. These capital expenditures are being made for
system extensions and for the replacement and improvement of existing
transmission, distribution, gathering, storage and general facilities.
The following is provided to summarize our contractual cash obligations for
indicated periods after June 30, 2004:
Payments Due by Period
($000) 2005 2006-2007 2008-2009 After 2009 Total
---- --------- --------- ---------- -----
Interest expense(a) $ 4,160 $ 8,320 $ 8,320 $ 41,344 $ 62,144
Long-term debt(b) 1,650 3,300 3,300 46,449 54,699
Operating lease(c) 76 139 125 758 1,098
Pension contributions(d) 798 1,596 1,596 10,334 14,324
Gas purchase obligations(e) 13,973 6,354 1,620 -- 21,947
--------- --------- --------- --------- ---------
Total contractual
obligations $ 20,657 $19,709 $14,961 $ 98,885 $154,212
========= ========= ======== ========= ========
(a) Our Long-Term Debt, Notes Payable and Customers' Deposits all require
interest payments. Interest payments are projected based on fiscal 2004
interest payments until the underlying debt matures. We have assumed a 40
year maturity for the Notes Payable.
(b) See Note 8 of the Notes to Consolidated Financial Statements for a
description of this debt.
(c) The operating lease amount after June, 2009 includes the present value of
leases having an indeterminate life. These leases relate primarily to
storage well and compressor station site leases. For the purpose of this
calculation we have assumed a 40 year life for these agreements, although
we may cancel these leases at our option. To the extent that these leases
extend beyond 2043, the annual lease payments will be $53,000.
(d) The pension contribution amount is based on the 2005 company contribution
to the pension plan. For the purpose of this calculation, we have assumed a
40 year life for the pension plan. To the extent that the plan extends
beyond 2043, the annual contribution is estimated to be $798,000.
(e) Gas purchase obligations represent annual commitments with suppliers for
periods extending up to four years. These costs are recoverable in customer
rates.
In July, 2002, the U.S. Congress passed the Sarbanes-Oxley Act of 2002.
Although the Act did not substantively change our corporate governance and
internal control practices, we have formalized many of our governance and
internal control related procedures, and are working in order to be in the
position to issue the required Statement of Management Responsibility, which
must be attested to by our external auditors in conjunction with the June 30,
2005 Annual Report on Form 10-K. We estimate that our external expenses for
complying with the Act by June 30, 2005 will total in the range of approximately
$400,000 to $450,000 of which approximately $349,000 has been recorded as of
June 30, 2004.
See Note 11 of the Notes to Consolidated Financial Statements for other
commitments and contingencies.
Sufficiency of Future Cash Flows
To the extent that internally generated cash is not sufficient to satisfy
operating and capital expenditure requirements and to pay dividends, we will
rely on our short-term line of credit. Our current available line of credit is
$40,000,000, of which $4,738,000 was borrowed at June 30, 2004, classified as
notes payable in the accompanying balance sheet. The line of credit is with
Branch Banking and Trust Company, and extends through October 31, 2004. We
intend to pursue renewal or to enter into a new agreement and seek similar terms
as the existing agreement.
We expect that internally generated cash, coupled with short-term
borrowings, will be sufficient to satisfy our operating and normal capital
expenditure requirements and to pay dividends for the next twelve months and the
foreseeable future. We do not foresee defaulting on any of our line of credit or
Debenture agreements.
Our ability to sustain acceptable earnings levels, finance capital
expenditures and pay dividends is contingent on the adequate and timely
adjustment of the regulated sales and transportation prices we charge our
customers. The Kentucky Public Service Commission sets these prices and we
continuously monitor our need to file rate requests with the Kentucky Public
Service Commission for a general rate increase for our regulated services. On
April 5, 2004, Delta filed a request for increased rates with the Kentucky
Public Service Commission. This general rate case (Case No. 2004-00067)
requested an annual revenue increase of $4,277,000, an increase of 7.4%. The
test year for the case was December 31, 2003. The rates were suspended up to and
including October 4, 2004 by the Kentucky Public Service Commission in an Order
dated April 23, 2004 so that they could investigate and determine the
reasonableness of the proposed rates. A hearing was held on August 18, 2004. We
cannot predict the outcome of this proceeding.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions, and at times difficult, subjective or
complex judgments. Changes in these estimates, assumptions and judgments, in and
of themselves, could materially impact our financial statements. The following
are the accounting estimates that we believe are the most critical in nature.
Regulatory Accounting
Our accounting policies historically reflect the effects of the rate-making
process in accordance with Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation. Our regulated segment
continues to be cost-of-service rate regulated, and we believe the application
of Statement No. 71 to that segment continues to be appropriate. We must
reaffirm this conclusion at each balance sheet date. If, as a result of a change
in circumstances, it is determined that the regulated segment no longer meets
the criteria of regulatory accounting under Statement No. 71, that segment will
have to discontinue regulatory accounting and write-off the respective
regulatory assets and liabilities. Such a write-off could have a material impact
on our consolidated financial statements.
The application of Statement No. 71 results in recording regulatory assets
and liabilities. Regulatory assets represent the deferral of incurred costs that
are probable of future recovery in customer rates. In some cases, we record
regulatory assets before approval for recovery has been received from the
Kentucky Public Service Commission. We must use judgment to conclude that costs
deferred as regulatory assets are probable of future recovery. We base this
conclusion on certain factors, including changes in the regulatory environment,
recent rate orders issued by regulatory agencies and the status of any potential
new legislation. Regulatory liabilities represent revenues received from
customers to fund expected costs that have not yet been incurred or for probable
future refunds to customers.
We use our best judgment when recording regulatory assets and liabilities;
however, regulatory commissions can reach different conclusions about the
recovery of costs, and those conclusions could have a material impact on our
consolidated financial statements. We believe it is probable that we will
recover the regulatory assets that have been recorded.
Pension
Our reported costs of providing pension benefits (as described in Note 4(a)
of the Notes to Financial Statements) are dependent upon numerous factors
resulting from actual plan experience and assumptions of future experience.
Pension costs associated with our defined benefit pension plan, for
example, are impacted by employee demographics (including age, compensation
levels, and employment periods), the level of contributions we make to the plan
and earnings on plan assets. Changes made to the provisions of the plan may
impact current and future pension costs. Pension costs may also be significantly
affected by changes in key actuarial assumptions, including anticipated rates of
return on plan assets and the discount rates used in determining the projected
benefit obligation and pension costs.
In accordance with Statement of Financial Accounting Standards No. 87,
Employers' Accounting for Pensions, changes in pension obligations associated
with the above factors may not be immediately recognized as pension costs on the
income statement, but may be deferred and amortized in the future over the
average remaining service period of active plan participants in accordance with
Statement 87. For the years ended June 30, 2004, 2003 and 2002, we recorded
pension costs for our defined benefit pension plan of $725,000, $535,000 and
$428,000, respectively.
Effective April 1, 2002, our Board of Directors adopted a plan amendment
which enhanced the formula for benefits paid under the Company's Defined Benefit
Retirement Plan. In September, 2002, our Board of Directors approved an
amendment to the plan effective November 1, 2002. The plan amendment reduced the
formula for benefits paid under the plan for future service and restricted
participants from taking the benefits paid on service rendered subsequent to
November 1, 2002 in the form of lump-sum distributions from the plan.
Our pension plan assets are principally comprised of equity and fixed
income investments. Differences between actual portfolio returns and expected
returns may result in increased or decreased pension costs in future periods.
Likewise, changes in assumptions regarding current discount rates and expected
rates of return on plan assets could also increase or decrease recorded pension
costs.
In selecting our discount rate assumption we considered rates of return on
high-quality fixed-income investments that are expected to be available through
the maturity dates of the pension benefits. Our expected long-term rate of
return on pension plan assets is 8 percent and is based on our targeted asset
allocation assumption of approximately 60 percent equity investments and
approximately 40 percent fixed income investments. Our approximately 60 percent
equity investment target includes allocations to domestic, international, and
emerging markets managers. Our asset allocation is designed to achieve a
moderate level of overall portfolio risk in keeping with our desired risk
objective. We regularly review our asset allocation and periodically rebalance
our investments to our targeted allocation as appropriate.
We calculate the expected return on assets in our determination of pension
cost based on the market value of assets at the measurement date. Using the
market value recognizes investment gains or losses in the year in which they
occur.
Based on our assumed long-term rate of return of 8 percent, discount rate
of 6 percent, and various other assumptions, we estimate that our pension costs
associated with our defined benefits pension plan will decrease from $725,000 in
2004 to $556,000 in 2005. Modifying the expected long-term rate of return on our
pension plan assets by .25 percent would change pension costs for 2005 by
approximately $27,000. Modifying the discount rate assumption by .25 percent
would change 2005 pension costs by approximately $45,000.
Accumulated Provisions for Doubtful Accounts
We encounter risks associated with the collection of our accounts
receivable. As such, we record a monthly provision for accounts receivable that
are considered to be uncollectible. In order to calculate the appropriate
monthly provision, we primarily utilize the historical accounts receivable
write-off amounts. Quarterly, at a minimum, we review the reserve for
reasonableness based on the level of revenue and the aging of the receivable
balance. The underlying assumptions used for the allowance can change from
period to period and the allowance could potentially cause a material impact to
the income statement and working capital. The actual weather, commodity prices
and other internal and external economic conditions, such as the mix of the
customer base between residential, commercial and industrial, may vary
significantly from our assumptions and may impact operating income.
Asset Retirement Obligations
We adopted Statement of Financial Accounting Standards No. 143, Accounting
for Asset Retirement Obligations, during fiscal year 2003 and the primary impact
was to change the method of accruing for oil and gas well plugging and
abandonment costs. Statement No. 143 requires that the fair value of our
retirement obligations be recorded at the time the obligations are incurred.
Statement No. 143 does not require the recognition of asset retirement
obligations with indeterminate useful lives. Upon initial recognition of an
asset retirement obligation, we increase the carrying amount of the long-lived
asset by the same amount as the liability. Over time the liabilities are
accreted for the change in their present value, through charges to depreciation,
depletion and amortization, and the initial capitalized costs are depleted over
the useful lives of the related assets. We must use judgment to identify all
appropriate asset retirement obligations. The underlying assumptions used for
the value of the retirement obligation and related capitalized costs can change
from period to period. These assumptions include the estimated future retirement
costs, the estimated retirement date and the assumed credit-adjusted risk free
interest rate.
New Accounting Pronouncements
Significant management judgment is generally required during the process of
adopting new accounting pronouncements. See Note 2 of the Notes to Consolidated
Financial Statements for a discussion of these pronouncements.
Factors That May Affect Future Results
Management's Discussion and Analysis of Financial Condition and Results of
Operations and the other sections of this report contain forward-looking
statements that are not statements of historical facts. We have attempted to
identify these statements by using words such as "estimates", "attempts",
"expects", "monitors", "plans", "anticipates", "intends", "continues",
"believes", "seeks", "strives" and similar expressions.
These forward-looking statements include, but are not limited to,
statements about:
o our operational plans and strategies,
o the cost and availability of our natural gas supplies,
o our capital expenditures,
o sources and availability of funding for our operations and expansion,
o our anticipated growth and growth opportunities through system
expansion and acquisition,
o competitive conditions that we face,
o our production, storage, gathering and transportation activities,
o regulatory and legislative matters, and
o dividends
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical results
include the impact or outcome of:
o the ongoing restructuring of the natural gas industry and the
outcome of the regulatory proceedings related to that restructuring,
o the changing regulatory environment, generally,
o a change in the rights under present regulatory rules to recover for
costs of gas supply, other expenses and investments in
capital assets,
o uncertainty in our capital expenditure requirements,
o changes in economic conditions, demographic patterns and weather
conditions in our retail service areas,
o changes affecting our cost of providing gas service, including
changes in gas supply costs, cost and availability of
interstate pipeline capacity, interest rates, the availability of
external sources of financing for our operations, tax
laws, environmental laws and the general rate of inflation,
o changes affecting the cost of competing energy alternatives and
competing gas distributors, and
o changes in accounting principles and tax laws or the application of
such principles and laws to us.
Results of Operations
For meaningful analysis of our revenue and expense variations, the
variation amounts and percentages presented below for regulated and
non-regulated revenues and expenses include intersegment transactions. These
intersegment revenues and expenses whose variations are also disclosed in the
following tables, are eliminated in the consolidated statements of income.
Operating Revenues
In the following table we set forth variations in our revenues for the last
two fiscal years:
($000) 2004 compared 2003 compared
to to
2003 2002
------------ ------------
Increase (decrease) in our regulated
revenues
Gas rates 6,801 3,030
Weather normalization adjustment 690 (1,619)
Sales volumes (3,576) 5,685
On-system transportation (19) 47
Off-system transportation 544 340
Other 10 (3)
---------- ---------
Total 4,450 7,480
---------- ---------
Increase (decrease) in our non-regulated
revenues
Gas rates 4,349 4,519
Sales volumes 2,100 (1,106)
Other 31 7
----------- ---------
Total 6,480 3,420
Increase (decrease) in our intersegment
revenues (116) 1,610
----------- --------
Increase (decrease) in our
consolidated revenues 10,814 12,510
========== ==========
Percentage increase (decrease) in our
regulated volumes
Gas sales (7.8) 15.3
On-system transportation (2.5) 8.9
Off-system transportation 33.2 28.0
Percentage increase (decrease) in our non-
regulated gas sales volumes 10.2 (7.5)
Heating degree days billed were 96% of normal thirty year average
temperatures for fiscal 2004, as compared with 106% of normal temperatures for
2003 and 89% of normal for 2002. A "heating degree day" results from a day
during which the average of the high and low temperature is at least one degree
less than 65 degrees Fahrenheit.
The increase in operating revenues for 2004 of $10,814,000 was primarily
due to a 26.1% increase in gas costs reflected in higher sales prices and a
10.2% increase in non-regulated sales volumes due to increases in volumes
purchased by our off-system customers. These increases were offset by a 7.8%
decrease in regulated volumes due to the 8.6% warmer weather in the 2004 period.
The increase in operating revenues for 2003 of $12,510,000 was primarily
due to the 15.3% increase in our regulated volumes because of the significantly
colder weather in 2003, as well as the 23.7% increase in gas costs reflected in
higher sales prices. This increase, however, was offset to some extent because
unusually cold temperatures caused us to adjust our rates downward under our
authorized weather normalization tariff. The decrease in our non-regulated sales
volumes and our intersegment revenues is a result of the non-regulated segment
discontinuing the practice of selling gas to the regulated segment effective
January 1, 2002.
Operating Expenses
In the following table we set forth variations in our purchased gas expense
for the last two fiscal years:
($000) 2004 compared 2003 compared
to 2003 to 2002
------------- -------------
Increase (decrease) in our regulated
gas expense
Gas rates 6,423 3,068
Purchase volumes (2,071) 3,784
---------- ----------
Total 4,352 6,852
--------- ----------
Increase (decrease) in our non-regulated
gas expense
Gas rates 5,070 3,273
Purchase volumes 1,559 (922)
Transportation expense 116 81
--------- ------------
Total 6,745 2,432
-------- ----------
Decrease (increase) in our intersegment
gas expense (116) 1,610
--------- ----------
Increase in our consolidated gas expense 10,981 10,894
======= =========
Natural gas prices are determined in an unregulated national market.
Therefore, the price that we pay for natural gas fluctuates with national supply
and demand.
The increase in purchased gas expense for 2004 of $10,981,000 was primarily
due to a 26.1% increase in gas costs because of higher prices and a 10.2%
increase in non-regulated sales volumes offset by a 7.8% decrease in regulated
volumes sold.
The increase in purchased gas expense for 2003 of $10,894,000 was due
primarily to the 23.7% increase in the cost of gas purchased for regulated sales
and the 15.3% increase in regulated volumes sold.
The increase in operation and maintenance expense of $972,000 for the year
ended June 30, 2003 was primarily due to an increase in bad debt expense
resulting from higher gas prices and colder winter weather, as well as an
increase in employee benefit costs.
The increase in taxes other than income taxes for the year ended June 30,
2003 of $155,000 was primarily due to increased property taxes.
The decrease in other interest for 2004 of $260,000 is a result of lower
short-term borrowings.
Basic and Diluted Earnings Per Common Share
For the fiscal years ended June 30, 2004, 2003 and 2002, our basic earnings
per common share changed as a result of changes in net income and an increase in
the number of our common shares outstanding. We increased our number of common
shares outstanding as a result of shares issued through our Dividend
Reinvestment and Stock Purchase Plan, our Employee Stock Purchase Plan and our
May, 2003 common stock offering of 600,000 shares.
We have no potentially dilutive securities. As a result, our basic earnings
per common share and our diluted earnings per common share are the same.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We purchase our gas supply through a combination of spot market gas
purchases and forward gas purchases. The price of spot market gas is based on
the market price at the time of delivery. The price we pay for our natural gas
supply acquired under our forward gas purchase contracts, however, is fixed
prior to the delivery of the gas. Additionally, we inject some of our gas
purchases into gas storage facilities in the non-heating months and withdraw
this gas from storage for delivery to customers during the heating season. We
have minimal price risk resulting from these forward gas purchase and storage
arrangements, because we are permitted to pass these gas costs on to our
regulated customers through the gas cost recovery rate mechanism.
Price risk for the non-regulated business is mitigated by efforts to
balance supply and demand. However, there are greater risks in the non-regulated
segment because of the practical limitations on the ability to perfectly predict
demand. In addition, we are exposed to price risk resulting from changes in the
market price of gas on uncommitted gas volumes of our non-regulated companies.
None of our gas contracts are accounted for using the fair value method of
accounting. While some of our gas purchase contracts meet the definition of a
derivative, we have designated these contracts as "normal purchases" under
Statement of Financial Accounting Standards No. 133, entitled Accounting for
Derivative Instruments and Hedging Activities.
We are exposed to risk resulting from changes in interest rates on our
variable rate notes payable. The interest rate on our current short-term line of
credit with Branch Banking and Trust Company is benchmarked to the monthly
London Interbank Offered Rate. The balance on our short-term line of credit was
$4,738,000 and $1,031,000 on June 30, 2004 and 2003, respectively. Based on the
amount of our outstanding short-term line of credit on June 30, 2004 and 2003, a
one percent (one hundred basis point) increase in our average interest rate
would result in a decrease in our annual pre-tax net income of $47,000 and
$10,000, respectively.
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE PAGE
Management's Statement of Responsibility for Financial Reporting
and Accounting 27
Report of Independent Registered Public Accounting Firm 28
Consolidated Statements of Income for the years ended June 30,
2004, 2003, and 2002 29
Consolidated Statements of Cash Flows for the years ended
June 30, 2004, 2003 and 2002 30
Consolidated Balance Sheets as of June 30, 2004 and 2003 32
Consolidated Statements of Changes in Shareholders' Equity
for the years ended June 30, 2004, 2003 and 2002 34
Consolidated Statements of Capitalization as of June 30,
2004 and 2003 36
Notes to Consolidated Financial Statements 37
Schedule II - Valuation and Qualifying Accounts for the years
ended June 30, 2004, 2003 and 2002 49
Schedules other than those listed above are omitted because they are not
required, not applicable or the required information is shown in the financial
statements or notes thereto.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure controls and procedures are our controls and other procedures
that are designed to provide reasonable assurance that information required to
be disclosed by us in the reports that we file or submit under the Securities
Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized, and
reported within the time periods specified in the Securities and Exchange
Commission's ("SEC") rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to provide
reasonable assurance that information required to be disclosed by us in the
reports that we file under the Exchange Act is accumulated and communicated to
our management, including our chief executive officer and chief financial
officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, we have
evaluated the effectiveness of our disclosure controls and procedures as of June
30, 2004, and, based upon this evaluation, our Chief Executive Officer and Chief
Financial Officer have concluded that these controls and procedures are
effective in providing reasonable assurance that information requiring
disclosure is recorded, processed, summarized, and reported within the timeframe
specified by the SEC's rules and forms.
Under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, we have
evaluated any change in our internal control over financial reporting (as such
term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during
the fiscal quarter ended June 30, 2004 and found no change that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Code of Conduct
We have adopted our Business Code of Conduct and Ethics, which is a code of
ethics that applies to our Chief Executive Officer, Chief Financial Officer, and
Controller. Our Code of Ethics may be viewed on our website at www.deltagas.com.
Any amendment to or waiver of the application of our Code of Ethics will be
promptly disclosed on our website at www.deltagas.com.
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions
Item 14. Principal Accountant Fees and Services
Registrant intends to file a definitive proxy statement with the Commission
pursuant to Regulation 14A (17 CFR 240.14a) not later than 120 days after the
close of the fiscal year. In accordance with General Instruction G(3) to Form
10-K, the information called for by Items 10, 11, 12, 13 and 14 is incorporated
herein by reference to the definitive proxy statement. Neither the report on
Executive Compensation nor the performance graph included in the Company's
definitive proxy statement shall be deemed incorporated herein by reference.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) - Financial Statements, Schedules and Exhibits
(1) - Financial Statements See Index at Item 8
(2) - Financial Statement Schedules
See Index at Item 8
(3) - Exhibits
Exhibit No.
3(i) Registrant's Amended and Restated Articles of Incorporation are
incorporated herein by reference to Exhibit 4(a) to Delta's Registration
Statement on Form S-2 (Reg. No. 333-0431) dated April 4, 2003.
3(ii)Registrant's Amended and Restated By-Laws (dated November 21, 2002) are
incorporated herein by reference to Exhibit 3(a) to Registrant's Form 10-Q
(File No. 000-08788) for the period ended December 31, 2002.
4(a) The Indenture dated September 1, 1993 in respect of 6 5/8% Debentures due
October 1, 2023, is incorporated herein by reference to Exhibit 4(e) to
Delta's Form S-2 (Reg. No. 33-68274) dated September 2, 1993.
4(b) The Indenture dated March 1, 1998 in respect of 7.15% Debentures due April
1, 2018, is incorporated herein by reference to Exhibit 4(d) to Delta's
Form S-2 (Reg. No. 333-47791) dated March 11, 1998.
4(c) The Indenture dated January 1, 2003 in respect of 7% Debentures due
February 1, 2023, is incorporated herein by reference to Exhibit 4(d) to
Delta's Form S-2 (Reg. 333-100852) dated October 30, 2002.
10(a)Employment agreements between Registrant and five officers, those being
John B. Brown, Johnny L. Caudill, John F. Hall, Alan L. Heath and Glenn R.
Jennings, are incorporated herein by reference to Exhibit 10(k) to
Registrant's Form 10-Q (File No. 000-08788) for the period ended March 31,
2000.
10(b)Gas Sales Agreement, dated May 1, 2000, by and between the Registrant and
Woodward Marketing, L.L.C. is incorporated herein by reference to Exhibit
10(d) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7,
2003.
10(c)Gas Sales Agreement, dated May 1, 2003, by and between the Registrant and
Woodward Marketing, LLC is incorporated herein by reference to Exhibit
10(c) to Registrant's Form 10-K (Reg. No. 000-08788) dated September 5,
2003.
10(d)Gas Transportation Agreement (Service Package 9069), dated December 19,
1994, by and between Tennessee Gas Pipeline Company and Registrant is
incorporated herein by reference to Exhibit 10(e) to Registrant's Form S-2
(Reg. No. 333-100852) dated February 7, 2003.
10(e)GTS Service Agreement (Service Agreement No. 37815), dated November 1,
1993, by and between Columbia Gas Transmission Corporation and Registrant
is incorporated herein by reference to Exhibit 10(f) to Registrant's Form
S-2 (Reg. No. 333-100852) dated February 7, 2003.
10(f)FTS1 Service Agreement (Service Agreement No. 4328), dated October 4,
1994, by and between Columbia Gulf Transmission Company and Registrant is
incorporated herein by reference to Exhibit 10(g) to Registrant's Form S-2
(Reg. No. 333-100852) dated February 7, 2003.
10(g)Loan Agreement, dated October 31, 2002, by and between Branch Banking and
Trust Company and Registrant is incorporated herein by reference to Exhibit
10(i) to Registrant's Form S-2 (Reg. No. 333-100852) dated February 7,
2003. 10(h) Promissory Note, in the original principal amount of
$40,000,000, made by Registrant to the order of Branch Banking and Trust
Company, is incorporated herein by reference to Exhibit 10(a) to
Registrant's Form 10-Q (File No. 000-08788) for the period ended September
30, 2002.
10(i)Gas Storage Lease, dated October 4, 1995, by and between Judy L. Fuson,
Guardian of Jamie Nicole Fuson, a minor, and Lonnie D. Ferrin and
Assignment and Assumption Agreement, dated November 10, 1995, by and
between Lonnie D. Ferrin and Registrant is incorporated herein by reference
to Exhibit 10(j) to Registrant's Form S-2 (Reg. No. 333-104301) dated April
4, 2003.
10(j)Gas Storage Lease, dated November 6, 1995, by and between Thomas J.
Carnes, individually and as Attorney-in-fact and Trustee for the
individuals named therein, and Registrant, is incorporated herein by
reference to Exhibit 10(k) to Registrant's Form S-2 (Reg. No. 333-104301)
dated April 4, 2003.
10(k)Deed and Perpetual Gas Storage Easement, dated December 21, 1995, by and
between Katherine M. Cornelius, William Cornelius, Frances Carolyn
Fitzpatrick, Isabelle Fitzpatrick Smith and Kenneth W. Smith and Registrant
is incorporated herein by reference to Exhibit 10(l) to Registrant's Form
S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(l)Underground Gas Storage Lease and Agreement, dated March 9, 1994, by and
between Equitable Resources Exploration, a division of Equitable Resources
Energy Company, and Lonnie D. Ferrin and Amendment No. 1 and Novation to
Underground Gas Storage Lease and Agreement, dated March 22, 1995, by and
between Equitable Resources Exploration, Lonnie D. Ferrin and Registrant,
is incorporated herein by reference to Exhibit 10(m) to Registrant's Form
S-2 (Reg. No. 333-104301) dated April 4, 2003.
10(m)Base Contract for Short-Term Sale and Purchase of Natural Gas, dated
January 1, 2002, by and between M & B Gas Services, Inc. and Registrant, is
incorporated herein by reference to Exhibit 10(n) to Registrant's Form S-2
(Reg. No. 333-104301) dated April 4, 2003.
10(n)Oil and Gas Lease, dated July 19, 1995, by and between Meredith J. Evans
and Helen Evans and Paddock Oil and Gas, Inc.; Assignment, dated June 15,
1995, by Paddock Oil and Gas, Inc., as assignor, to Lonnie D. Ferrin, as
assignee; Assignment, dated August 31, 1995, by Paddock Oil and Gas, Inc.,
as assignor, to Lonnie D. Ferrin, as assignee; and Assignment and
Assumption Agreement, dated November 10, 1995, by and between Lonnie D.
Ferrin and Registrant, is incorporated herein by reference to Exhibit 10(o)
to Registrant's Form S-2 (Reg. No. 333-104301) dated April 4, 2003.
12 Computation of the Consolidated Ratio of Earnings to Fixed Charges.
21 Subsidiaries of the Registrant.
23 Consent of Independent Registered Public Accounting Firm.
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act.
31.2 Certification of the Principal Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act.
32.1 Written statement of the Chief Executive Officer, pursuant to 18 U.S.C.
Section 1350.
32.2 Written statement of the Principal Financial Officer, pursuant to 18 U.S.C.
Section 1350.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 3rd day of
September, 2004.
DELTA NATURAL GAS COMPANY, INC.
By: /s/Glenn R. Jennings
-------------------------------
Glenn R. Jennings, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
(i) Principal Executive Officer:
/s/Glenn R. Jennings President, Chief Executive September 3, 2004
- -------------------------------- Officer and Vice Chairman
(Glenn R. Jennings) of the Board
(ii) Principal Financial Officer:
/s/John F. Hall Vice-President - Finance, September 3, 2004
- -------------------------------- Secretary and Treasurer
(John F. Hall)
(iii) Principal Accounting Officer:
/s/John B. Brown Controller September 3, 2004
- --------------------------------
(John B. Brown)
(iv) A Majority of the Board of Directors:
/s/H. D. Peet Chairman of the Board September 3, 2004
- ---------------------------------
(H. D. Peet)
/s/Donald R. Crowe Director September 3, 2004
- ---------------------------------
(Donald R. Crowe)
/s/Jane Hylton Green Director September 3, 2004
- ---------------------------------
(Jane Hylton Green)
/s/Lanny D. Greer Director September 3, 2004
- ---------------------------------
(Lanny D. Greer)
/s/Billy Joe Hall Director September 3, 2004
- --------------------------------
(Billy Joe Hall)
/s/Michael J. Kistner Director September 3, 2004
- --------------------------------
(Michael J. Kistner)
/s/Lewis N. Melton Director September 3, 2004
- --------------------------------
(Lewis N. Melton)
/s/Arthur E. Walker, Jr. Director September 3, 2004
- --------------------------------
(Arthur E. Walker, Jr.)
/s/Michael R. Whitley Director September 3, 2004
- --------------------------------
(Michael R. Whitley)
Management's Statement of Responsibility for Financial Reporting and Accounting
Management is responsible for the preparation, presentation and integrity
of the financial statements and other financial information in this report. In
preparing financial statements in conformity with accounting principles
generally accepted in the United States, management is required to make
estimates and assumptions that affect the reported amount of assets,
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities at the date of the financial statements and during the reporting
period. Actual results could differ from these estimates.
The Company maintains a system of accounting and internal controls which
management believes provides reasonable assurance that the accounting records
are reliable for purposes of preparing financial statements and that the assets
are properly accounted for and protected.
The Board of Directors pursues its oversight role for these financial
statements through its Audit Committee, which consists of four outside
directors. The Audit Committee meets periodically with management to review the
work and monitor the discharge of their responsibilities. The Audit Committee
also meets periodically with the Company's internal auditor as well as
representatives of Deloitte & Touche LLP, the Company's independent registered
public accounting firm, who have full and free access to the Audit Committee,
with or without management present, to discuss internal accounting control,
auditing and financial reporting matters.
Glenn R. Jennings John F. Hall John B. Brown
President and Chief Vice President - Finance, Controller
Executive Officer Secretary and Treasurer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Delta Natural Gas Company, Inc.:
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Delta Natural Gas Company and subsidiaries (the "Company") as
of June 30, 2004 and 2003, and the related consolidated statements of income,
cash flows and changes in shareholders' equity for the three years in the period
ended June 30, 2004. Our audit also included the financial statement schedule
included in Item 15a(2) of this Annual Report. These financial statements and
financial statement schedule are the responsibility of the Company's management.
Our responsibility is to express an opinion on the financial statements and
financial statement schedule based on our audits.
We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company as of June 30, 2004 and
2003, and the results of its operations and its cash flows for each of the three
years in the period ended June 30, 2004, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion the financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
As discussed in Note 2 to the financial statements, in 2003 the Company adopted
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations".
DELOITTE & TOUCHE LLP
Cincinnati, Ohio
August 13, 2004
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Income
For the Years Ended June 30, 2004 2003 2002
---- ----- ----
Operating Revenues $ 79,193,614 $ 68,380,263 $ 55,870,219
------------ ------------ ------------
Operating Expenses
Purchased gas $ 51,972,671 $ 40,991,670 $ 30,097,664
Operation and maintenance 10,665,340 10,657,552 9,685,746
Depreciation and depletion 4,432,151 4,281,207 4,080,944
Taxes other than income
taxes 1,590,548 1,510,111 1,354,913
Income tax expense (Note 3) 2,359,600 2,413,357 2,249,500
------------ -------------- --------------
Total operating expenses $ 71,020,310 $ 59,853,897 $ 47,468,767
------------ ------------ ------------
Operating Income $ 8,173,304 $ 8,526,366 $ 8,401,452
------------ ------------- -------------
Other Income and Deductions, Net $ 60,532 $ 47,641 $ 17,018
Interest Charges
Interest on long-term debt 3,835,797 3,858,082 3,728,847
Other interest 323,191 582,955 891,750
Amortization of debt expense 236,789 193,993 161,160
------------ -------------- ------------
Total interest charges $ 4,395,777 $ 4,635,030 $ 4,781,757
------------ -------------- ------------
Income Before Cumulative Effect of
a Change in Accounting Principle $ 3,838,059 $ 3,938,977 $ 3,636,713
Cumulative Effect of a Change in
Accounting Principle, net of income
taxes of $55,000 (Note 2) -- (88,370) --
------------ -------------- ------------
Net Income $ 3,838,059 $ 3,850,607 $ 3,636,713
============ ============== ============
Basic and Diluted Earnings Per Common
Share Before Cumulative Effect of a
Change In Accounting Principle $ 1.20 $ 1.49 $ 1.45
Cumulative Effect of a Change in
Accounting Principle
-- (.03) --
------------- -------------- -------------
Basic and Diluted Earnings Per
Common Share $ 1.20 $ 1.46 $ 1.45
============ ============= =============
Weighted Average Number of Common Shares
Outstanding (Basic and Diluted) 3,185,158 2,641,829 2,513,804
Dividends Declared Per Common Share $ 1.18 $ 1.18 $ 1.16
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended June 30, 2004 2003 2002
---- ---- ----
Cash Flows From Operating Activities
Net income $ 3,838,059 $ 3,850,607 $ 3,636,713
Adjustments to reconcile net income to net
cash from operating activities
Cumulative effect of a change in accounting -- 88,370 --
principle
Depreciation, depletion and amortization 4,658,413 4,461,812 4,354,396
Deferred income taxes and investment
tax credits 1,905,680 1,991,258 1,110,916
Other - net 681,910 675,807 595,894
(Increase) decrease in assets
Accounts receivable (204,603) (1,682,752) 1,767,741
Gas in storage (2,615,968) 189,870 (556,871)
Deferred gas cost 2,768,192 (215,765) 368,648
Materials and supplies 199,717 (28,723) 69,663
Prepayments (723,669) (78,355) 681,195
Other assets (142,794) (235,549) (89,615)
Increase (decrease) in liabilities
Accounts payable (3,272,634) 6,178,302 (1,197,677)
Accrued taxes 230,713 178,207 (44,503)
Other current liabilities (60,720) (244,388) 163,936
Other liabilities 13,727 57,368 (22,001)
--------------- --------------- ---------------
Net cash provided by operating activities $ 7,276,023 $15,186,069 $ 10,838,435
------------ ----------- ------------
Cash Flows From Investing Activities
Capital expenditures $ (8,959,153) $ (8,839,091) $ (9,748,304)
------------- ------------ ------------
Net cash used in investing activities $ (8,959,153) $ (8,839,091) $ (9,748,304)
------------- ------------ ------------
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Cash Flows (continued)
For the Years Ended June 30, 2004 2003 2002
---- ---- ----
Cash Flows From Financing Activities
Dividends on common stock $ (3,758,748) $ (3,185,900) $ (2,916,418)
Issuance of common stock, net 807,617 13,096,249 707,422
Issuance of long-term debt -- 20,000,000 --
Long-term debt issuance expense -- (819,408) --
Repayment of long-term debt (324,000) (15,919,240) (1,375,000)
Issuance of notes payable 57,805,684 84,556,011 36,860,000
Repayment of notes payable (54,098,603) (102,879,912) (34,305,000)
--------------- ------------ ------------
Net cash provided by (used in)
financing activities $ 431,950 $ (5,152,200) $ (1,028,996)
-------------- -------------- -------------
Net Increase (Decrease) in Cash and
Cash Equivalents $ (1,251,180) $ 1,194,778 $ 61,135
Cash and Cash Equivalents,
Beginning of Year $ 1,420,014 225,236 164,101
------------- --------------- ---------------
Cash and Cash Equivalents,
End of Year $ 168,834 $ 1,420,014 $ 225,236
============== ============== ==============
Supplemental Disclosures of Cash
Flow Information
Cash paid during the year for
Interest $ 4,160,291 $ 4,701,320 $ 4,636,051
Income taxes (net of refunds) $ 804,035 $ 355,308 $ 1,130,566
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets
As of June 30, 2004 2003
---- ----
Assets
Gas Utility Plant, at cost $170,337,427 $163,745,044
Less - Accumulated provision for depreciation (55,121,511) (51,670,448)
------------- ------------
Net gas plant $115,215,916 $112,074,596
------------ ------------
Current Assets
Cash and cash equivalents $ 168,834 $ 1,420,014
Accounts receivable, less accumulated provision for
doubtful accounts of $300,000 and $350,000 in
2004 and 2003, respectively 4,771,380 4,566,777
Gas in storage, at average cost 7,749,089 5,090,440
Deferred gas costs 1,523,632 4,291,824
Materials and supplies, at first-in, first-out cost 352,762 552,479
Prepayments 1,190,818 467,149
------------- ----------------
Total current assets $ 15,756,515 $ 16,388,683
------------- -------------
Other Assets
Cash surrender value of officers' life
insurance (face amount of $1,236,009) $ 376,930 $ 356,137
Note receivable from officer 110,000 134,000
Prepaid pension cost (Note 4) 2,694,151 --
Unamortized debt expense
and other (Notes 4 and 8) 4,218,617 4,333,900
------------- ---------------
Total other assets $ 7,399,698 $ 4,824,037
------------ --------------
Total assets $138,372,129 $ 133,287,316
============ ==============
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Balance Sheets (continued)
As of June 30, 2004 2003
---- ----
Liabilities and Shareholders' Equity
Capitalization (See Consolidated Statements
of Capitalization)
Common shareholders' equity
Common shares ($1.00 par value) $ 3,200,715 $ 3,166,940
Premium on common shares 44,236,128 43,462,433
Capital stock expense (2,597,999) (2,598,146)
Accumulated other comprehensive loss -- (2,050,636)
Retained earnings 3,991,317 3,912,006
--------------- ---------------
Total common shareholders' equity $ 48,830,161 $ 45,892,597
Long-term debt (Notes 8 and 9) 53,049,000 53,373,000
-------------- --------------
Total capitalization $ 101,879,161 $ 99,265,597
------------- -------------
Current Liabilities
Notes payable (Note 7) $ 4,738,180 $ 1,031,099
Current portion of long-term debt (Notes 8 and 9) 1,650,000 1,650,000
Accounts payable 6,609,787 10,624,087
Accrued taxes 1,027,937 797,224
Customers' deposits 433,809 442,315
Accrued interest on debt 901,370 902,673
Accrued vacation 624,604 576,388
Other accrued liabilities 488,031 587,158
---------------- ----------------
Total current liabilities $ 16,473,718 $ 16,610,944
------------- -------------
Deferred Credits and Other
Deferred income taxes $ 17,967,611 $ 14,620,631
Investment tax credits 326,200 364,600
Regulatory liabilities (Note 1) 1,431,600 1,428,652
Pension liability (Note 4) -- 716,780
Advances for construction and other 293,839 280,112
--------------- ----------------
Total deferred credits and other $ 20,019,250 $ 17,410,775
------------- -------------
Commitments and Contingencies (Note 11)
Total liabilities and shareholders' equity $138,372,129 $133,287,316
============ ============
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Changes in
Shareholders' Equity
For the Years Ended June 30, 2004 2003 2002
---- ---- ----
Common Shares
Balance, beginning of year $ 3,166,940 $ 2,530,079 $ 2,495,679
Common stock offering, $1.00 par value
of 600,000 shares issued in 2003 -- 600,000 --
Dividend reinvestment and stock
purchase plan, $1.00 par value of 29,129,
30,821 and 28,506 shares issued in 2004,
2003 and 2002, respectively 29,129 30,821 28,506
Issued to directors, $1.00 par value of 900
and 800 shares in 2003 and 2002, -- 900 800
respectively
Employee stock purchase plan and
other, $1.00 par value of 4,646, 5,140
and 5,094 shares issued in 2004, 2003 and
2002, respectively 4,646 5,140 5,094
----------------- ---------------- ---------------
Balance, end of year $ 3,200,715 $ 3,166,940 $ 2,530,079
============= ============== ==============
Premium on Common Shares
Balance, beginning of year $ 43,462,433 $ 30,330,330 $ 29,657,308
Premium on issuance of common shares
Common stock offering -- 12,360,000 --
Dividend reinvestment and stock
purchase plan 670,243 644,906 561,547
Issued to directors -- 19,638 16,712
Employee stock purchase plan and
other 103,452 107,559 94,763
--------------- ---------------- -----------------
Balance, end of year $ 44,236,128 $ 43,462,433 $ 30,330,330
============ ============= ==============
Capital Stock Expense
Balance, beginning of year $ (2,598,146) $ (1,925,431) $ (1,925,431)
Common stock offering 147 (672,715) --
--------------- -------------- --------------
Balance, end of year $ (2,597,999) $ (2,598,146) $ (1,925,431)
============= ============== ==============
Accumulated Other Comprehensive
Income (Loss)
Balance, beginning of year $ (2,050,636) $ -- $ --
Minimum pension liability adjustment,
net of tax benefit of $1,335,800 (Note 4) 2,050,636 (2,050,636) --
-------------- --------------- ---------------
Balance, end of year $ -- $ (2,050,636) $ --
================== ============== ===============
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary
Companies
Consolidated Statements of Changes in
Shareholders' Equity (continued)
For the Years Ended June 30, 2004 2003 2002
---- ---- ----
Retained Earnings
Balance, beginning of year $ 3,912,006 $ 3,247,299 $ 2,527,004
Net income 3,838,059 3,850,607 3,636,713
Cash dividends declared on common
shares (See Consolidated
Statements of Income for rates) (3,758,748) (3,185,900) (2,916,418)
--------------- -------------- --------------
Balance, end of year $ 3,991,317 $ 3,912,006 $ 3,247,299
============= ============== =============
Common Shareholders' Equity
Balance, beginning of year $ 45,892,597 $ 34,182,277 $ 32,754,560
------------ ------------- ------------
Comprehensive income
Net income $ 3,838,059 $ 3,850,607 $ 3,636,713
Other comprehensive income (loss) 2,050,636 (2,050,636) --
-------------- --------------- -------------
Comprehensive income $ 5,888,695 $ 1,799,971 $ 3,636,713
Issuance of common stock 807,617 13,096,249 707,422
Dividends on common stock (3,758,748) (3,185,900) (2,916,418)
------------- -------------- ------------
Balance, end of year $ 48,830,161 $ 45,892,597 $ 34,182,277
============ ============= ============
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Capitalization
As of June 30, 2004 2003
---- ----
Common Shareholders' Equity
Common shares, par value $1.00 per share
(Notes 4 and 5)
Authorized 6,000,000 shares
Issued and outstanding 3,200,715 and
3,166,940 shares in 2004 and 2003,
respectively $ 3,200,715 $ 3,166,940
Premium on common shares 44,236,128 43,462,433
Capital stock expense (2,597,999) (2,598,146)
Accumulated other comprehensive loss -- (2,050,636)
Retained earnings (Note 8) 3,991,317 3,912,006
-------------- --------------
Total common shareholders' equity $ 48,830,161 $ 45,892,597
------------- ------------
Long-Term Debt (Notes 8 and 9)
Debentures, 6 5/8%, due 2023 $ 10,872,000 $ 11,051,000
Debentures, 7.0%, due 2023 20,000,000 20,000,000
Debentures, 7.15%, due 2018 23,827,000 23,972,000
-------------- -------------
Total debt $ 54,699,000 $ 55,023,000
Less amounts due within one year,
included in current liabilities (1,650,000) (1,650,000)
--------------- --------------
Total long-term debt $ 53,049,000 $ 53,373,000
------------- -------------
Total capitalization $101,879,161 $ 99,265,597
============ =============
The accompanying notes to consolidated financial statements are an integral part
of these statements.
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
(a) Principles of Consolidation Delta Natural Gas Company, Inc. ("Delta" or
"the Company") sells natural gas to approximately 40,000 customers on our
distribution system in central and southeastern Kentucky. 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 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. Certain reclassifications have been made to prior-period amounts to
conform to the 2004 presentation.
(b) Cash Equivalents For the purposes of the Consolidated Statements of
Cash Flows, all temporary cash investments with a maturity of three months or
less at the date of purchase are considered cash equivalents.
(c) 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 2.8%, 2.9% and 2.9% of
average depreciable plant for 2004, 2003 and 2002, respectively.
(d) Maintenance All expenditures for maintenance and repairs of units of
property are charged to the appropriate maintenance expense accounts in the
month incurred. A betterment or replacement of a unit of property is accounted
for as an addition and retirement of utility plant. At the time of such a
retirement, the accumulated provision for depreciation is charged with the
original cost of the property retired.
(e) Gas Cost Recovery We have a Gas Cost Recovery ("GCR") clause 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 approved by the Kentucky Public Service Commission. We expense gas
costs based on the amount of gas costs recovered through revenue. Any
differences between actual gas costs and those estimated costs billed are
deferred and reflected in the computation of future billings to customers using
the GCR mechanism.
(f) Revenue Recognition We record revenues as billed to our customers on a
monthly meter reading cycle. At the end of each month, gas service which has
been rendered from the latest date of each cycle meter reading to the month-end
is unbilled. Revenue is shown net of excise taxes collected from customers.
(g) Revenues and Customer Receivables We serve 40,000 customers in central
and southeastern Kentucky. Revenues and customer receivables arise primarily
from sales of natural gas to customers and from transportation services for
others. Provisions for doubtful accounts are recorded to reflect the expected
net realizable value of accounts receivable.
(h) 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.
(i) Rate Regulated Basis of Accounting Our regulated operations follow the
accounting and reporting requirements of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation". 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 in the
consolidated balance sheet (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:
Regulatory assets ($000) 2004 2003
---- ----
Deferred gas cost 1,524 4,292
Loss on extinguishment of debt 2,257 2,386
Rate case and gas audit expense 152 --
--------- ---------
Total regulatory assets 3,933 6,678
======= =======
Regulatory liabilities ($000)
Accrued cost of removal on long-lived assets 784 715
Regulatory liability for deferred income taxes 648 714
------- -------
1,432 1,429
===== =====
We are currently earning a return on loss on extinguishment of debt and
rate case expenses. Deferred gas costs are presented every three months to the
Kentucky Public Service Commission for recovery in accordance with the gas cost
recovery rate mechanism.
(j) 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. Until the assets are disposed of, their estimated fair value is
re-evaluated when circumstances or events change. In the opinion of management,
our long-lived assets are appropriately valued in the accompanying financial
statements.
(2) New Accounting Pronouncements
In June, 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, entitled Accounting for Asset Retirement
Obligations, and Delta adopted this statement effective July 1, 2002. Statement
No. 143 addresses financial accounting for legal obligations associated with the
retirement of long-lived assets. Upon adoption of this statement, as of July,
2002, we recorded $178,000 of asset retirement obligations in the balance sheet
primarily representing the current estimated fair value of our obligation to
plug oil and gas wells at the time of abandonment. Of this amount, $47,000 was
recorded as incremental cost of the underlying property, plant and equipment.
The cumulative effect on earnings of adopting this new statement was a charge to
earnings of $88,000 (net of income taxes of $55,000), representing the
cumulative amounts of depreciation and depletion expenses and changes in the
asset retirement obligation due to the passage of time for historical accounting
periods. The adoption of the new standard did not have a significant impact on
income before cumulative effect of a change in accounting principle for the
years ended June 30, 2004 and 2003. Pro forma net income and earnings per share
have not been presented for the year ended June 30, 2002 because the pro forma
application of Statement No. 143 to prior periods would result in pro forma net
income and earnings per share not materially different from the actual amounts
reported for those periods in the accompanying consolidated statements of
income. We also have asset retirement obligations which have indeterminate
settlement dates. These obligations, which relate to our gas wells and oil lines
at our storage facility and compressor station sites, are not recorded until an
estimated range of potential settlement dates is known, according to Statement
No. 143. In accordance with established regulatory practices, we accrue costs of
removal on long-lived assets through depreciation expense if we believe removal
of the assets at the end of their useful life is likely even though such costs
do not represent legal obligations, under Statement No. 143. In accordance with
the provisions of Statement of Financial Accounting Standards No. 71, entitled
Accounting for the Effects of Certain Types of Regulation, we have recorded
approximately $784,000 and $714,000 of such accrued cost of removal as
regulatory liabilities on the accompanying balance sheets as of June 30, 2004
and 2003, respectively.
In January, 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, entitled Consolidation of Variable Interest Entities,
which significantly changed the consolidation requirements for special purpose
entities and other entities subject to its scope. We have no relationships with
variable interest entities as defined by Interpretation No. 46; therefore,
adoption of this Interpretation on December 31, 2003 had no impact on our
financial position and results of operations.
In May, 2003, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 150, entitled Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity.
Statement No. 150 was developed in response to concerns relating to
classification in the consolidated balance sheet of certain financial
instruments that have characteristics of both liabilities and equity. Statement
No. 150 was effective July 1, 2003. There was no impact of implementation on our
financial position and results of operations.
In December, 2003, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 132 (Revised 2003), entitled
Employers' Disclosure about Pensions and Other Postretirement Benefits. This
Statement revises employers' disclosures about pension plans and other
post-retirement benefit plans to present more information about the economic
resources and obligations of such plans and also require certain disclosures in
the financial statements for interim periods. We adopted the revised Statement
No. 132 effective January 1, 2004. Since the Statement only addressed disclosure
requirements, there was no impact of implementation on our financial position
and results of operations. See Note 4(a) for the revised disclosures.
(3) 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 cost 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 are 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 temporary differences which gave rise
to the net accumulated deferred income tax liability for the periods are as
follows:
2004 2003
---- ----
Deferred Tax Liabilities
Accelerated depreciation $ 17,646,300 $ 14,841,007
Deferred gas cost 601,000 1,692,900
Pension 1,365,400 900
Debt issuance expense 780,400 582,800
Other 279,900 --
--------------- ------------------
Total $ 20,673,000 $ 17,117,607
------------ ------------
Deferred Tax Assets
Alternative minimum tax credits $ 1,601,789 $ 1,408,945
Regulatory liabilities 255,600 282,100
Investment tax credits 128,700 143,800
Other 719,300 662,131
--------------- ---------------
Total $ 2,705,389 $ 2,496,976
------------- -------------
Net accumulated deferred
income tax liability $ 17,967,611 $ 14,620,631
============ ============
The components of the income tax provision are comprised of the following for
the years ended June 30:
2004 2003 2002
---- ---- ----
Components of Income Tax Expense
Current
Federal $ (14,100) $ 258,700 $ 776,200
State 484,900 64,200 296,100
------------- -------------- -------------
Total $ 470,800 $ 322,900 $ 1,072,300
Deferred 1,873,700 2,074,657 1,159,400
Deferred investment tax credits 15,100 15,800 17,800
-------------- -------------- --------------
Income tax expense $ 2,359,600 $ 2,413,357 $ 2,249,500
=========== =========== ===========
Reconciliation of the statutory federal income tax rate to the effective
income tax rate is shown in the table below:
2004 2003 2002
---- ---- ----
Statutory federal income tax rate 34.0% 34.0% 34.0 %
State income taxes, net of federal benefit 5.3 5.2 5.3
Amortization of investment tax credits (0.6) (0.6) (0.8)
Other differences, net (0.3) (0.3) (0.2)
-------- -------- -------
Effective income tax rate 38.4% 38.3% 38.3 %
======= ======= =======
(4) Employee Benefit Plans
(a) Defined Benefit Retirement Plan We have a trusteed, noncontributory,
defined benefit pension plan covering all eligible employees. Retirement income
is based on the number of years of service and annual rates of compensation. The
Company makes annual contributions equal to the amounts necessary to fund the
plan adequately.
Effective April 1, 2002, our Board of Directors adopted a plan amendment
which enhanced the formula for benefits paid under our Company's Defined Benefit
Retirement Plan. In September, 2002, our Board of Directors approved an
amendment to the Plan effective November 1, 2002. The plan amendment reduced the
formula for benefits paid under the plan for future service and restricted
participants from taking lump-sum distributions from the plan.
Our obligations and the funded status of our plan, measured at March 31,
are as follows:
2004 2003
---- ----
Change in Benefit Obligation
Benefit obligation at beginning of year $ 9,214,925 $ 10,681,119
Service cost 662,770 601,607
Interest cost 557,183 636,649
Amendments -- (2,807,300)
Actuarial loss 87,936 692,436
Benefits paid (255,758) (589,586)
------------ ------------
Benefit obligation at end of year $ 10,267,056 $ 9,214,925
------------ ------------
Change in Plan Assets
Fair value of plan assets at beginning of year $ 8,310,322 $ 9,219,679
Actual return (loss) on plan assets 1,645,573 (1,198,684)
Employer contribution 749,929 878,913
Benefits paid (255,758) (589,586)
-------------- --------------
Fair value of plan assets at end of year $10,450,066 $ 8,310,322
----------- ------------
Funded status $ 183,010 $ (904,603)
Unrecognized net actuarial loss 3,709,444 4,858,741
Unrecognized prior service cost (1,198,303) (1,284,482)
------------- --------------
Net amount recognized $ 2,694,151 $ 2,669,656
============= ============
Amounts recognized in the statement of
financial position consist of:
Prepaid benefit cost $ 2,694,151 $ --
Accrued benefit cost -- (716,780)
Accumulated other comprehensive income -- 3,386,436
------------- ------------
Net amount recognized $ 2,694,151 $ 2,669,656
============= ===========
Projected benefit obligation $ 10,267,056 $ 9,214,925
Accumulated benefit obligation $ 9,932,355 $ 9,027,102
Fair value of plan assets $ 10,450,066 $ 8,310,322
The pre-tax increase (decrease) in minimum liability included in other
comprehensive income for 2004 and 2003 was ($3,386,436) and $3,386,436,
respectively.
2004 2003 2002
---- ---- ----
Components of Net Periodic Benefit Cost
Service cost $ 662,770 $ 601,607 $ 518,496
Interest cost 557,183 636,649 657,125
Expected return on plan assets (670,823) (756,731) (755,307)
Amortization of unrecognized net loss 262,483 61,873 36,528
Amortization of prior service cost (86,179) (8,198) (29,262)
------------ ------------- -----------
Net periodic benefit cost $ 725,434 $ 535,200 $ 427,580
========== ========== =========
Weighted-Average Assumptions Used to
Determine Benefit Obligations
Discount rate - pre-retirement 6.00% 6.25% 7.50%
Discount rate - post-retirement 5.75% 5.75% 5.71%
Rate of compensation increase 4.00% 4.00% 4.00%
Weighted-Average Assumptions Used to
Determine Net Periodic Benefit Cost
Discount rate - pre-retirement 6.25% 7.50% 7.75%
Discount rate - post-retirement 5.75% 5.71% 5.34%
Expected long-term return on plan assets 8.00% 8.00% 8.00%
Rate of compensation increase 4.00% 4.00% 4.00%
Our expected long-term rate of return on pension plan assets is based on
our targeted asset allocation assumption of approximately 60 percent equity
investments and approximately 40 percent fixed income investments.
Plan Assets
Our pension plan weighted-average asset allocations as of the plan's
measurement date (March 31) by asset category are as follows:
2004 2003
---- ----
Equity securities 69% 54%
Debt securities 24 35
Other 7 11
----- ----
100% 100%
=== ===
Our equity investment target of approximately 60 perccent includes
allocations to domestic, international and emerging markets managers. Our asset
allocation is designed to achieve a moderate level of overall portfolio risk in
keeping with our desired risk objective. We regularly review our asset
allocation and periodically rebalance our investments to our targeted allocation
as appropriate.
We expect to contribute $798,000 to the pension plan in 2005.
The following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid:
2005 $ 120,000
2006 130,000
2007 175,000
2008 230,000
2009 305,000
years 2010 - 2014 2,650,000
The Statement of Financial Accounting Standards No. 106, entitled
Employers' Accounting for Postretirement Benefits, and the Statement of
Financial Accounting Standards No. 112, entitled Employers' Accounting for
Postemployment Benefits, do not affect us as 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. Through June 30, 2004,
the Company matched 50% of the employee's contribution up to a maximum Company
contribution of 2.5% of the employee's annual compensation. For 2004, 2003, and
2002, Delta's Savings Plan expense was $167,800, $158,900 and $165,500,
respectively. Effective July 1, 2004, the Company will match 100% of the
employee's contribution up to a maximum Company contribution of 3.5% of the
employee's annual compensation.
(c) Employee Stock Purchase Plan We had an Employee Stock Purchase Plan
("Stock Plan") under which qualified permanent employees were eligible to
participate. Under the terms of the Stock Plan, such employees could contribute
on a monthly basis 1% of their annual salary level (as of July 1 of each year)
to be used to purchase Delta's common stock. We issued Delta common stock, based
upon the fiscal year contributions, using an average of the high and low sale
prices of Delta's stock as quoted in NASDAQ's National Market System on the last
business day in June and matched those shares so purchased. Our expenses for the
matching shares granted under the stock plan were $59,000, $53,000, and $52,000
for the three years ended June 30, 2004, respectively. Therefore, stock with an
equivalent market value of $118,000 was issued in July, 2004. Our Board
discontinued the Stock Plan as of July 1, 2004.
(5) 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 29,129, 30,821 and
28,506 shares in 2004, 2003 and 2002, respectively. We registered 150,000 shares
for issuance under the Reinvestment Plan in December, 2000, and as of June 30,
2004 there were 46,316 shares still available for issuance.
(6) Note Receivable From Officer
Delta's note receivable from an officer on the accompanying balance sheet
relates to a $160,000 loan made to Glenn R. Jennings, our President and Chief
Executive Officer. The loan, secured by real estate owned by Jennings, bears
interest at 6%, which Jennings pays monthly. Delta forgives $2,000 of the
principal amount for each month of service Jennings completes. The outstanding
balance on this loan was $110,000 as of June 30, 2004. In the event Jennings
terminates his employment with Delta other than due to a change in control, or
Jennings' employment is terminated for cause or as a result of his disability or
death, the loan will become immediately due and payable.
(7) Notes Payable and Line of Credit
The current available line of credit with Branch Banking and Trust Company
is $40,000,000, of which $4,738,000 and $1,031,000 were borrowed having a
weighted average interest rate of 3.14% and 3.07% as of June 30, 2004 and 2003,
respectively. The maximum amount borrowed during 2004 and 2003 was $19,034,000
and $30,690,000, respectively. The interest on this line is determined monthly
at the London Interbank Offered Rate plus 1% on the used line of credit. The
cost of the unused line of credit is 0.30%. We expect to renew the current line
of credit during October, 2004.
(8) Long-Term Debt
In February, 2003 we issued $20,000,000 of 7.00% Debentures that mature in
February, 2023. Redemption of up to $25,000 annually will be made on behalf of
deceased holders, up to an aggregate of $400,000 annually for all deceased
beneficial owners. The 7.00% Debentures can be redeemed by us beginning in
February, 2007 at a 2% premium, such premium declining ratably until it ceases
in February, 2009.
In March, 1998 we issued $25,000,000 of 7.15% Debentures that mature in
March, 2018. Redemption of up to $25,000 annually will be made on behalf of
deceased holders within 60 days of notice, subject to an annual aggregate
$750,000 limitation. The 7.15% Debentures can be redeemed by us with no premium.
In October, 1993 we issued $15,000,000 of 6 5/8% Debentures that mature in
October, 2023. Each holder may require redemption of up to $25,000 annually,
subject to an annual aggregate limitation of $500,000. Such redemption will also
be made on behalf of deceased holders within 60 days of notice, subject to the
annual aggregate $500,000 limitation. The 6 5/8% Debentures can be redeemed by
us with no premium.
In February, 2003, we redeemed $14,806,000 aggregate principal amount of
8.30% Debentures due 2026.
Debt issuance expenses are deferred and amortized over the terms of the
related debt. Loss on extinguishment of debt of $2,257,000 has been deferred and
is being amortized over the term of the related debt consistent with regulatory
treatment.
We amortize debt issuance expenses over the life of the related debt on a
straight-line basis, which approximates the effective yield method.
Our line of credit agreement and the indentures relating to all of our
publicly held debentures contain defined "events of default" which, among other
things, can make the obligation immediately due and payable. Of these, we
consider the following covenants to be most significant:
o Dividend payments cannot be made unless consolidated shareholders' equity
of the Company exceeds $25,800,000 (thus no retained earnings were
restricted); and
o We may not assume any additional mortgage indebtedness in excess of
$2,000,000 without effectively securing all debentures equally to such
additional indebtedness.
Furthermore, a default on the performance on any single obligation incurred
in connection with our borrowings simultaneously creates an event of default
with the line of credit and all of the debentures. We were not in default on any
of our line of credit or debenture agreements during any period presented.
(9) Fair Values of Financial Instruments
The fair value of our Debentures is estimated using discounted cash flow
analysis, based on our current incremental borrowing rates for similar types of
borrowing arrangements. The fair value of our Debentures at June 30, 2004 and
2003 was estimated to be $55,758,000 and $59,596,000, respectively. The carrying
amount in the accompanying consolidated financial statements as of June 30, 2004
and 2003 is $54,699,000 and $55,023,000, respectively.
The carrying amount of our other financial instruments including cash
equivalents, accounts receivable, notes receivable and accounts payable
approximate their fair value.
(10) Operating Leases
Our operating leases relate primarily to well and compressor station site
leases. Rental expense under long-term operating leases was $87,000, $90,000 and
$74,000 for the three years ending June 30, 2004, 2003 and 2002, respectively.
(11) Commitments and Contingencies
We have entered into individual employment agreements with our five
officers. The agreements expire or may be terminated at various times. The
agreements provide for continuing monthly payments or lump sum payments and
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 $2.9
million would be paid in addition to continuation of specified benefits for up
to five years.
(12) Rates
The Kentucky Public Service Commission exercises regulatory authority over
our retail natural gas distribution and our transportation services. The
Kentucky Public Service Commission regulation of our business includes setting
the rates we are permitted to charge our retail customers and our transportation
customers.
We monitor our need to file requests with the Kentucky Public Service
Commission for a general rate increase for our retail gas and transportation
services. Through these general rate cases, we are able to adjust the sales
prices of our retail gas we sell to and transport for our customers.
On April 5, 2004, we filed a general rate case with the Kentucky Public
Service Commission. This filing requested an annual increase in revenues of
$4,277,000, an increase of 7.4%. In accordance with normal practices the
Commission suspended the proposed rates until October 4, 2004 and a hearing was
held on August 18, 2004. We cannot predict the outcome of this proceeding.
The Kentucky Public Service Commission has also approved a gas cost
recovery clause, which permits us to adjust the rates charged to our customers
to reflect changes in our natural gas supply costs. Although we are not required
to file a general rate case to adjust rates pursuant to the gas cost recovery
clause, we are required to make quarterly filings with the Kentucky Public
Service Commission.
During July, 2001, the Kentucky Public Service Commission required an
independent audit of our gas procurement activities and the gas procurement
activities of four other Kentucky gas distribution companies as part of its
investigation of increases in wholesale natural gas prices and their impact on
customers. The Kentucky Public Service Commission indicated that Kentucky
distributors had generally developed sound planning and procurement procedures
for meeting their customers' natural gas requirements and that these procedures
had provided customers with reliable supplies of natural gas at reasonable
costs. The Kentucky Public Service Commission noted the events of the 2000-2001
heating season, including changes in natural gas wholesale markets. It required
the auditors to evaluate distributors' gas planning and procurement strategies
in light of the recent more volatile wholesale markets, with a primary focus on
a balanced portfolio of gas supply that balances cost issues, price risk and
reliability. The auditors were selected by the Kentucky Public Service
Commission. The final audit report, dated November 15, 2002, contains 16
procedural and reporting-related recommendations in the areas of gas supply
planning, organization, staffing, controls, gas supply management, gas
transportation, gas balancing, response to regulatory change and affiliate
relations. The report also addresses several general areas for the five gas
distribution companies involved in the audit, including Kentucky natural gas
price issues, hedging, gas cost recovery mechanisms, budget billing,
uncollectible accounts and forecasting. We believe that implementation of the
recommendations will not result in a significant impact on our financial
position or results of operations. We are required to file periodic reports as
to the status of our implementation of the recommendations. On July 26, 2004,
the Kentucky Public Service Commission notified us that fourteen of the sixteen
recommendations are considered completed. Our next progress report is to be
filed by October 22, 2004.
In addition to regulation by the Kentucky Public Service Commission, we may
obtain non-exclusive franchises from the cities and communities 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 a local franchise. We hold
franchises in four of the cities and seven of the communities we serve. In the
other cities and communities we serve, either our franchises have expired, the
communities do not have governmental organizations authorized to grant
franchises, or the local governments have not required or do not want to offer a
franchise. We attempt to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government 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 or community. To date, the absence of
a franchise has caused no adverse effect on our operations.
(13) Operating Segments
Our Company has two segments: (i) a regulated natural gas distribution,
transmission and storage segment, and (ii) a non-regulated segment which
participates in related ventures, consisting of natural gas marketing and
production. The regulated segment serves residential, commercial and industrial
customers in the single geographic area of central and southeastern Kentucky.
Virtually all of the revenue recorded under both segments comes from the sale or
transportation of natural gas. Price risk for the regulated business is
mitigated through our Gas Cost Recovery Clause, approved quarterly by the
Kentucky Public Service Commission. Price risk for the non-regulated business is
mitigated by efforts to balance supply and demand. However, there are greater
risks in the non-regulated segment because of the practical limitations on the
ability to perfectly predict our demand. In addition, we are exposed to price
risk resulting from changes in the market price of gas and uncommitted gas
volumes of our non-regulated companies.
The segments follow the same accounting policies as described in the
Summary of Significant Accounting Policies in Note 1 of the Notes to
Consolidated Financial Statements. Intersegment revenues and expenses consist of
intercompany revenues and expenses from the sale and purchase of gas as well as
intercompany gas transportation services. Effective January 1, 2002, the
non-regulated segment discontinued the practice of selling gas to the regulated
segment. This led to a decline in intersegment revenues and expenses for 2003.
Intersegment transportation revenue and expense is recorded at our tariff rates.
Transfer pricing for sales of gas between segments was at cost. Operating
expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown below for the periods:
($000) 2004 2003 2002
---- ---- ----
Operating Revenues
Regulated
External customers 52,103 47,769 40,370
Intersegment 3,247 3,131 3,050
--------- -------- -------
Total regulated 55,350 50,900 43,420
Non-regulated
External customers 27,091 20,611 15,500
Intersegment -- -- 1,691
------------- ------------ ---------
Total non-regulated 27,091 20,611 17,191
Eliminations for intersegment (3,247) (3,131) (4,741)
---------- -------- ---------
Total operating revenues 79,194 68,380 55,870
======== ======= ========
Operating Expenses
Regulated
Purchased gas 30,947 26,595 19,743
Depreciation 4,302 4,163 3,964
Income taxes 1,402 1,395 1,599
Other 12,007 11,823 10,743
-------- ------- --------
Total regulated 48,658 43,976 36,049
-------- ------- --------
Non-regulated
Purchased gas 21,026 14,397 10,355
Depreciation 130 150 117
Income taxes 958 963 651
Other 3,495 3,499 5,038
--------- --------- ---------
Total non-regulated 25,609 19,009 16,161
Eliminations for intersegment (3,247) (3,131) (4,741)
--------- -------- ---------
Total operating expenses 71,020 59,854 47,469
======== ======== ========
Other Income and Deductions, Net
Regulated 61 48 17
Non-regulated -- -- --
------------- ------------- -------------
Total other income and
deductions 61 48 17
============ =========== ============
Interest Charges
Regulated 4,409 4,624 4,768
Non-regulated (13) 11 25
Eliminations for intersegment -- -- (11)
----------- -------------- ------------
Total interest charges 4,396 4,635 4,782
========= ========== ==========
Net Income
Regulated 2,344 2,348 2,621
Non-regulated 1,494 1,503 1,016
--------- ---------- ----------
Total net income 3,838 3,851 3,637
========= ========== ==========
Assets
Regulated 135,084 130,937 125,086
Non-regulated 3,288 2,350 2,055
--------- --------- ----------
Total assets 138,372 133,287 127,141
======= ======= ========
Capital Expenditures
Regulated 8,957 8,827 9,741
Non-regulated 2 12 7
------------- ------------ -----------
Total capital expenditures 8,959 8,839 9,748
========= ========= ==========
(14) 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.
Basic and
Diluted Earnings
(Loss) per
Income(Loss) Common Share
Cumulative Cumulative Basic and
Effect of a Effect of a Diluted
Principle Change In Change In Earnings (loss)
Operating Operating Accounting Accounting Net Income per Common
Quarter Ended Revenues Income Principle Principle(a) (Loss) Share(a)
------------- -------- ------ ------------ ------------- ------------ ---------
Fiscal 2004
September 30 $ 10,137,842 $ 217878 $ (863,725) $ (.27) $ (863,725) $(.27)
December 31 16,828,444 1,534,667 409,027 .13 409,027 .13
March 31 35,587,614 4,884,292 3,794,193 1.19 3,794,193 1.19
June 30 16,639,714 1,536,467 498,564 .16 498,564 .16
Fiscal 2003
September 30 $ 7,153,282 $ 231,609 $ (902,877) $ (.36) $ (991,247) $(.39)
December 31 15,501,819 1,850,943 692,765 .27 692,765 .27
March 31 31,217,192 5,478,145 4,258,292 1.66 4,258,292 1.66
June 30 14,507,970 965,669 (109,203) (.08) (109,203) (.08)
(a) Quarterly earnings per share may not equal annual earnings per share due to
changes in shares outstanding.
SCHEDULE II
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED JUNE 30, 2004, 2003, AND 2002
Column A Column B Column C Column D Column E
Additions Deductions
Charged to
Balance at Charged to Other Accounts Amounts Charged
Beginning of Costs and -Recoveries Off Balance at
Description Period Expenses Or Paid End of Period
Deducted From the Asset to
Which it Applies - Allowance
for doubtful accounts for the
years ended:
June 30, 2004 $ 350,000 $ 391,360 $ 65,844 $ 507,204 $ 300,000
June 30, 2003 $ 165,000 $ 536,910 $ 63,351 $ 415,261 $ 350,000
June 30, 2002 $ 575,000 $ 153,074 $ 63,832 $ 626,906 $ 165,000
EXHIBIT 12
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
COMPUTATION OF THE CONSOLIDATED RATIO OF EARNINGS
TO FIXED CHARGES
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
Earnings
Net income $3,838,059 $3,850,607 $3,636,713 $3,635,895 $3,464,858
Provisions for income
taxes 2,359,600 2,413,357 2,249,500 2,232,500 2,068,500
Fixed charges 4,424,777 4,665,030 4,806,457 5,140,965 4,777,031
--------- --------- --------- --------- ---------
Total $10,622,436 $10,928,994 $10,692,670 $11,009,360 $10,310,389
=========== =========== =========== =========== ===========
Fixed Charges
Interest on debt $4,158,988 $4,441,037 $4,620,597 $4,955,805 $ 4,593,571
Amortization of debt
expense 236,789 193,993 161,160 161,160 161,160
One third of rental
expense 29,000 30,000 24,700 24,000 22,300
------ --------- --------- --------- --------
Total $4,424,777 $4,665,030 $4,806,457 $5,140,965 $ 4,777,031
========== ========== ========== ========== ===========
Ratio of earnings to
fixed charges 2.40x 2.34x 2.22x 2.14x 2.16x
EXHIBIT 21
Subsidiaries of the Registrant
Delgasco, Inc., Enpro, Inc. and Delta Resources, Inc. are wholly-owned
subsidiaries of the Registrant, are incorporated in
the state of Kentucky and do business under their corporate names.
EXHIBIT 23
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No.
333-104301 of Delta Natural Gas Company, Inc. on Form S-2 of our report dated
August 13, 2004 (which expresses an unqualified opinion on the Company's
consolidated financial statements and includes an explanatory paragraph
referring to the Company's change effective July 1, 2002 in its accounting for
asset retirement obligations), related to the consolidated financial statements
of Delta Natural Gas Company, Inc. appearing in this Annual Report on Form 10-K
for the year ended June 30, 2004.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio
September 3, 2004
Exhibit 31.1
CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Glenn R. Jennings, certify that:
1. I have reviewed this annual report on Form 10-K of Delta Natural Gas
Company, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrants as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's Board
of Directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: September 3, 2004
By: /s/Glenn R. Jennings
------------------------------
Glenn R. Jennings
President and Chief Executive Officer
Exhibit 31.2
CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John F. Hall, certify that:
1. I have reviewed this annual report on Form 10-K of Delta Natural Gas
Company, Inc.;
2. Based on my knowledge, this report does not contain any untrue statement of
a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrants as of, and for, the periods presented in this report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during the period in
which this report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
c) Disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in
the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal
control over financial reporting; and
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's Board
of Directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to
record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
control over financial reporting.
Date: September 3, 2004
By: /s/John F. Hall
----------------------------
John F. Hall
Vice President - Finance, Secretary and Treasurer
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Delta Natural Gas Company, Inc. on Form
10-K for the period ending June 30, 2004 as filed with the Securities and
Exchange Commission on the date hereof (the "Report"), I, Glenn R. Jennings,
President and Chief Executive Officer of the Company, certify, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002, to the best of my knowledge and belief, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material
respects, the financial condition and result of operations of Delta Natural
Gas Company, Inc.
/s/Glenn R. Jennings
- ----------------------------
Glenn R. Jennings
President and Chief Executive Officer
September 3, 2004
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Delta Natural Gas Company, Inc. on Form
10-K for the period ending June 30, 2004 as filed with the Securities and
Exchange Commission on the date hereof (the "Report"), I, John F. Hall, Vice
President - Finance, Secretary and Treasurer of the Company, certify, pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:
(1) The Report fully complies with the requirements of section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material
respects, the financial condition and result of operations of Delta Natural
Gas Company, Inc.
/s/John F. Hall
- -------------------------------
John F. Hall
Vice President - Finance, Secretary and Treasurer
September 3, 2004