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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, 2002.
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, Winchester, Kentucky 40391___
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 859-744-6171.
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class 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]
As of August 30, 2002, Delta Natural Gas Company, Inc. had outstanding
2,538,845 shares of common stock $1 Par Value, and the aggregate market value of
the voting stock held by non-affiliates was approximately $53,290,356.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant's definitive proxy statement to be filed with the Commission
not later than 120 days after June 30, 2002, is incorporated by reference in
Part III of this Report.
TABLE OF CONTENTS
Page Number
PART I
Item 1. Business 1
General 1
Gas Operations and Supply 1
Regulatory Matters 3
Capital Expenditures 5
Financing 5
Employees 5
Consolidated Statistics 6
Item 2. Properties 7
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 and
Related Stockholder Matters 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 16
Item 8. Financial Statements and Supplementary Data 18
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 18
PART III
Item 10. Directors and Executive Officers of the Registrant 18
Item 11. Executive Compensation 18
Item 12. Security Ownership of Certain Beneficial
Owners and Management 18
Item 13. Certain Relationships and Related Transactions 19
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 19
Signatures 22
PART I
Item 1. Business
General
Delta Natural Gas Company, Inc. provides natural gas distribution to retail
customers and also provides gas transportation service to industrial customers
and interconnected pipelines.
Delta operates under two segments, a regulated segment and an unregulated
segment. See Note 11 of the Notes to Consolidated Financial Statements.
Delta's regulated segment sells natural gas to 40,000 retail customers in
23 predominately rural communities in central and southeastern Kentucky. In
addition, Delta transports gas to industrial customers on Delta's system who
purchase gas in the open market. Delta also transports gas on behalf of local
producers and customers not on Delta's distribution system.
Delta's unregulated segment operates through two wholly-owned subsidiaries,
Delta Resources, Inc. and Delgasco, Inc. These subsidiaries purchase gas from
gas marketers and Kentucky producers and resell the gas to industrial customers
on Delta's system and to others not on Delta's distribution system. Enpro, Inc.,
another wholly-owned subsidiary that is part of the unregulated segment,
produces natural gas and oil that is sold in the unregulated market.
Gas Operations and Supply
Currently, over 99% of Delta's customers are residential and commercial.
Delta's remaining light industrial customers purchased 4% of the total volume of
gas sold by Delta at retail during 2002.
The communities in Delta's service area typically contain populations of
less than 20,000. The three largest service areas are Nicholasville, Corbin and
Berea, where Delta serves 7,000, 6,000 and 4,000 retail customers, respectively.
The communities served by Delta continue to expand, resulting in some growth
opportunities for the Company. Industrial parks have been developed in several
areas and have resulted in additional industrial customers, some of whom
purchase gas through Delta's regulated segment.
The economy of Delta's service area is based principally on light industry,
farming and coal mining. Delta's revenues are affected by various factors,
including rates billed to customers, the cost of natural gas, economic
conditions in the areas that Delta serves, weather conditions and competition.
Delta competes for retail customers and sales with alternative sources of
energy, including electricity, coal, oil, propane and wood. Delta Resources and
Delgasco, who purchase gas and resell it to various industrial customers and
others, also compete for their customers with producers and marketers of natural
gas. Higher gas costs, which the Company is generally able to pass through to
customers, may influence customers to conserve, or, in the case of industrial
customers, to use alternative energy sources. Also, the potential bypass of
Delta's system by industrial customers and others is a competitive concern that
Delta has addressed and will continue to address through rate design and
marketing strategies.
Delta's retail sales are seasonal and temperature-sensitive, as the
majority of the gas sold by Delta is used for heating. This seasonality impacts
Delta's liquidity position and its management of its working capital
requirements. Variations in the average temperature during the winter impacts
its revenues year-to-year. The impact of average temperature variations is
ameliorated, however, by regulatory rules that allow Delta to vary rates charged
customers in response to weather conditions that vary from thirty-year average
("normal") weather in the five traditional winter months billed in December
through April. (See Management's Discussion and Analysis of Financial Condition
and Results of Operations).
Retail gas sales in 2002 were 3,664,000 Mcf, generating $38,175,000 in
revenues, as compared to 4,529,000 Mcf and $47,174,000 in revenues for 2001.
Heating degree days billed during 2002 were 89.0% of normal as compared with
106.8% in 2001. Sales volumes decreased by 865,000 Mcf, or 19%, in 2002 as
compared to 2001.
Delta's transportation of natural gas during 2002 generated revenues of
$5,046,000 as compared with $4,709,000 during 2001. Of the total transportation
revenues in 2002, $3,826,000 (4,866,000 Mcf) was earned for transportation of
gas to customers on Delta's distribution system ("on-system"), while $1,220,000
(3,590,000 Mcf) was earned for transportation of gas to customers outside
Delta's distribution system ("off-system"). Of the total transportation revenues
for 2001, $3,895,000 (4,768,000 Mcf) and $814,000 (2,677,000 Mcf) were earned
for transportation for on-system and off-system customers, respectively.
As an active participant in many areas of the natural gas industry, Delta
plans to continue its efforts to expand its gas distribution system and customer
base. Delta continues to consider acquisitions of other gas systems, some of
which are contiguous to its existing service areas, as well as expansion within
its existing service areas.
Delta also anticipates continuing activity in gas production and
transportation and plans to pursue and increase these activities wherever
practicable. Delta will 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.
Some producers in Delta's service area can access certain pipeline delivery
systems other than Delta, which provides competition from others for
transportation of gas. Delta will continue its efforts to purchase or transport
any natural gas available that is produced in reasonable proximity to its
facilities.
Delta receives its gas supply from a combination of interstate and Kentucky
sources. Delta acquires its interstate gas supply from gas marketers. Delta's
interstate gas supply is transported to Delta from production and storage fields
by Tennessee Gas Pipeline Company ("Tennessee"), Columbia Gas Transmission
Corporation ("Columbia"), Columbia Gulf and Texas Eastern Transmission
Corporation.
Delta's agreements with Tennessee extend until 2003 and unless terminated
by Tennessee or Delta, shall automatically renew thereafter on subsequent
five-year terms. Tennessee is obligated under the agreements to transport up to
19,600 Mcf per day for Delta. During 2002, Tennessee transported a total of
1,109,000 Mcf for Delta under these agreements.
All but two of Delta's agreements with Columbia and Columbia Gulf extend
through 2008 and thereafter continue on a year-to-year basis until terminated by
one of the parties to the particular agreement. The two other agreements
currently continue on a year-to-year basis. Under these agreements, Columbia is
obligated to transport up to 12,500 Mcf per day for Delta, and Columbia Gulf is
obligated to transport up to 4,300 Mcf per day for Delta. During 2002, Columbia
and Columbia Gulf transported a total of 555,000 Mcf for Delta under these
agreements.
Delta currently has agreements with two gas marketers. Under these
commodity requirements contracts, the marketers are obligated to supply the
volumes consumed by Delta's regulated customers in the respective Tennessee or
Columbia serviced areas. Gas prices are based on index prices. One of the
agreements began May 1, 2000 and extends through April 30, 2003 with an option
to extend the agreement for one additional year. The other agreement currently
continues on a year-to-year basis. Delta purchases gas from other gas marketers
as needed at either current market prices or forward market prices.
Delta has an agreement with Columbia Natural Resources ("CNR") to purchase
natural gas through October 31, 2004. Delta purchased 55,000 Mcf from CNR during
2002. CNR delivers this gas to Delta's customers on CNR's pipelines.
Delta also purchased 25,000 Mcf of natural gas from its wholly-owned
subsidiary, Enpro, Inc., during 2002.
Delta owns and operates an underground natural gas storage field which is
used to provide storage for a significant portion of Delta's winter gas supply
needs. This storage capability permits Delta to purchase and store gas during
the non-heating months and then withdraw and sell the gas during the peak usage
months. During 2002, 1,900,000 Mcf was withdrawn from this storage field.
Delta continues to seek additional new gas supplies from available sources.
Delta 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 its customers.
Regulatory Matters
Delta's retail natural gas distribution and its transportation services are
subject to the regulatory authority of the Public Service Commission of Kentucky
("PSC") with respect to various aspects of Delta's business, including rates and
service to retail and transportation customers. Delta monitors the need to file
a general rate case as a way to adjust its sales prices.
On December 27, 1999, Delta received approval from the PSC for an annual
revenue increase of $420,000. This resulted from Delta's last rate case that was
filed by Delta in July, 1999. The approval included a weather normalization
provision that permits Delta to adjust base rates for the billing months of
December through April to reflect variations from normal winter weather.
Delta's rates include a Gas Cost Recovery ("GCR") clause, which permits
changes in Delta's gas supply costs to be reflected in the rates charged to
customers. The GCR requires Delta to make quarterly filings with the PSC, but
such procedure does not require a general rate case.
During July, 2001, the PSC required an independent audit of the gas
procurement activities of Delta and four other gas distribution companies as
part of its investigation of increases in wholesale natural gas prices and their
impacts on customers. The PSC 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 a
reliable supply of natural gas at reasonable costs. The PSC noted the events of
the prior year, including changes in natural gas wholesale markets, and required
the audits 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 consultants that were selected by the PSC are currently
completing this audit. Delta has received a draft of the consultant's report and
is in the process of reviewing and commenting on it. The draft report contains
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, GCR mechanisms, budget billing, uncollectible accounts
and forecasting. Delta cannot predict how the PSC will interpret or act on any
audit recommendations. As a result, Delta cannot predict the impact of this
regulatory proceeding on the Company's financial position or results of
operations.
In addition to PSC regulation, Delta may obtain non-exclusive franchises
from the cities and communities in which it operates authorizing it to place its
facilities in the streets and public grounds. No utility may obtain a franchise
until it has obtained approval from the PSC to bid on a local franchise. Delta
holds franchises in four of the cities and seven other communities it serves. In
the other cities and communities served by Delta, either Delta's 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. Delta attempts to acquire or reacquire franchises whenever
feasible.
Without a franchise, a local government could require Delta to cease its
occupation of the streets and public grounds or prohibit Delta from extending
its facilities into any new area of that city or community. To date, the absence
of a franchise has had no adverse effect on Delta's operations.
Capital Expenditures
Capital expenditures during 2002 were $9.4 million and for 2003 are
estimated to be $9.8 million. The Company's planned expenditures include system
extensions as well as the replacement and improvement of existing transmission,
distribution, gathering and general facilities.
Financing
The Company's 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 $19.4 million had
been borrowed at June 30, 2002.
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 the
Company's capital needs and market conditions.
During 2002 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 4,916 shares of common stock resulting in an increase of $96,000 in
Delta's common shareholders' equity. The Dividend Reinvestment and Stock
Purchase Plan (see Note 5 of the Notes to Consolidated Financial Statements)
resulted in the issuance of 28,506 shares of common stock providing an increase
of $590,000 in Delta's common shareholders' equity.
Employees
Delta employed a total of 156 full-time employees on June 30, 2002. Delta
considers its relationship with its employees to be satisfactory. Delta's
employees are not represented by unions or subject to any collective bargaining
agreements.
Consolidated Statistics
For the Years Ended June 30, 2002 2001 2000 1999 1998
Average Retail Customers Served
Residential 33,624 33,691 33,251 32,429 31,953
Commercial 5,235 5,227 5,110 4,958 4,873
Industrial 62 65 66 68 70
---- -- ---- -- ---- -- ---- -- ----
Total 38,921 38,983 38,427 37,455 36,896
====== ====== ====== ====== ======
Operating Revenues ($000)
Residential sales 23,202 28,088 19,672 17,329 19,969
Commercial sales 13,832 17,040 10,952 10,039 11,890
Industrial sales 1,141 2,046 1,104 1,173 1,576
On-system transportation 3,826 3,895 4,056 4,107 3,877
Off-system transportation 1,220 814 522 363 483
Non-regulated sales 12,511 18,640 9,431 5,491 6,335
Other 198 247 190 170 128
--- --- --- --- --- --- --- --- ---
Total 55,930 70,770 45,927 38,672 44,258
====== ====== ====== ====== ======
System Throughput
(Million Cu. Ft.)
Residential sales 2,133 2,614 2,266 2,223 2,377
Commercial sales 1,389 1,666 1,397 1,401 1,504
Industrial sales 142 249 174 189 231
--- --- --- --- --- --- --- --- ---
Total retail sales 3,664 4,529 3,837 3,813 4,112
On-system transportation 4,866 4,768 4,703 4,434 3,467
Off-system transportation 3,590 2,677 1,672 1,144 1,489
- ----- - ----- - ----- - ----- -
Total 12,120 11,974 10,212 9,391 9,068
====== ====== ====== ===== =====
Average Annual Consumption Per
Average Residential Customer
(Thousand Cu. Ft.) 63 78 68 69 74
Lexington, Kentucky Degree Days
Actual 4,137 4,961 4,162 4,188 4,397
Percent of 30 year average
(4,646) 89.0 106.8 89.6 90.1 94.6
Average Revenue Per Mcf Sold
at Retail ($) 10.42 10.42 8.27 7.49 8.13
Average Gas Cost Per Mcf Sold
at Retail ($) 5.39 6.07 3.77 3.69 4.60
Item 2. Properties
Delta owns its corporate headquarters in Winchester, Kentucky. Delta owns
ten buildings used for field operations in the cities it serves. Also, Delta
owns a building in Laurel County used for training and equipment and materials
storage.
The Company owns 2,403 miles of natural gas gathering, transmission,
distribution, storage and service lines. These lines range in size up to twelve
inches in diameter.
Delta holds leases for the storage of natural gas under 8,000 acres located
in Bell County, Kentucky. This property was developed for the underground
storage of natural gas.
All the foregoing properties described in this Item 2 are used principally
in connection with Delta's regulated natural gas distribution, transmission and
storage segment. See Note 11 of the Notes to Consolidated Financial Statements
for a description of Delta's two business segments.
In addition, through its three wholly-owned subsidiaries, Enpro, Delgasco
and Delta Resources, the Company operates its unregulated segment, which
involves related ventures consisting of natural gas marketing as well as oil and
gas production. The properties owned by Enpro that are described in the
following two paragraphs are used in connection with Delta's unregulated
segment.
Enpro owns interests in certain oil and gas leases relating to 11,000 acres
located in Bell, Knox and Whitley Counties. There presently are 40 gas wells and
5 oil wells producing from these properties. Enpro's remaining proved, developed
natural gas reserves are estimated at 3 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 no reserve studies have been performed on the
properties. Enpro had production of 187,000 Mcf during 2002.
Under the terms of an agreement with a producer relating to 14,000 acres of
Enpro's undeveloped holdings, the producer is conducting exploration activities
on the acreage. Enpro reserved the option to participate in wells drilled and
also retained certain working and royalty interests in any production from
future wells.
There are no significant encumbrances on the Company's assets.
Item 3. Legal Proceedings
Delta and its subsidiaries are not parties to any legal proceedings that
are expected to have a materially adverse impact on the liquidity, financial
condition or results of operations of the Company.
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted during the fourth quarter of 2002.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Delta has paid cash dividends on its common stock each year since 1964.
While it is the intention of the Board of Directors to continue to declare
dividends on a quarterly basis, the frequency and amount of future dividends
will depend upon the Company's earnings, financial requirements and other
relevant factors, including limitations imposed by the indenture for the
Debentures. There were 2,298 record holders of Delta's common stock as of August
1, 2002.
Delta's common stock is traded in the National Association of Securities
Dealers Automated Quotation ("NASDAQ") National Market System under the symbol
DGAS. The accompanying table reflects the high and low sales prices during each
quarter as reported by NASDAQ and the quarterly dividends declared per share.
Range of Stock Prices($) Dividends
Quarter High Low Per Share($)
- ------- ---- --- ------------
Fiscal 2002
First 20.43 18.90 .29
Second 20.99 18.67 .29
Third 23.08 19.75 .29
Fourth 22.50 21.47 .29
Fiscal 2001
First 18.00 15.25 .285
Second 19.62 16.25 .285
Third 20.31 17.69 .285
Fourth 20.75 18.00 .285
During July, 2001, Delta distributed 4,916 shares of its common stock to
its employees under its Employee Stock Purchase Plan (see Note 4(c) of the Notes
to Consolidated Financial Statements). Delta received cash consideration of
$19.58 per share for one-half of those shares (2,458 shares), for a total cash
consideration of $48,000, while one-half of the shares (2,458 shares) were
provided to the employees without cash consideration as a part of Delta's
compensation and benefits for its employees. The securities were sold pursuant
to the exemption from registration provided by Rule 147 under the Securities Act
of 1933. This exemption was relied upon in light of the facts that Delta is
incorporated and doing business in Kentucky, and all eligible employees are
residents of Kentucky. Subsequent to year end, in July, 2002 Delta distributed
4,728 shares of its common stock to its employees at $21.83 per share under the
same program, and this was recorded in July, 2002. Delta's Employee Stock
Purchase Plan was authorized by Delta's Board of Directors, but was not required
to be submitted for shareholder approval.
Also, during June, 2002, Delta provided a total of 800 shares of its common
stock to its directors (100 shares per director). Delta received no cash
consideration for the shares, which were provided to its directors as a part of
their compensation. This transaction may not involve a "sale" of securities
under the Securities Act of 1933, and in any event, the securities were
qualified for an exemption from registration provided by Rule 147 under the
Securities Act of 1933. This exemption was relied upon in light of the facts
that Delta is incorporated and doing business in Kentucky, and all participating
directors are residents of Kentucky.
No underwriters were engaged in connection with any of the foregoing
transactions, and thus no underwriter discounts or commissions were paid in
connection with any of the foregoing.
Item 6. Selected Financial Data
For the Years Ended June 30, 2002 2001 2000 1999 1998(a)
---- ---- ---- ---- -------
Summary of Operations ($)
Operating revenues 55,929,780 70,770,156 45,926,775 38,672,238 44,258,000
Operating income 8,401,452 8,721,719 8,176,722 6,652,070 6,731,859
Net income 3,636,713 3,635,895 3,464,857 2,150,794 2,451,272
Basic and diluted earnings
per common share 1.45 1.47 1.42 .90 1.04
Dividends declared
per common share 1.16 1.14 1.14 1.14 1.14
Average Number of Common
Shares Outstanding
(basic and diluted) 2,513,804 2,477,983 2,433,397 2,394,181 2,359,598
Total Assets ($) 127,948,525 124,179,138 112,918,919 107,473,117 102,866,613
Capitalization ($)
Common shareholders'
equity 34,182,277 32,754,560 31,297,418 29,912,007 29,810,294
Long-term debt 48,600,000 49,258,902 50,723,795 51,699,700 52,612,494
---------- ---------- ---------- ---------- ----------
Total capitalization 82,782,277 82,013,462 82,021,213 81,611,707 82,422,788
========== ========== ========== ========== ==========
Short-Term Debt ($)(b) 21,105,000 19,250,000 11,375,000 8,145,000 3,665,000
Other Items ($)
Capital expenditures 9,421,765 7,069,713 8,795,653 7,982,143 11,193,613
Total plant 156,305,063 147,792,390 141,986,856 133,804,954 127,028,159
- ---------------------
(a) During March, 1998, $25,000,000 of debentures were sold, and the
proceeds were used to repay short-term debt and to redeem the
Company's $10,000,000 of 9% debentures.
(b) Includes current portion of long-term debt.
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Overview
The Company's utility operations are subject to regulation by the PSC,
which has a significant role in determining the Company's return on equity. The
PSC approves rates that are intended to permit a specified rate of return on
investment. The Company's rate tariffs allow the cost of gas to be passed
through to customers (see Business - Regulatory Matters).
The Company's business is temperature-sensitive. Accordingly, the Company's
sales volumes in any given period reflect, in addition to other factors, the
impact of weather, with colder temperatures generally resulting in increased
sales volumes by the Company. The Company anticipates that this sensitivity to
seasonal and other weather conditions will continue to be reflected in the
Company's sales volumes in future periods. However, Delta's current tariffs,
approved by the PSC effective January 1, 2000, provide for some adjustment of
gas rates through a weather normalization tariff (see Business - Regulatory
Matters). Under the weather normalization tariff, Delta's rates for residential
and small non-residential customers are generally increased when winter weather
is warmer than normal and decreased when winter weather is colder than normal.
Delta is permitted to adjust rates for these classes of customers for the
billing months of December through April under this tariff.
Liquidity and Capital Resources
Because of the seasonal nature of Delta's sales, the smallest proportion of
cash generated from operations is received during the warmer months when sales
volumes decrease considerably. Additionally, most construction activity takes
place during the non-heating season because of more favorable weather
conditions. During the warmer, non-heating months, therefore, cash needs for
operations and construction are partially met through short-term borrowings.
Capital expenditures for Delta for fiscal 2003 are expected to be $9.8
million. The capital expenditures will be made for system extensions as well as
the replacement and improvement of existing transmission, distribution,
gathering and general facilities.
Delta has been generating internally only a portion of the cash necessary
for its capital expenditure requirements and thus finances the balance of its
capital expenditures on an interim basis through the use of its borrowing
capability under its short-term line of credit. The current available line of
credit is $40,000,000, of which $19,355,000 was borrowed at June 30, 2002. The
line of credit, which is with Bank One, Kentucky, NA, requires renewal during
October, 2002. The Company intends to pursue renewal or to enter into a new
agreement and seek substantially the same terms as the existing agreement.
These short-term borrowings are periodically repaid with the net proceeds
from the sale of long-term debt and equity securities, as was done in March,
1998 when the net proceeds of $24,100,000 from the sale of $25,000,000 of
debentures were used to repay short-term debt and to redeem the Company's 9%
debentures, that would have matured in 2011, in the amount of $10,000,000.
The primary cash flows during the last three years are summarized below:
2002 2001 2000
---- ---- ----
Provided by operating activities $10,511,896 $ 2,652,572 $ 8,827,505
Used in investing activities (9,421,765) (7,069,713) (8,795,653)
Provided by used in)financing
activities (1,028,996) 4,185,248 115,554
------------ ----------- -----------
Net increase (decrease) in cash and
cash equivalents $ 61,135 $ (231,893) $ 147,406
=========== =========== ===========
Cash provided by operating activities consists of net income and noncash
items including depreciation, depletion, amortization and deferred income taxes.
Additionally, changes in working capital are also included in cash provided by
operating activities. The Company expects that internally generated cash,
coupled with short-term borrowings, will be sufficient to satisfy its operating,
normal capital expenditure and dividend requirements.
Results of Operations
Operating Revenues
The decrease in operating revenues for 2002 of $14,840,000 was primarily
attributable to decreased sales volumes and decreased gas rates. Sales volumes
decreased due to the warmer winter weather in 2002. Gas rates decreased due to
lower gas prices, net of increases from the impact of the weather normalization
tariff.
The increase in operating revenues for 2001 of $24,843,000 was primarily
attributable to increased gas rates and increased sales volumes. Gas rates
increased due to higher gas prices, net of decreases from the impact of the
weather normalization tariff. Sales volumes increased due to the colder winter
weather in 2001.
Heating degree days billed for 2002 were 89.0% of normal as compared with
106.8 % of normal for 2001 and 89.6% of normal for 2000.
The following table sets forth certain variations in revenues for the last
two fiscal years:
2002 compared 2001 compared
Increase (Decrease) to 2001 to 2000
Variations in regulated revenues
Gas rates $ (1,930,000) $ 11,364,800
Weather normalization adjustment 1,935,000 (1,634,000)
Sales volumes (9,002,000) 5,715,700
Transportation 529,000 69,100
Other (49,000) 57,400
--------------- ---------------
Total $ (8,517,000) $ 15,573,000
------------- ------------
Variations in non-regulated revenues
Gas rates $ (6,354,000) $ 8,669,000
Sales volumes 32,000 601,000
Other (1,000)
----------------- --------------
Total (6,323,000) 9,270,000
--------------- --------------
Total variations in revenues $(14,840,000) $ 24,843,000
============= ============
Percentage variations in regulated volumes
Gas sales (19.1) 18.0
Transportation 13.6 16.8
Percentage variations in non-regulated gas .4 7.7
sales volumes
Operating Expenses
The decrease in purchased gas expense for 2002 of $14,551,000 was due
primarily to the 21.3% decrease in the cost of gas purchased for retail sales
and the 10.7% decrease in volumes sold.
The increase in purchased gas expense for 2001 of $23,493,000 was due
primarily to the 73% increase in the cost of gas purchased for retail sales and
the 13% increase in volumes sold, both related to the above detailed revenue
variations.
The following table sets forth certain variations in purchased gas expense
for the last two fiscal years:
2002 compared 2001 compared
to 2001 to 2000
------------------- ------------
Variations in regulated gas expense
Gas rates $ (2,887,000) $ 11,505,000
Purchase volumes (4,877,000) 2,967,000
-------------- ---------------
Total $ (7,764,000) $ 14,472,000
-------------- --------------
Variations in non-regulated gas expense
Gas rates $ (6,651,000) $ 8,308,000
Purchase volumes (136,000) 713,000
---------------- ---------------
Total $ (6,787,000) $ 9,021,000
--------------- ---------------
Total variations in gas expense $ (14,551,000) $ 23,493,000
=============== ==============
Basic and Diluted Earnings Per Common Share
For the years ended June 30, 2002, 2001 and 2000, basic earnings per common
share changed as a result of changes in net income and the increased average
common shares outstanding that resulted from the common shares issued under
Delta's dividend reinvestment plan and shares issued to employees during the
periods. There are no potentially dilutive securities, therefore basic and
diluted earnings per common share are the same.
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. These forward-looking
statements are identified by their language, which may in some cases include
words such as "estimates", "attempts", "expects", "monitors", "plans",
"anticipates", "intends", "continues" or "will continue", "believes", and
similar expressions. Such forward-looking statements may concern future matters
(among other matters) such as: Delta's cost and the availability of natural gas
supplies; Delta's capital expenditures; its sources and availability of funding
for operation and expansion; Delta's anticipated growth and growth opportunities
through system expansion and acquisition; competitive conditions; Delta's
production, storage, gathering and transportation activities; regulatory and
legislative matters; dividends; and external and internal funding sources.
Such forward-looking statements are accordingly subject to important risks
and uncertainties that could cause the Company's actual results to differ
materially from those expressed in any such forward-looking statements.
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 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 Delta's capital expenditure requirements.
o Changes in economic conditions, demographic patterns and weather
conditions in Delta's retail service areas.
o Changes affecting Delta's cost of providing gas service, including
changes in gas supply costs, interest rates, the availability of
external sources of financing for Delta's operations, tax laws,
environmental laws, and the general rate of inflation.
o Changes affecting the cost of competing energy alternatives and
competing gas distributors.
o Changes in accounting principles and tax laws or the application of
such principles and laws to Delta.
New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No.
141 eliminates the pooling-of-interests method and requires all business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method. It also requires intangible assets acquired in a business
combination to be recognized separately from goodwill. SFAS No. 141 had no
impact on the Company's financial position or results of operations with respect
to business combination transactions that occurred prior to June 30, 2001. SFAS
No. 142 addresses how goodwill and other intangible assets should be accounted
for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is
that future goodwill and intangible assets with indefinite lives will no longer
be amortized beginning in 2002. Instead of amortization, goodwill will be
subject to an assessment for impairment by applying a fair-value-based test
annually and more frequently if circumstances indicate a possible impairment. If
the carrying amount of goodwill exceeds the fair value of that goodwill, an
impairment loss is recognized in an amount equal to the excess. The Company does
not have recorded goodwill or intangible assets. Accordingly, these new
accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No.
143 addresses asset retirement obligations that result from the acquisition,
construction or normal operation of long-lived assets. It requires companies to
recognize asset retirement obligations as a liability when the liability is
incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a
significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which is required to be adopted
July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and
APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" and combines the two accounting models into a single model based
on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not
have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an
exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and
Activities Related to Property, Plant, and Equipment". This proposed SOP applies
to all nongovernmental entities that acquire, construct or replace tangible
property, plant and equipment ("PP&E") including lessors and lessees. A
significant element of the SOP requires that entities use component accounting
for PP&E to the extent future component replacement will be capitalized. At
adoption, entities would have the option to apply component accounting
retroactively for all PP&E assets, to the extent applicable, or to apply
component accounting as an entity incurs capitalizable costs that replace all or
a portion of PP&E. The proposed effective date of the SOP is January 1, 2003.
The Company is currently analyzing the impact of this proposed SOP.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Delta serves its regulated customers using 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, while the price of a forward purchase
is fixed months prior to the delivery of the gas. Some of Delta's gas purchases
are injected into gas storage facilities in the non-heating months and withdrawn
from storage for delivery to customers during the heating season. The Company
has minimal price risk resulting from these gas purchase and storage
arrangements because these gas costs are passed on to Delta's regulated
customers through the gas cost recovery rate mechanism.
Delta's non-regulated subsidiaries actively pursue gas sales opportunities
for customers within and outside the Company's service area. At the time the
Company makes a sales commitment to one of these customers, the Company attempts
to cover this position immediately with gas purchase commitments matched to the
terms of the related sales contract. The non-regulated subsidiaries attempt to
minimize their exposure to price volatility by predetermining the gross profit
on their sales at the time of each sales commitment.
None of the Company's gas contracts is accounted for using the fair value
method of accounting. While some of the Company's gas purchase contracts meet
the definition of a derivative, the Company has designated these contracts as
"normal purchases" under SFAS No. 133, "Accounting for Derivatives".
Delta is exposed to risk resulting from changes in interest rates on its
variable rate notes payable. The interest rate on the notes payable is
benchmarked to the monthly London Interbank Offered Rate. Delta's outstanding
notes payable amounted to $19,355,000 and $16,800,000, as of June 30, 2002 and
2001, respectively. Based on the amount of the outstanding notes payable on June
30, 2002, a one percent increase (decrease) in average interest rates would
result in a decrease (increase) in annual pre-tax net income of $194,000. See
(6) of the Notes to Consolidated Financial Statements.
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 24
Report of Independent Public Accountants 25
Consolidated Statements of Income for the years ended
June 30, 2002, 2001, and 2000 27
Consolidated Statements of Cash Flows for the years ended
June 30, 2002, 2001 and 2000 28
Consolidated Balance Sheets as of June 30, 2002 and 2001 30
Consolidated Statements of Changes in Shareholders'
Equity for the years ended June 30, 2002, 2001, and 2000 32
Consolidated Statements of Capitalization as of
June 30, 2002 and 2001 33
Notes to Consolidated Financial Statements 34
Schedule II - Valuation and Qualifying Accounts for the
years ended June 30, 2002, 2001, and 2000 46
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.
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
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 and 13 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 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(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(a) - Delta's Amended and Restated Articles of Incorporation
are incorporated herein by reference to Exhibit 3(a) to
Delta's Form 10-Q for the period ended March 31, 1990.
3(b) - Delta's By-Laws as amended August 21, 1996 are incorporated
herein by reference to Exhibit 3(b) to Delta's Form 10-K for
the period ended June 30, 1996.
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
dated September 2, 1993.
4(b) - The Indenture dated July 1, 1996 in respect of 8.3%
Debentures due August 1, 2026, is incorporated
herein by reference to Exhibit 4(c) to Delta's Form S-2 dated
June 21, 1996.
4(c) - 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 dated March 11, 1998.
10(a) - Certain of Delta's material natural gas supply contracts are
incorporated herein by reference to Exhibit 10 to Delta's
Form 10 for the year ended June 30, 1978 and by reference
to Exhibits C and D to Delta's Form 10-K for the year ended
June 30, 1980.
10(b) - Assignment to Delta by Wiser of its Columbia Service Agreement,
including a copy of said Service Agreement, is incorporated here-
in by reference to Exhibit 2(D) to Delta's Form 8-K dated
February 9, 1981.
10(c) - Contract between Tennessee and Delta (amends earlier contract
for Nicholasville and Wilmore Service Areas) is incorporated
herein by reference to Exhibit 10(d) to Delta's Form 10-Q for
the period ended September 30, 1990.
10(d) - Contract between Tennessee and Delta (amends earlier contract
for Jeffersonville Service Area) is incorporated herein by
reference to Exhibit 10(e) to Delta's Form 10-Q for the
period ended September 30, 1990.
10(e) - Contract between Tennessee and Delta (amends earlier contract
for Salt Lick Service Area) is incorporated herein by reference
to Exhibit 10(f) to Delta's Form 10-Q for the period
ended September 30, 1990.
10(f) - Contract between Tennessee and Delta (amends earlier contract
for Berea Service Area) is incorporated herein by reference to
Exhibit 10(g) to Delta's Form 10-Q for the period ended
September 30, 1990.
10(g) - Service Agreements between Columbia and Delta (amends
earlier service agreements for Cumberland, Stanton and
Owingsville service areas) are incorporated herein by
reference to Exhibit 10(h) to Delta's Form 10-Q for the
period ended September 30, 1990.
10(h) - Employment agreements between Delta 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 Delta's Form
10-Q for the period ended March 31, 2000.
10(i) - Agreement between Delta and Harrison D. Peet, Chairman of the
Board, is incorporated herein by reference to Exhibit 10(l)
to Delta's Form 10-Q for the period ended March 31, 2000.
12 - Computation of the Consolidated Ratio of Earnings to Fixed
Charges.
16 - Letter dated May 22, 2002 to the Securities and Exchange
Commission is incorporated herein by reference as
Exhibit 16 to Delta's Form 8-K dated May 22, 2002.
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Public Accountants.
(b) Reports on 8-K.
On May 22, 2002, the Company filed a Form 8-K reporting the change in the
Company's Auditor.
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 9th day of
September, 2002.
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 9, 2002
(Glenn R. Jennings) Officer and Vice Chairman
of the Board
(ii) Principal Financial Officer:
/s/John F. Hall Vice-President - Finance, September 9, 2002
(John F. Hall) Secretary and Treasurer
(iii) Principal Accounting Officer:
/s/John B. Brown Controller September 9, 2002
(John B. Brown)
(iv) A Majority of the Board of Directors:
/s/H. D. Peet Chairman of the Board September 9, 2002
(H. D. Peet)
/s/Donald R. Crowe Director September 9, 2002
(Donald R. Crowe)
/s/Jane Hylton Green Director September 9, 2002
(Jane Hylton Green)
/s/Lanny D. Greer Director September 9, 2002
(Lanny D. Greer)
/s/Billy Joe Hall Director September 9, 2002
(Billy Joe Hall)
/s/Lewis N. Melton Director September 9, 2002
(Lewis N. Melton)
/s/Arthur E. Walker, Jr. Director September 9, 2002
(Arthur E. Walker, Jr.)
/s/Michael R. Whitley Director September 9, 2002
(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 and
liabilities and the disclosure of contingent assets and liabilities at the date
of the financial statements and revenues and expenses 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 Deloitte
& Touche LLP, the independent auditors, 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 & Chief Vice President - Finance, Controller
Executive Officer Secretary & Treasurer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders
of Delta Natural Gas Company, Inc.:
We have audited the accompanying consolidated balance sheet of Delta Natural Gas
Company, Inc. and subsidiary companies (the "Company") as of June 30, 2002, and
the related consolidated statements of capitalization, income, cash flows and
changes in shareholders' equity for the year ended June 30, 2002. Our audit also
included the 2002 financial statement schedule listed on the index at Item 14.
These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Delta Natural Gas Company, Inc. and
subsidiary companies as of June 30, 2002, and the results of its operations and
its cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States of America. Also, in our opinion, the
2002 financial statement schedule, when considered in relation to the basic 2002
consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio
August 19, 2002
Report of Previous Independent Public Accountants
THE FOLLOWING REPORT IS A COPY OF A REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
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, INC. (a Kentucky corporation)
and subsidiary companies as of June 30, 2001 and 2000, and the related
consolidated statements of income, cash flows and changes in shareholders'
equity for each of the three years in the period ended June 30, 2001. These
financial statements and the schedule referred to below are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the 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, the financial statements referred to above present fairly,
in all material respects, the financial position of Delta Natural Gas Company,
Inc. and subsidiary companies as of June 30, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended June 30, 2001, in conformity with accounting principles generally accepted
in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the Index to
Consolidated Financial Statements and Schedule is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
Arthur Andersen LLP
Louisville, Kentucky
August 10, 2001
Delta Natural Gas Company, Inc. and Subsidiary Companies
Consolidated Statements of Income
For the Years Ended June 30, 2002 2001 2000
Operating Revenues $ 55,929,780 $ 70,770,156 $45,926,775
------------ ------------ -----------
Operating Expenses
Purchased gas $ 30,157,225 $ 44,707,739 $21,214,834
Operation and maintenance 9,685,746 9,844,728 9,139,143
Depreciation and depletion 4,080,944 3,840,450 3,989,090
Taxes other than income
taxes 1,354,913 1,423,020 1,338,486
Income taxes (Note 3) 2,249,500 2,232,500 2,068,500
------------ ------------ ---------
Total operating expenses $ 47,528,328 $ 62,048,437 $37,750,053
------------ ------------ -----------
Operating Income $8,401,452 $8,721,719 $ 8,176,722
Other Income and Deductions, Net 17,018 31,141 42,866
------------ ------------ ------------
Income Before Interest Charges $8,418,470 $8,752,860 $ 8,219,588
---------- ---------- -----------
Interest Charges
Interest on long-term debt $3,728,847 $3,775,856 $ 3,845,565
Other interest 891,750 1,179,949 748,006
Amortization of debt expense 161,160 161,160 161,160
------------ ----------- -----------
Total interest charges $4,781,757 $5,116,965 $ 4,754,731
---------- ---------- -----------
Net Income $3,636,713 $3,635,895 $ 3,464,857
========== ========== ===========
Weighted Average Number of
Common Shares Outstanding
(Basic and Diluted) 2,513,804 2,477,983 2,433,397
Basic and Diluted Earnings
Per Common Share $ 1.45 $ 1.47 $ 1.42
Dividends Declared Per
Common Share $ 1.16 $ 1.14 $ 1.14
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, 2002 2001 2000
Cash Flows From Operating Activities
Net income $ 3,636,713 $ 3,635,895 $ 3,464,857
Adjustments to reconcile net
income to net cash from
Operating activities
Depreciation, depletion and
Amortization 4,354,396 4,047,715 4,240,595
Deferred income taxes and
Investment tax credits 1,110,916 2,332,458 1,446,444
Other - net 595,894 700,091 841,877
(Increase) decrease in assets
Accounts receivable 1,767,741 (1,860,926) (1,160,957)
Gas in storage (556,871) (1,665,124) 48,005
Deferred (advance recovery of)
gas cost 368,648 (4,518,953) (1,124,219)
Materials and supplies 69,663 (129,278) 200,689
Prepayments 681,195 (690,662) (51,964)
Other assets (1,551,055) (333,402) (561,893)
Increase (decrease) in
liabilities
Accounts payable (1,524,216) 1,647,056 1,630,760
Refunds due customers 35,653 (5,708) 2,679
Accrued taxes (44,503) (521,190) 284,891
Other current liabilities 128,283 11,340 (302,553)
Other liabilities 1,439,439 3,260 (131,706)
----------- ------------ ------------
Net cash provided by
operating activities $10,511,896 $ 2,652,572 $ 8,827,505
----------- ----------- ------------
Cash Flows From Investing Activities
Capital expenditures $(9,421,765) $(7,069,713) $ (8,795,653)
------------ ------------ ------------
Net cash used in investing
activities $(9,421,765) $(7,069,713) $ (8,795,653)
------------ ----------- ------------
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, 2002 2001 2000
Cash Flows From Financing
Activities
Dividends on common stock $(2,916,418) $ (2,825,267) $ (2,777,372)
Issuance of common stock, net 707,422 646,514 697,926
Repayment of long-term debt (1,375,000) (810,999) (1,735,000)
Issuance of notes payable 36,860,000 52,415,000 27,810,000
Repayment of notes payable (34,305,000) (45,240,000) (23,880,000)
----------- ------------ ------------
Net cash provided by
financing activities $(1,028,996) $ 4,185,248 $ 115,554
----------- ------------ ------------
Net Increase (Decrease) in Cash and
Cash Equivalents $ 61,135 $ (231,893) $ 147,406
Cash and Cash Equivalents,
Beginning of Year 164,101 395,994 248,588
----------- ------------ ------------
Cash and Cash Equivalents,
End of Year $ 225,236 $ 164,101 $ 395,994
=========== ============ ============
Supplemental Disclosures of Cash
Flow Information
Cash paid during the year for
Interest $ 4,636,051 $ 4,970,327 $ 4,626,542
Income taxes (net of refunds) $ 1,130,566 $ 395,737 $ 533,908
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, 2002 2001
Assets
Gas Utility Plant, at cost $156,305,063 $147,792,390
Less - Accumulated provision for
depreciation (49,142,976) (45,375,230)
------------ ------------
Net gas plant $107,162,087 $102,417,160
------------ ------------
Current Assets
Cash and cash equivalents $ 225,236 $ 164,101
Accounts receivable, less accumulated
provisions for doubtful accounts of
$165,000 and $575,000 in 2002 and
2001, respectively 2,884,025 4,651,766
Gas in storage, at average cost 5,216,772 4,659,901
Deferred gas costs 4,076,059 4,444,707
Materials and supplies, at first-in,
first-out cost 523,756 593,419
Prepayments 388,794 1,090,515
------------ ------------
Total current assets 13,314,642 $ 15,604,409
------------ ------------
Other Assets
Cash surrender value of officers' life
insurance (face amount of $1,236,009) $ 344,687 $ 354,891
Note receivable from officer 158,000 128,000
Prepaid pension, unamortized debt expense
and other (Notes 4 and 7) 6,969,109 5,674,678
------------ ------------
Total other assets $ 7,471,796 $ 6,157,569
------------ ------------
Total assets $127,948,525 $124,179,138
============ ============
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, 2002 2001
Liabilities and Shareholders' Equity
Capitalization (See Consolidated Statements
of Capitalization)
Common shareholders' equity $ 34,182,277 $ 32,754,560
Long-term debt (Notes 7 and 8) 48,600,000 49,258,902
---------- ----------
Total capitalization $ 82,782,277 $ 82,013,462
------------ ------------
Current Liabilities
Notes payable (Note 6) $ 19,355,000 $ 16,800,000
Current portion of long-term
debt (Notes 7 and 8) 1,750,000 2,450,000
Accounts payable 4,077,983 5,602,199
Accrued taxes 673,873 718,376
Refunds due customers 73,973 38,320
Customers' deposits 440,568 418,582
Accrued interest on debt 1,162,956 1,178,410
Accrued vacation 558,066 538,595
Other accrued liabilities 503,178 400,898
------- ----------
Total current liabilities $ 28,595,597 $ 28,145,380
------------ ------------
Deferred Credits and Other
Deferred income taxes $ 14,078,273 $ 12,851,457
Investment tax credits 404,600 449,800
Regulatory liability (Note 3) 562,025 632,725
Additional minimum pension
liability (Note 4) 1,461,440 --
Advances for construction and other 64,313 86,314
----------- ----------
Total deferred credits and other $ 16,570,651 $ 14,020,296
------------ ------------
Commitments and Contingencies (Note 9) ____________ ____________
Total liabilities and
shareholders' equity $127,948,525 $124,179,138
============ ============
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, 2002 2001 2000
Common Shares
Balance, beginning of year $ 2,495,679 $ 2,459,067 $ 2,413,942
$1.00 par value of 34,400, 36,612,
and 45,125 shares issued in 2002,
2001 and 2000, respectively
Dividend reinvestment and stock
purchase plan 28,506 28,958 37,499
Employee stock purchase plan and
other 5,894 7,654 7,626
------------ ------------ ------------
Balance, end of year $ 2,530,079 $ 2,495,679 $ 2,459,067
============ ============ ============
Premium on Common Shares
Balance, beginning of year $ 29,657,308 $ 29,038,995 $ 28,386,194
Premium on issuance of common shares
Dividend reinvestment and stock
purchase plan 561,547 503,897 533,760
Employee stock purchase plan and
other 111,475 114,416 119,041
------------ ------------ ------------
Balance, end of year $ 30,330,330 $ 29,657,308 $ 29,038,995
============ ============ ============
Capital Stock Expense
Balance, beginning of year $ (1,925,431) $ (1,917,020) $ (1,917,020)
Dividend reinvestment and stock
purchase plan - (8,411) -___
------------- ------------ ---------
Balance, end of year $ (1,925,431) $ (1,925,431) $ (1,917,020)
============= ============ ============
Retained Earnings
Balance, beginning of year $ 2,527,004 $ 1,716,376 $ 1,028,891
Net income 3,636,713 3,635,895 3,464,857
Cash dividends declared on common
shares (See Consolidated
Statements of Income for rates) (2,916,418) (2,825,267) (2,777,372)
------------ ------------ ------------
Balance, end of year $ 3,247,299 $ 2,527,004 $ 1,716,376
============ ============ ============
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, 2002 2001
Common Shareholders' Equity
Common shares, par value $1.00 per share
(Notes 4 and 5)
Authorized 6,000,000 shares
Issued and outstanding 2,530,079 and
2,495,679 shares in 2002 and
2001, respectively $ 2,530,079 $ 2,495,679
Premium on common shares 30,330,330 29,657,308
Capital stock expense (1,925,431) (1,925,431)
Retained earnings (Note 7) 3,247,299 2,527,004
----------- -----------
Total common shareholders' equity $34,182,277 $32,754,560
----------- -----------
Long-Term Debt (Notes 7 and 8)
Debentures, 8.3%, due 2026 $14,816,000 $14,821,000
Debentures, 6 5/8%, due 2023 11,445,000 11,933,000
Debentures, 7.15%, due 2018 24,089,000 24,271,000
Promissory note from acquisition of under-
ground storage, non-interest bearing,
due through 2001 (less unamortized
discount of $16,098 in 2001) - 683,902
------------ -----------
Total long-term debt $50,350,000 $51,708,902
Less amounts due within one year,
included in current liabilities (1,750,000) (2,450,000)
----------- -----------
Net long-term debt $48,600,000 $49,258,902
----------- -----------
Total capitalization $82,782,277 $82,013,462
=========== ===========
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") has 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.
(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 The Company determines its provision for depreciation
using the straight-line method and by the application of rates to various
classes of utility plant. The rates are based upon the estimated service lives
of the properties and were equivalent to composite rates of 2.9%, 2.8% and 3.1%
of average depreciable plant for 2002, 2001 and 2000, respectively.
(d) Maintenance All expenditures for maintenance and repairs of units of
property are charged to the appropriate maintenance expense accounts. 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 and also for the net cost of removal.
(e) Gas Cost Recovery Delta has 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. The Company
expenses 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 The Company records revenues as billed to its
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.
(g) Revenues and Customer Receivables The Company serves 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 The Company's 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 by the
Company as regulatory assets and regulatory liabilities are as follows:
Regulatory assets ($000) 2002 2001
---- ----
Deferred gas cost 4,076 4,445
Loss on extinguishment of debt 1,337 1,395
Rate case and gas audit expense 116 142
------ ------
Total regulatory assets 5,529 5,982
===== =====
Regulatory liabilities ($000)
Refunds from suppliers that are due customers 74 38
Regulatory liability for deferred income taxes 562 633
------ -------
Total regulatory liabilities 636 671
====== =======
The Company is currently earning a return on loss on extinguishment of debt
and rate case expenses. Deferred gas costs are presented every three months to
the PSC for recovery in accordance with the gas cost recovery rate mechanism.
(2) New Accounting Pronouncements
Effective June, 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No.
141 eliminates the pooling-of-interests method and requires all business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method. It also requires intangible assets acquired in a business
combination to be recognized separately from goodwill. SFAS No. 141 had no
impact on the Company's financial position or results of operations with respect
to business combination transactions that occurred prior to June 30, 2001. SFAS
No. 142 addresses how goodwill and other intangible assets should be accounted
for upon their acquisition and afterwards. The primary impact of SFAS No. 142 is
that future goodwill and intangible assets with indefinite lives will no longer
be amortized beginning in 2002. Instead of amortization, goodwill will be
subject to an assessment for impairment by applying a fair-value-based test
annually and more frequently if circumstances indicate a possible impairment. If
the carrying amount of goodwill exceeds the fair value of that goodwill, an
impairment loss is recognized in an amount equal to the excess. The Company does
not have recorded goodwill or intangible assets. Accordingly, these new
accounting rules will not presently have a significant impact on the Company.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", which is required to be adopted July 1, 2002. SFAS No.
143 addresses asset retirement obligations that result from the acquisition,
construction or normal operation of long-lived assets. It requires companies to
recognize asset retirement obligations as a liability when the liability is
incurred at its fair value. Adoption of SFAS No. 143 is not expected to have a
significant impact on the Company.
In August, 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets", which is required to be adopted
July 1, 2002. SFAS No. 144 supercedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" and
APB Opinion No. 30, "Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions" and combines the two accounting models into a single model based
on the framework established in SFAS No. 121. Adoption of SFAS No. 144 will not
have a significant impact on the Company.
The American Institute of Certified Public Accountants has issued an
exposure draft Statement of Position ("SOP") "Accounting for Certain Costs and
Activities Related to Property, Plant, and Equipment". This proposed SOP applies
to all nongovernmental entities that acquire, construct or replace tangible
property, plant and equipment ("PP&E") including lessors and lessees. A
significant element of the SOP requires that entities use component accounting
for PP&E to the extent future component replacement will be capitalized. At
adoption, entities would have the option to apply component accounting
retroactively for all PP&E assets, to the extent applicable, or to apply
component accounting as an entity incurs capitalizable costs that replace all or
a portion of PP&E. The proposed effective date of the SOP is January 1, 2003.
The Company is currently analyzing the impact of this proposed SOP.
(3) Income Taxes
The Company provides 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 purposes, differences in
recognition of purchased gas cost recoveries and certain other 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. The
Company utilizes 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. The change in tax rates applied to accumulated deferred
income taxes may not be immediately recognized in operating results because of
ratemaking treatment. A regulatory liability has been established to recognize
the future revenue requirement impact from these deferred taxes. The temporary
differences which gave rise to the net accumulated deferred income tax liability
for the periods are as follows:
2002 2001
---- ----
Deferred Tax Liabilities
Accelerated depreciation $ 13,436,373 $12,440,957
Deferred gas cost 1,364,800 1,444,200
Accrued pension 1,104,200 1,157,200
Debt expense 406,300 426,900
------------ -----------
Total $ 16,311,673 $15,469,257
------------ -----------
Deferred Tax Assets
Alternative minimum tax credits $ 1,365,200 $ 1,701,100
Regulatory liabilities 221,700 249,600
Investment tax credits 159,600 177,400
Other 486,900 489,700
----------- -----------
Total $2,233,400 $ 2,617,800
---------- -----------
Net accumulated deferred
income tax liability $ 14,078,273 $12,851,457
============ ===========
The components of the income tax provision are comprised of the following
for the years ended June 30:
2002 2001 2000
---- ---- ----
Components of Income Tax Expense
Current
Federal $ 776,200 $ (77,000) $ 568,100
State 296,100 (71,700) 137,500
----------- ----------- -----------
Total $ 1,072,300 $ (148,700) $ 705,600
Deferred 1,177,200 2,381,200 1,362,900
----------- ----------- -----------
Income tax expense $ 2,249,500 $ 2,232,500 $ 2,068,500
=========== =========== ===========
Reconciliation of the statutory federal income tax rate to the effective
income tax rate is shown in the table below:
2002 2001 2000
---- ---- ----
Statutory federal income tax rate 34.0 % 34.0 % 34.0 %
State income taxes net of federal benefit 5.3 5.4 5.2
Amortization of investment tax credits (0.8) (0.9) (1.1)
Other differences - net (0.2) (0.3) (0.4)
------ ------ -----
Effective income tax rate 38.3 % 38.2 % 37.7 %
======= ====== ======
(4) Employee Benefit Plans
(a) Defined Benefit Retirement Plan Delta has 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. The following table provides a
reconciliation of the changes in the plans' benefit obligations and fair
value of assets over the two-year period ended March 31, 2002, and a
statement of the funded status as of March 31 of both years, as recognized
in the Company's consolidated balance sheets at June 30:
2002 2001
---- ----
Change in Benefit Obligation
Benefit obligation at beginning of year $ 8,486,103 $ 8,188,361
Service cost 518,496 487,392
Interest cost 657,126 592,537
Amendments 1,514,620 --
Actuarial loss (84,009) 332,610
Benefits paid (411,217) (1,114,797)
------------ ------------
Benefit obligation at end of year $ 10,681,119 $ 8,486,103
------------ ------------
Change in Plan Assets
Fair value of plan assets at beginning of year $ 9,073,398 $ 10,176,049
Actual return (loss) on plan assets 14,243 (636,591)
Employer contribution 543,255 648,737
Benefits paid (411,217) (1,114,797)
------------ ------------
Fair value of plan assets at end of year $ 9,219,679 $ 9,073,398
------------ ------------
Funded status $ (1,461,440) $ 587,295
Unrecognized net actuarial loss 2,272,764 1,652,236
Unrecognized prior service cost 1,514,620 --
Net transition asset -- (29,262)
------------- ------------
Net pension asset $ 2,325,944 $ 2,210,269
============ ============
In addition, the Company has recognized an additional minimum pension
liability of $1,461,440 and a corresponding intangible pension asset in the
accompanying balance sheet as of June 30, 2002. Effective April 1, 2002, the
Company adopted a plan amendment which enhanced the formula for benefits paid
under the plan.
The assets of the plan consist primarily of common stocks, bonds and
certificates of deposit. Net pension costs for the years ended June 30 include
the following:
2002 2001 2000
---- ---- ----
Components of Net Periodic Benefit Cost
Service cost $ 518,496 $ 487,392 $ 535,681
Interest cost 657,125 592,537 538,400
Expected return on plan assets (755,307) (800,303) (764,449)
Amortization of unrecognized net loss 36,528 -- --
Amortization of net transition asset (29,262) (42,394) (42,394)
--------- --------- ---------
Net periodic benefit cost $ 427,580 $ 237,232 $ 267,238
========= ========= =========
Weighted-Average Assumptions
Discount rate 7.50% 7.75% 7.75%
Expected return on plan assets 8.00% 8.00% 8.00%
Rate of compensation increase 4.00% 4.00% 4.00%
During the plan year ended March 31, 2000, Delta eliminated 16 positions in
conjunction with a workforce reduction plan. Subsequently, 7 additional
positions were eliminated as a result of reorganization of Delta's branch
offices, which was completed by June 30, 2000. These events constituted a
curtailment under SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits". The
combined impact of the curtailment gain, the savings in salary expense, and the
cost of one time payments made to severed employees was not material to results
of operations in 2000.
SFAS No. 106, "Employers' Accounting for Post-Retirement Benefits", and
SFAS No. 112, "Employers' Accounting for Post-Employment Benefits", do not
affect the Company, as Delta does not provide benefits for post-retirement or
post-employment other than the pension plan for retired employees.
(b) Employee Savings Plan The Company has an Employee Savings Plan
("Savings Plan") under which eligible employees may elect to contribute any
whole percentage between 2% and 15% of their annual compensation. The Company
will match 50% of the employee's contribution up to a maximum Company
contribution of 2.5% of the employee's annual compensation. For 2002, 2001, and
2000, Delta's Savings Plan expense was $165,500, $154,600, and $170,800,
respectively.
(c) Employee Stock Purchase Plan The Company has an Employee Stock Purchase
Plan ("Stock Plan") under which qualified permanent employees are eligible to
participate. Under the terms of the Stock Plan, such employees can 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. The Company issues 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 matches those shares so purchased. Therefore,
stock with an equivalent market value of $96,300 was issued in July, 2002. The
continuation and terms of the Stock Plan are subject to approval by Delta's
Board of Directors on an annual basis. Delta's Board has continued the Stock
Plan through June 30, 2003.
(5) Dividend Reinvestment and Stock Purchase Plan
The Company's 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 the Company issued 28,506,
28,958, and 37,499 shares in 2002, 2001, and 2000, respectively. Delta reserved
150,000 shares for issuance under the Reinvestment Plan in December, 2000, and
as of June 30, 2002 there were 106,266 shares still available for issuance.
(6) Notes Payable and Line of Credit
The current available line of credit is $40,000,000, of which $19,355,000
and $16,800,000 was borrowed having a weighted average interest rate of 3.67%
and 6.97% as of June 30, 2002 and 2001, respectively. The maximum amount
borrowed during 2002 and 2001 was $29,005,000 and $21,445,000, 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%. The current line of credit must be renewed during October, 2002.
(7) Long-Term Debt
In March, 1998 Delta 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 the Company after
April 1, 2003. Restrictions under the indenture agreement covering the 7.15%
Debentures include, among other things, a restriction whereby dividend payments
cannot be made unless consolidated shareholders' equity of the Company exceeds
$21,500,000. No retained earnings are restricted under the provisions of the
indenture.
In July, 1996 Delta issued $15,000,000 of 8.3% Debentures that mature in
July, 2026. Redemption on behalf of deceased holders within 60 days of notice of
up to $25,000 per holder will be made annually, subject to an annual aggregate
limitation of $500,000. The 8.3% Debentures can be redeemed by the Company
beginning in August, 2001 at a 5% premium, such premium declining ratably until
it ceases in August, 2006.
In October, 1993 Delta 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
the Company beginning in October, 1998 at a 5% premium, such premium declining
ratably until it ceases in October, 2003. The Company may not assume any
additional mortgage indebtedness in excess of $2 million without effectively
securing the 6 5/8% Debentures equally to such additional indebtedness.
The Company amortizes debt issuance expenses over the life of the related
debt on a straight-line basis, which approximates the effective yield method.
(8) Fair Values of Financial Instruments
The fair value of the Company's debentures is estimated using discounted
cash flow analysis, based on the Company's current incremental borrowing rates
for similar types of borrowing arrangements. The fair value of the Company's
debentures at June 30, 2002 and 2001 was estimated to be $47,479,000 and
$48,429,000, respectively. The carrying amount in the accompanying consolidated
financial statements as of June 30, 2002 and 2001 is $50,350,000 and
$51,025,000, respectively.
The carrying amount of the Company's other financial instruments including
cash equivalents, accounts receivable, notes receivable, accounts payable and
the non-interest bearing promissory note approximate their fair value.
(9) Commitments and Contingencies
The Company has entered into individual employment agreements with its five
officers and an agreement with the Chairman of the Board. 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.
(10) Rates
Delta's retail natural gas distribution and its transportation services are
subject to the regulatory authority of the Public Service Commission of Kentucky
("PSC") with respect to various aspects of Delta's business, including rates and
service to retail and transportation customers. Delta monitors the need to file
a general rate case as a way to adjust its sales prices.
On December 27, 1999, Delta received approval from the PSC for an annual
revenue increase of $420,000. This resulted from Delta's last rate case that was
filed by Delta in July, 1999. The approval included a weather normalization
provision that permits Delta to adjust base rates for the billing months of
December through April to reflect variations from normal winter weather.
Delta's rates include a Gas Cost Recovery ("GCR") clause, which permits
changes in Delta's gas supply costs to be reflected in the rates charged to
customers. The GCR requires Delta to make quarterly filings with the PSC, but
such procedure does not require a general rate case.
During July, 2001, the PSC required an independent audit of the gas
procurement activities of Delta and four other gas distribution companies as
part of its investigation of increases in wholesale natural gas prices and their
impacts on customers. The PSC 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 a
reliable supply of natural gas at reasonable costs. The PSC noted the events of
the prior year, including changes in natural gas wholesale markets, and required
the audits 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 consultants that were selected by the PSC are currently
completing this audit. Delta has received a draft of the consultant's report and
is in the process of reviewing and commenting on it. The draft report contains
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, GCR mechanisms, budget billing, uncollectible accounts
and forecasting. Delta cannot predict how the PSC will interpret or act on any
audit recommendations. As a result, Delta cannot predict the impact of this
regulatory proceeding on the Company's financial position or results of
operations.
In addition to PSC regulation, Delta may obtain non-exclusive franchises
from the cities and communities in which it operates authorizing it to place its
facilities in the streets and public grounds. No utility may obtain a franchise
until it has obtained approval from the PSC to bid on a local franchise. Delta
holds franchises in four of the cities and seven other communities it serves. In
the other cities and communities served by Delta, either Delta's 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. Delta attempts to acquire or reacquire franchises whenever
feasible.
Without a franchise, a local government could require Delta to cease its
occupation of the streets and public grounds or prohibit Delta from extending
its facilities into any new area of that city or community. To date, the absence
of a franchise has had no adverse effect on Delta's operations.
(11) Operating Segments
The 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 represents Delta and the non-regulated segment
consists of Resources, Delgasco and Enpro. The Company operates in a single
geographic area of central and southeastern Kentucky.
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 2002.
Intersegment transportation revenue and expense is recorded at Delta's tariff
rates. Transfer pricing for sales of gas between segments is at cost. Operating
expenses, taxes and interest are allocated to the non-regulated segment.
Segment information is shown below for the periods:
($000) 2002 2001 2000
---- ---- ----
Revenues
Regulated
External customers 40,370 48,887 33,314
Intersegment 3,050 3,244 4,606
------- --------- --------
Total regulated 43,420 52,131 37,920
Non-regulated
External customers 15,560 21,883 12,613
Intersegment 1,688 27,609 16,249
------- --------- --------
Total non-regulated 17,248 49,492 28,862
Eliminations for intersegment (4,738) (30,853) (20,855)
-------- -------- --------
Total operating revenues 55,930 70,770 45,927
======= ========= ========
Operating Expenses
Regulated
Depreciation 3,964 3,797 3,940
Income taxes 1,599 1,696 1,657
Other 30,485 38,662 24,792
------- --------- --------
Total regulated 36,048 44,155 30,389
------- --------- --------
Non-regulated
Depreciation 117 43 49
Income taxes 651 536 412
Other 15,450 48,167 27,755
------- --------- --------
Total non-regulated 16,218 48,746 28,216
Eliminations for intersegment (4,738) (30,853) (20,855)
-------- -------- --------
Total operating expenses 47,528 62,048 37,750
======= ========= ========
($000) 2002 2001 2000
---- ---- ----
Other Income and Deductions
Regulated 17 31 43
Non-regulated - - -
--------- --------- ------
Total other income 17 31 43
and deductions ======== ========= ========
Interest Charges
Regulated 4,768 5,191 4,766
Non-regulated 25 42 41
Eliminations for intersegment (11) (116) (52)
-------- -------- --------
Total interest charges 4,782 5,117 4,755
======== ========= ========
Net Income
Regulated 2,621 2,817 2,808
Non-regulated 1,016 819 657
-------- --------- --------
Total net income 3,637 3,636 3,465
======== ========= ========
Assets
Regulated 124,764 120,710 108,876
Non-regulated 1,723 3,469 4,043
-------- --------- --------
Total assets 126,487 124,179 112,919
======== ========= ========
Capital Expenditures
Regulated 9,415 7,070 8,796
Non-regulated 7 - -
--------- --------- ------
Total capital expenditures 9,422 7,070 8,796
======== ========= ========
(12) 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)
Operating Operating Net Income per Common
Revenues Income (Loss) Share(a)
Quarter Ended
Fiscal 2002
September 30 $ 7,258,892 $ 479,305 $ (778,325) $ (.31)
December 31 12,580,389 1,880,382 591,751 .24
March 31 25,158,025 4,843,984 3,745,226 1.49
June 30 10,932,474 1,197,781 78,061 .03
Fiscal 2001
September 30 $ 6,722,188 $ 152,070 $ (1,055,810) $ (.43)
December 31 16,941,117 2,081,843 765,633 .31
March 31 32,330,755 5,315,853 3,983,175 1.60
June 30 14,776,096 1,171,953 (57,103) (.02)
(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, 2002, 2001 AND 2000
Column A Column B Column C Column D Column E
Additions Deductions
- --------------------------- ------------- ------------------------- ------------- -----------
Balance Charged to
at Charged to Other Amounts Balance
Beginning Costs and Accounts- Charged Off at End
Description of Period Expenses Recoveries or Paid of Period
----------- --------- ------------ ------------- ------------
Deducted From the Asset to
Which it Applies - Allowance
for doubtful accounts for
the years ended:
June 30, 2002 $ 575,000 $ 153,074 $ 63,832 $ 626,906 $ 165,000
June 30, 2001 $ 144,380 $ 810,432 $ 40,565 $ 420,377 $ 575,000
June 30, 2000 $ 138,514 $ 213,000 $ 39,086 $ 246,220 $ 144,380
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
COMPUTATION OF THE CONSOLIDATED RATIO OF EARNINGS
TO FIXED CHARGES
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Earnings
Net income $ 3,636,713 $ 3,635,895 $ 3,464,858 $ 2,150,794 $ 2,451,272
Provisions for income
Taxes 2,249,500 2,232,500 2,068,500 1,239,100 1,401,000
Fixed charges 4,781,757 5,116,965 4,754,731 4,534,936 4,348,498
----------- ----------- ----------- ----------- ---------
Total $10,667,970 $10,985,360 $10,288,089 $ 7,924,830 $ 8,200,770
=========== =========== =========== =========== ===========
Fixed Charges
Interest on debt $ 4,620,597 $ 4,955,805 $ 4,593,571 $4,373,776 $4,223,946
Amortization of debt
Expense 161,160 161,160 161,160 161,160 124,552
----------- ----------- ----------- ----------- -------
Total $ 4,781,757 $ 5,116,965 $ 4,754,731 $ 4,534,936 $ 4,348,498
=========== =========== =========== =========== ===========
Ratio of earnings to
fixed charges 2.23x 2.15x 2.16x 1.75x 1.89x
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 PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in Registration Statement No.
333-52542 of Delta Natural Gas Company, Inc. on Form S-3 of our report dated
August 19, 2002, appearing in this Form 10-K of Delta Natural Gas Company, Inc.
for the year ended June 30, 2002.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio
September 6, 2002