AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 13, 2002
REGISTRATION NO. 333-100852
PRE-EFFECTIVE
AMENDMENT NO. 1
TO
FORM S-2
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
KENTUCKY 61-0458329
(State or other jurisdiction (IRS Employer Identification No.)
of incorporation or organization)
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COPIES TO:
RUTHEFORD B CAMPBELL, JR., ESQ. JOHN L. GILLIS, JR., ESQ.
J. DAVID SMITH, JR., ESQ. Armstrong Teasdale LLP
Stoll, Keenon & Park, LLP One Metropolitan Square
300 West Vine St., Suite 2100 St. Louis, MO 63102
Lexington, KY 40507 (314) 621-5070
(859) 231-3000
----------------------
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As
soon as practicable after the effective date of this Registration Statement.
SUBJECT TO COMPLETION, DATED DECEMBER 13, 2002
***************************************************************************** THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES, AND IT IS NOT SOLICITING OFFERS TO BUY THESE SECURITIES IN ANY STATE IN WHICH THE OFFER OR SALE IS NOT PERMITTED. *****************************************************************************
PROSPECTUS
[DELTA LOGO] DELTA NATURAL GAS COMPANY, INC.
$20,000,000 % DEBENTURES DUE 2023
We are offering $20,000,000 of our % Debentures due in 2023. We will receive all the net proceeds from this sale.
We will pay interest on the % Debentures quarterly. The Debentures will mature on January 1, 2023.
We have the right to redeem your Debentures at any time after , 2007. If we elect to redeem your Debentures in the first year after , 2007, we are required to pay you 102% of the principal value of your Debentures. If we redeem during the next year, we must pay you 101% of the principal value of your Debentures. After , 2009, we may redeem your Debentures at 100% of their principal value. In all redemptions, we also must pay you any accrued but unpaid interest on your Debentures. We will also redeem the Debentures, subject to limitations, at the option of the representative of any deceased beneficial owner of the Debentures.
There is no market for these Debentures, and we can give no assurance that a market will develop.
INVESTING IN OUR DEBENTURES INVOLVES RISKS. SEE "RISK FACTORS" ON
PAGE 5.
================================================================================
PER $1,000
DEBENTURE TOTAL
--------------------------------------------------------------------------------
Public offering price $ 1,000.00 $20,000,000.00
--------------------------------------------------------------------------------
Underwriting discount $ $
--------------------------------------------------------------------------------
Proceeds, before our expenses $ $
================================================================================
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NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
We expect the Debentures will be ready for delivery on or about .
EDWARD D. JONES & CO.,L.P.
THE DATE OF THIS PROSPECTUS IS , 2002.
TABLE OF CONTENTS
Prospectus Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Forward Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . 7
Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . 10
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Description of Debentures. . . . . . . . . . . . . . . . . . . . . . . . . . 23
Underwriting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Legal Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Experts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Where You Can Find More Information. . . . . . . . . . . . . . . . . . . . . 33
Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . . F-1
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PROSPECTUS SUMMARY
This summary highlights selected information in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in our Debentures. You should read this entire prospectus carefully before investing in our Debentures.
THE COMPANY
We sell natural gas to approximately 40,000 retail customers on our distribution system. Additionally, we transport natural gas to our industrial customers, who purchase their gas in the open market. We also transport natural gas on behalf of local producers and customers not on our distribution system, and we produce a relatively small amount of natural gas and oil from our southeastern Kentucky wells.
OUR ADDRESS AND TELEPHONE NUMBER
Our executive offices are located at 3617 Lexington Road, Winchester, Kentucky 40391. Our telephone number is (859) 744-6171. Our FAX number is (859) 744-6552, and our internet address is www.deltagas.com.
SUMMARY CONSOLIDATED FINANCIAL INFORMATION
The following table summarizes our selected consolidated financial information. The table provides information about each of our last three fiscal years and the three months ended September 30, 2002 and 2001.
The following selected financial information should be read in conjunction with our Consolidated Financial Statements and the Notes included in this prospectus.
THREE THREE
MONTHS MONTHS
ENDED ENDED FOR THE FISCAL YEARS ENDED JUNE 30,
SEPT. 30, SEPT. 30, -----------------------------------------
2002 2001 2002 2001 2000
--------- --------- ---------- ---------- ----------
INCOME DATA ($)
Operating revenues 7,153,282 7,258,892 55,929,780 70,770,156 45,926,775
Operating income 231,609 479,305 8,401,452 8,721,719 8,176,722
Net income (loss) (991,247) (778,325) 3,636,713 3,635,895 3,464,857
Basic earnings (loss) per common share (.39) (.31) 1.45 1.47 1.42
Diluted earnings (loss) per common share (.39) (.31) 1.45 1.47 1.42
Dividends declared per common share .295 .29 1.16 1.14 1.14
SEPTEMBER 30, 2002
---------------------------------------------------------------
ACTUAL AS ADJUSTED(1)
---------------------------- ----------------------------
CAPITALIZATION ($)
Common shareholders' equity 32,748,493 39.4% 32,748,493 37.1%
Long-term debt (including current portion) 50,297,000 60.6 55,481,000 62.9
---------- ----- ---------- -----
Total capitalization 83,045,493 100.0% 88,229,493 100.0%
========== ===== ========== =====
SHORT-TERM NOTES PAYABLE ($) 26,945,000 23,084,000
THREE THREE
MONTHS MONTHS
ENDED ENDED FOR THE FISCAL YEARS ENDED JUNE 30,
SEPT. 30, SEPT. 30, -----------------------------------------
2002 2001 2002 2001 2000
--------- --------- ---------- ---------- ----------
RATIO OF EARNINGS TO FIXED CHARGES (2)
Actual (.35x) .01x 2.23x 2.15x 2.16x
Pro Forma (1) (.32x) 2.20x
---------
(1) Adjusted to reflect the issuance of the Debentures (at an assumed
interest rate of 7.25%) and the application of the estimated net
proceeds of $19,270,000. We will use $15,409,000 of the net
proceeds to call our 8.30% Debentures due 2026, and the remaining
$3,861,000 to reduce our short term notes payable. See "Use of
Proceeds".
(2) The ratio of earnings to fixed charges is the number of times that
fixed charges are covered by earnings. Earnings for the calculation
consist of net income before income taxes and fixed charges. Fixed
charges consist of interest expense and amortization of debt
expense.
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RISK FACTORS
Purchasing our Debentures involves risks. The following are material risks.
You should carefully consider each of the following factors and all of the information in this prospectus before purchasing any of our Debentures.
WEATHER CONDITIONS MAY CAUSE OUR REVENUES TO VARY FROM YEAR TO YEAR. Our revenues vary from year to year, depending on weather conditions. We estimate that approximately 75% of our annual gas sales are temperature sensitive. As a result, mild winter temperatures can cause a decrease in the amount of gas we sell in any year. For example, in fiscal 2002 the average daily temperature in our service areas was 89% of normal and in fiscal 2001 the average daily temperature in our service areas was 107% of normal. Our operating revenues in fiscal 2002 were approximately $14.8 million less than in fiscal 2001, mostly due to warmer winter temperatures during fiscal 2002 and decreased gas rates due to lower gas prices.
CHANGES IN FEDERAL REGULATIONS COULD REDUCE THE AVAILABILITY OR INCREASE THE COST OF OUR INTERSTATE GAS SUPPLY. We purchase a substantial portion of our gas supply from interstate sources. For example, in our fiscal year ended June 30, 2002 approximately 98% of our gas supply was purchased from interstate sources. The Federal Energy Regulatory Commission regulates the transmission of the natural gas we receive from interstate sources, and it could increase our transportation costs or decrease our available pipeline capacity by changing its regulatory policies in a manner that could increase transportation rates or reduce pipeline or storage capacity available to us. As an example, on the Tennessee Gas Pipeline System, which in our fiscal year ended June 30, 2002 supplied approximately 25% of our natural gas supply, we reserve capacity and transport the majority of our gas under a rate schedule approved by the Federal Energy Regulatory Commission for smaller local distribution companies that tend to have primarily residential customers. An increase in this rate schedule would cause the transportation cost of our natural gas supply to increase and, consequently, could increase our rates to such customers.
OUR GAS SUPPLY DEPENDS UPON THE AVAILABILITY OF ADEQUATE PIPELINE TRANSPORTATION CAPACITY. We purchase a substantial portion of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation service could reduce our normal interstate supply of gas.
OUR CUSTOMERS ARE ABLE TO ACQUIRE NATURAL GAS WITHOUT USING OUR DISTRIBUTION SYSTEM. Our larger customers can obtain their natural gas supply by purchasing their natural gas directly from interstate suppliers, local producers or marketers and arranging for alternate transportation of the gas to their plants or facilities. Customers may undertake such a by-pass of our distribution system in order to achieve lower prices for their gas service. Our larger customers who are in close proximity to alternative supply would be most likely to consider taking this action. This potential to by-pass our distribution system creates a risk of the loss of large customers and thus could result in lower revenues and profits and potentially higher rates to other customers.
WE FACE REGULATORY UNCERTAINTY AT THE STATE LEVEL. We are regulated by the Kentucky Public Service Commission. The majority of our revenues are generated by our regulated segment. We face the risk that the Kentucky Public Service Commission may fail to grant us adequate and timely rate increases or may take other actions that would cause a reduction in our income from operations, such as limiting our ability to pass on to our customers our increased costs of natural gas. Such regulatory actions would decrease our revenues and our profitability.
VOLATILITY IN THE PRICE OF NATURAL GAS COULD REDUCE OUR PROFITS. Significant increases in the price of natural gas will likely cause our retail customers to conserve or switch to alternate sources of energy. Any decrease in the volume of gas we sell that is caused by such actions will reduce our profits. Higher prices could also make it more difficult to add new customers.
WE DO NOT GENERATE SUFFICIENT CASH FLOWS TO MEET ALL OUR CASH NEEDS. Historically, we have made large capital expenditures in order to finance the maintenance, expansion and upgrading of our distribution system. As a result, we have funded a portion of our cash needs through borrowing and by offering new securities into the market. For example, by a combination of increasing our borrowing under our short-term
line of credit and sales of securities through our dividend reinvestment plan, we generated cash in the amount of $3,262,000 in fiscal 2002, $7,822,000 in fiscal 2001 and $4,628,000 in fiscal 2000. Although cash needs vary from year to year, we consider these years indicative of our future needs for external cash. Our dependency on external sources of financing creates the risks that our profits could decrease as a result of high capital costs and that lenders could impose onerous and unfavorable terms on us as a condition to granting us loans. We also risk the possibility that we may not be able to secure external sources of cash necessary to fund our operations.
THERE IS NO PUBLIC MARKET FOR OUR DEBENTURES. There is no public trading market for the Debentures. We do not intend to apply for listing of the Debentures on any national securities exchange or for quotation of the Debentures on any automated dealer quotation system. Our underwriter has told us it intends to make a market in the Debentures after this offering, although the underwriter is under no obligation to do so and may discontinue any market-making activities at any time without any notice. As a result, we can give no assurances that an active public market for the Debentures will develop. If an active public trading market for the Debentures does not develop, the market price and liquidity of the Debentures may be adversely affected.
OUR INABILITY TO OBTAIN ARTHUR ANDERSEN LLP'S CONSENT WILL LIMIT YOUR ABILITY TO ASSERT CLAIMS AGAINST ARTHUR ANDERSEN LLP. After reasonable efforts, we have not been able to obtain the written consent of Arthur Andersen LLP to our naming it in this prospectus as having certified our financial statements for the fiscal years ended June 30, 2000 and 2001, as required by Section 7 of the Securities Act of 1933. As a result, we have dispensed with the filing of their consent with the Securities and Exchange Commission in reliance on Rule 437a promulgated under the Securities Act. Consequently, your ability to assert claims against Arthur Andersen LLP will be limited. In particular, because of this lack of consent, you will not be able to sue Arthur Andersen LLP under Section 11(a)(4) of the Securities Act for any untrue statements of a material fact contained in the financial statements audited by Arthur Andersen LLP or any omissions to state a material fact required to be stated in those financial statements. Therefore, your right of recovery under that section will be limited.
CROSS-DEFAULT PROVISIONS IN OUR BORROWING ARRANGEMENTS INCREASE THE CONSEQUENCES OF A DEFAULT ON OUR PART. Each indenture under which our outstanding debentures were issued, as well as the loan agreement for our bank line of credit, contains a cross-default provision which provides that we will be in default under such indenture or loan agreement in the event of certain defaults under any of the other indentures or loan agreement. Accordingly, should an event of default occur under one of our debt agreements, we face the prospect of being in default under all of our debt agreements and obliged in such instance to satisfy all of our then-outstanding indebtedness.
OUR BORROWING ARRANGEMENTS INCLUDE VARIOUS NEGATIVE COVENANTS THAT RESTRICT OUR ACTIVITIES. Our bank line of credit prevents us from merging with another entity, selling a material portion of our assets other than in the ordinary course of business, issuing stock which in the aggregate exceeds thirty-five percent (35%) of our currently outstanding shares of common stock and having any person hold more than twenty percent (20%) of our outstanding shares of common stock. The indentures for our outstanding debentures prevent us from assuming additional mortgage indebtedness in excess of $2,000,000 or from paying dividends on our common stock unless our consolidated shareholders' equity exceeds $21,500,000 (which covenant will be adjusted to $25,800,000 under the indenture for the Debentures being offered under this prospectus). These negative covenants create the risk that we may be unable to take advantage of business and financing opportunities as they arise.
FORWARD LOOKING STATEMENTS
This prospectus contains forward-looking statements that relate to future events or our future performance. We have attempted to identify these statements by using words such as "estimates," "attempts," "expects," "monitors," "plans," "anticipates," "intends," "continues," "believes" and similar expressions.
These forward-looking statements include, but are not limited to, statements about:
o our operational plans,
o the cost and availability of our natural gas supplies,
o our capital expenditures,
o sources and availability of funding for our operations and expansion,
o our anticipated growth and growth opportunities through system expansion and acquisition,
o competitive conditions that we face,
o our production, storage, gathering and transportation activities,
o regulatory and legislative matters, and
o dividends.
FACTORS THAT COULD CAUSE FUTURE RESULTS TO DIFFER MATERIALLY FROM THOSE EXPRESSED IN OR IMPLIED BY THE FORWARD-LOOKING STATEMENTS OR HISTORICAL RESULTS INCLUDE THE IMPACT OR OUTCOME OF:
o the ongoing restructuring of the natural gas industry and the outcome of the regulatory proceedings related to that restructuring,
o the changing regulatory environment, generally,
o a change in the rights under present regulatory rules to recover for costs of gas supply, other expenses and investments in capital assets,
o uncertainty in our capital expenditure requirements,
o changes in economic conditions, demographic patterns and weather conditions in our retail service areas,
o changes affecting our cost of providing gas service, including changes in gas supply costs, interest rates, the availability of external sources of financing for our operations, tax laws, environmental laws and the general rate of inflation,
o changes affecting the cost of competing energy alternatives and competing gas distributors,
o changes in accounting principles and tax laws or the application of such principles and laws to us, and
o other matters described in the "RISK FACTORS" section.
USE OF PROCEEDS
We will use approximately $15.4 million of the estimated net proceeds from this offering to redeem our 8.30% Debentures due 2026. We will use the balance of the net proceeds, which we estimate to be $3,861,000, to reduce the outstanding balance of our revolving bank line of credit described below.
We have a revolving line of credit with Branch Banking and Trust Company under which we may draw a maximum principal amount of $40,000,000. The outstanding principal balance of this bank line of credit, which constitutes our short-term indebtedness, was $28,555,000 as of December 10, 2002. This line of credit extends through October 31, 2003. The interest rate on this line of credit, which is a variable rate based on the London Interbank Offered Rate, was 2.44% per annum as of December 10, 2002. We use this bank line of credit to fund general operating expenses and capital expenditures. The capital expenditures are primarily for replacement and upgrading of existing facilities and system extensions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
CAPITALIZATION
The following tables set forth our consolidated capitalization and short-term debt as of September 30, 2002, and as adjusted to reflect the sale of the Debentures and the application of the estimated net proceeds. This table should be read in conjunction with our consolidated financial statements and notes included in this prospectus.
AS OF SEPTEMBER 30, 2002
--------------------------------------------
ACTUAL AS ADJUSTED
-------------------- -------------------
LONG-TERM DEBT (INCLUDING CURRENT PORTION)
7.15% Debentures due 2018 $24,063,000 $24,063,000
% Debentures due 2023 - 20,000,000
6.625% Debentures due 2023 11,418,000 11,418,000
8.30% Debentures due 2026 14,816,000 -
----------- -----------
Total long-term debt $50,297,000 60.6% $55,481,000 62.9%
----------- -----------
COMMON SHAREHOLDERS' EQUITY
Common shares, par value $1 per share
Authorized-6,000,000 shares
Outstanding-2,544,479 shares $ 2,544,479 $ 2,544,479
Premium on common shares 30,622,312 30,622,312
Capital stock expense (1,925,392) (1,925,392)
Retained earnings 1,507,094 1,507,094
----------- -----------
Total common shareholders' equity $32,748,493 39.4% $32,748,493 37.1%
----------- ----- ----------- -----
Total capitalization $83,045,493 100.0% $88,229,493 100.0%
=========== ===== =========== =====
SHORT-TERM NOTES PAYABLE $26,945,000 $23,084,000
=========== ===========
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SELECTED FINANCIAL DATA
In the following table we set forth our selected financial data for the periods indicated. In the table we also include our ratio of earnings to our fixed charges. The data for each of the five fiscal years in the period ended June 30, 2002 are derived from our audited consolidated financial statements for each of those periods. The data for the three months ended September 30, 2002 and 2001 are derived from our unaudited consolidated financial statements. We believe that the unaudited consolidated financial statements include all adjustments necessary for the fair presentation of the information below.
The information in the table below does not provide all financial data about us. Consequently, we urge you to read and consider the information in our consolidated financial statements and the notes to those financial statements and in the section of this prospectus entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations".
THREE THREE
MONTHS MONTHS
ENDED ENDED AS OF AND FOR THE FISCAL YEARS ENDED JUNE 30,
SEPT. 30, SEPT. 30, -------------------------------------------------------------------
2002 2001 2002 2001 2000 1999 1998(a)
----------- ----------- ----------- ----------- ----------- ----------- -----------
SUMMARY OF OPERATIONS ($)
Operating revenues 7,153,282 7,258,892 55,929,780 70,770,156 45,926,775 38,672,238 44,258,000
Operating income 231,609 479,305 8,401,452 8,721,719 8,176,722 6,652,070 6,731,859
Net income (loss) (991,247) (778,325) 3,636,713 3,635,895 3,464,857 2,150,794 2,451,272
Basic and diluted earnings
(loss) per common share (.39) (.31) 1.45 1.47 1.42 .90 1.04
Dividends declared per common
share .295 .29 1.16 1.14 1.14 1.14 1.14
AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (BASIC AND DILUTED) 2,537,691 2,502,139 2,513,804 2,477,983 2,433,397 2,394,181 2,359,598
TOTAL ASSETS ($) 132,458,001 129,687,922 127,948,525 124,179,138 112,918,919 107,473,117 102,866,613
CAPITALIZATION ($)
Common shareholders' equity 32,748,493 31,489,678 34,182,277 32,754,560 31,297,418 29,912,007 29,810,294
Long-term debt 48,547,000 49,151,940 48,600,000 49,258,902 50,723,795 51,699,700 52,612,494
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total capitalization 81,295,493 80,641,618 82,782,277 82,013,462 82,021,213 81,611,707 82,422,788
=========== =========== =========== =========== =========== =========== ===========
SHORT-TERM DEBT ($)(b) 28,695,000 27,580,000 21,105,000 19,250,000 11,375,000 8,145,000 3,665,000
OTHER ITEMS ($)
Capital expenditures 2,641,803 2,627,824 9,421,765 7,069,713 8,795,653 7,982,143 11,193,613
Total plant, before accumulated
depreciation 158,780,385 150,247,189 156,305,063 147,792,390 141,986,856 133,804,954 127,028,159
RATIO OF EARNINGS TO FIXED
CHARGES (c)
Actual (.35x) .01x 2.23x 2.15x 2.16x 1.75x 1.89x
Pro forma (d) (.32x) 2.20x
---------------------
(a) During March 1998, we sold $25,000,000 of debentures. We used the
proceeds to repay short-term debt and to redeem $10,000,000 of our
9.00% debentures due 2011.
(b) Includes current portion of long-term debt.
(c) The ratio of earnings to fixed charges is the number of times that
fixed charges are covered by earnings. Earnings for the calculation
consist of net income before income taxes and fixed charges. Fixed
charges consist of interest expense and amortization of debt
expense.
(d) As adjusted to reflect the issuances of the Debentures (at an
assumed rate of 7.25%) offered hereby and the application of the
estimated net proceeds of $19,270,000.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
FOR OUR COMPLETE CONSOLIDATED FINANCIAL STATEMENTS,
SEE PAGES F-1 THROUGH F-27.
OVERVIEW
The Kentucky Public Service Commission regulates our utility operations. As a part of this regulation, the Kentucky Public Service Commission sets the rates we are permitted to charge our customers. These rates have a significant impact on our annual revenues and profits. See "Business - Regulatory Matters."
The rates approved by the Kentucky Public Service Commission allow us a specified rate of return on our regulated investment. The rates we are allowed to charge our customers also permit us to pass through to our customers changes in the costs of our gas supply. See "Business - Regulatory Matters."
Our business is temperature-sensitive. Our sales volumes in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods. The impact of unusual winter temperatures on our revenues was ameliorated to some extent when in the year 2000 the Kentucky Public Service Commission permitted us to start adjusting our winter rates in response to unusual winter temperatures. Under this weather normalization tariff, we are permitted to increase our rates for residential and small non-residential customers when, based on a thirty year average temperature, winter weather is warmer than normal, and we are required to decrease our rates when winter weather is colder than normal. We are permitted to adjust these rates for the billing months of December through April.
LIQUIDITY AND CAPITAL RESOURCES
Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably. Most of our construction activity takes place during these warmer months. As a result, we meet our cash needs for operations and construction during the warmer non-heating months partially through short-term borrowings.
We made capital expenditures of $2,641,803 during the first quarter of fiscal 2003. We expect our total capital expenditures for fiscal 2003 to be $9.8 million. We will make these capital expenditures for system extensions and for the replacement and improvement of existing transmission, distribution, gathering and general facilities.
We generate internally only a portion of the cash necessary for our capital expenditure requirements. We finance the balance of our capital expenditure requirements on an interim basis through a short-term line of bank credit. Our current available line of bank credit is $40,000,000, of which $26,945,000 was borrowed at September 30, 2002. Our line of credit was with Bank One, Kentucky, NA, at September 30, 2002. On October 31, 2002, we replaced this line of credit with a new $40,000,000 line of credit with Branch Banking and Trust Company. This new line of credit is on substantially the same terms as the former line of credit and extends through October 31, 2003.
We periodically repay our short term borrowings under our line of credit by using the net proceeds from the sale of long-term debt and equity securities. For example, in March, 1998, we used the net proceeds of $24,100,000 from the sale of $25,000,000 of our debentures to repay short-term debt and to redeem our 9.00% Debentures, that would have matured in 2011, in the amount of $10,000,000. We will use a portion of the proceeds from this offering to pay down our new line of credit with Branch Banking and Trust Company. See "Use of Proceeds". If market conditions are favorable, we plan to make an equity offering late in fiscal 2003.
Below, we summarize our primary cash flows during the last three fiscal years and the three months ended September 30, 2002 and 2001:
THREE MONTHS ENDED SEPTEMBER 30, FOR THE YEARS ENDED JUNE 30,
-------------------------------- ----------------------------------------------
2002 2001 2002 2001 2000
----------- ----------- ----------- ----------- -----------
Provided by (used in) our operating
activities $(4,390,229) $(4,614,773) $10,511,896 $ 2,652,572 $ 8,827,505
Used in our investing activities (2,641,803) (2,627,824) (9,421,765) (7,069,713) (8,795,653)
Provided by (used in) financing
activities 7,094,463 7,724,443 (1,028,996) 4,185,248 115,554
----------- ----------- ----------- ----------- -----------
Net increase (decrease) in cash and
cash equivalents $ 62,431 $ 481,846 $ 61,135 $ (231,893) $ 147,406
=========== =========== =========== =========== ===========
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Cash provided by our operating activities consists of net income and noncash items, including depreciation, depletion, amortization and deferred income taxes. Cash provided by our operating activities also includes changes in working capital in our cash generated by operating activities. We expect that internally generated cash, coupled with short-term borrowings, will be sufficient to satisfy our operating, normal capital expenditure and dividend requirements for the foreseeable future.
RESULTS OF OPERATIONS
OPERATING REVENUES
The decrease in our 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. This decrease, however, was offset to some extent, because unusually warm temperatures enabled us to adjust our rates upward.
The increase in operating revenues for 2001 of $24,843,000 was primarily attributable to higher gas rates and increased sales volumes. Gas rates increased due to higher gas prices. This increase, however, was offset to some extent, because unusually cold temperatures required us to adjust our rates downward. Our sales volumes increased due to the colder winter weather in 2001.
Heating degree days billed for 2002 were 89.0% of normal thirty-year average temperatures as compared with 106.8% of normal temperatures for 2001 and 89.6% of normal temperatures for 2000. A "heating degree day" is determined each day when the average of the high and low temperature is one degree less than 65 degrees Fahrenheit.
In the following table we set forth variations in our revenues for the last two fiscal years:
INCREASE (DECREASE)
--------------------------------------
2002 COMPARED 2001 COMPARED
TO 2001 TO 2000
-------------- -------------
Variations in our 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 our 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 our revenues $(14,840,000) $24,843,000
============ ===========
Percentage variations in our regulated volumes
Gas sales (19.1) 18.0
Transportation 13.6 16.8
Percentage variations in our non-regulated gas sales
volumes .4 7.7
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The decreases in non-regulated revenues and intersegment revenues for the three months ended September 30, 2002 were primarily attributable to the non-regulated segment discontinuance of selling gas to the regulated segment effective January 1, 2002.
In the following table we set forth variations in revenues for the three months ended September 30, 2002 compared to 2001:
INCREASE (DECREASE)
-------------------
Variations in our regulated revenues
Gas rates $ (106,000)
Weather normalization adjustment -
Sales volumes (73,000)
On-system transportation (4,000)
Off-system transportation 109,000
Other (9,000)
-----------
Total $ (83,000)
-----------
Variations in our non-regulated
revenues
Gas rates $ 269,000
Sales volumes (1,302,000)
-----------
Total $(1,033,000)
-----------
Total variations in revenues $(1,116,000)
Variations in our intersegment revenues 1,010,000
-----------
Variations in our consolidated
revenues $ (106,000)
===========
Percentage variations in our
regulated volumes
Gas sales (2.4)
On-system transportation 7.7
Off-system transportation 25.6
Percentage variations in our non-
regulated gas sales volumes (27.6)
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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.
In the following table we set forth variations in our purchased gas expense for the last two fiscal years:
INCREASE (DECREASE)
--------------------------------------------
2002 COMPARED 2001 COMPARED
TO 2001 TO 2000
------------- -------------
Variations in our 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 our 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 our gas expense $(14,551,000) $23,493,000
============ ===========
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The decreases in non-regulated gas expense and intersegment gas expenses for the three months ended September 30, 2002 were primarily attributable to the non-regulated segment discontinuance of selling gas to the regulated segment effective January 1, 2002.
In the following table we set forth variations in our purchased gas expense for the three months ended September 30, 2002 compared to 2001:
INCREASE (DECREASE)
-------------------
Variations in our regulated gas expense
Gas rates $ (163,000)
Purchase volumes (30,000)
-----------
Total $ (193,000)
-----------
Variations in our non-regulated gas expense
Gas rates $ 125,000
Purchase volumes (963,000)
-----------
Total $ (838,000)
-----------
Total variations in our gas expense $(1,031,000)
Variations in our intersegment gas expense 1,010,000
-----------
Variations in our consolidated gas expense $ (21,000)
===========
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The decrease in income taxes for the three months ending September 30, 2002 of $75,000 was primarily due to a decrease in net income.
The decrease in interest charges for the three months ending September 30, 2002 of $117,000 was primarily due to lower interest rates on the short-term notes payable.
BASIC AND DILUTED EARNINGS PER COMMON SHARE
For the years ended June 30, 2002, 2001 and 2000, our basic earnings per common share changed as a result of changes in net income and an increase in the number of our common shares outstanding. We increased our number of common shares outstanding as a result of shares issued through our dividend reinvestment plan and employee stock purchase plan.
We have no potentially dilutive securities. As a result, our basic earnings per common share and our diluted earnings per common share are the same.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, entitled Accounting for Asset Retirement Obligations, and we adopted this statement effective July 1, 2002. Statement No. 143 addresses financial accounting for legal obligations associated with the retirement of long-lived assets. Upon adoption of this statement, we recorded $178,000 of asset retirement obligations in the balance sheet primarily representing the current estimated fair value of our obligation to plug oil and gas wells at the time of abandonment. Of this amount, $47,000 was recorded as incremental cost of the underlying property, plant and equipment. The cumulative effect on earnings of adopting this new statement was a charge to earnings of approximately $88,000 (net of income taxes of approximately $55,000), representing the cumulative amounts of depreciation and changes in the asset retirement obligation due to the passage of time for historical accounting periods. The adoption of the new standard did not have a significant impact on income (loss) before cumulative effect of a change in accounting principle for the three and twelve months ended September 30, 2002. Pro forma net income and earnings per share have not been presented for the three months ended September 30, 2001 and for the twelve months ended September 30, 2002 and 2001 because the pro forma application of Statement No. 143 to prior periods would result in pro forma net income and earnings per share not materially different from the actual amounts reported for those periods in the accompanying consolidated statements of income.
In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, entitled Accounting for the Impairment or Disposal of Long-Lived Assets. Statement No. 144 addresses accounting and reporting for the impairment or disposal of long-lived assets. Statement No. 144 was effective July 1, 2002. The impact of implementation on our financial position or results of operations was not material.
In June 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 146, entitled Accounting for Costs Associated with Exit or Disposal Activities. Statement No. 146 addresses financial reporting and accounting for costs associated with exit or disposal activities. This statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and is effective for exit or disposal activities that are initiated after December 31, 2002. We have not committed to any such exit or disposal plan. Accordingly, this new statement will not presently have any impact on us.
The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position, entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. This proposed statement will apply to all nongovernmental entities that acquire, construct or replace tangible property, plant, and equipment. A significant element of the statement requires that entities use component accounting to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all such assets, to the extent applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of property, plant and equipment. We are currently analyzing the impact of this proposed statement, which has a proposed effective date of January 1, 2003.
OUR MARKET RISK
We purchase our gas supply through a combination of spot market gas purchases and forward gas purchases. The price of spot market gas is based on the market price at the time of delivery. The price we
pay for our natural gas supply acquired under our forward gas purchase contracts, however, is fixed months prior to the delivery of the gas. Additionally, we inject some of our gas purchases into gas storage facilities in the non-heating months and withdraw this gas from storage for delivery to customers during the heating season. We have minimal price risk resulting from these forward gas purchase and storage arrangements, because we are permitted to pass these gas costs on to our regulated customers through the gas cost recovery rate mechanism.
As a part of our unregulated transportation activities, we sometimes contract with our transportation customers to acquire gas that we will transport to these customers. At the time we make a sales commitment to one of these customers, we attempt to cover this position immediately with gas purchase commitments matched to the terms of the related sales contract. By immediately covering our obligation under the contracts with our transportation customers, we are able to minimize our price volatility risk.
None of our gas contracts are accounted for using the fair value method of accounting. While some of our gas purchase contracts meet the definition of a derivative, we have designated these contracts as "normal purchases" under statement No. 133 entitled Accounting for Derivative Instruments and Hedging Activities.
We are exposed to risk resulting from changes in interest rates on our variable rate notes payable. The interest rate on our current short-term line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate. The balance on our outstanding short- term line of credit was $26,945,000 on September 30, 2002 and $25,130,000 on September 30, 2001. On December 10, 2002, the balance on our short-term line of credit was $28,555,000. Based on the amount of our outstanding short-term line of credit on September 30, 2002, a one percent increase (decrease) in our average interest rates would result in a decrease (increase) in our annual pre-tax net income of $269,000. See Note 6 of the Notes to Consolidated Financial Statements.
A portion of the proceeds from this offering will be used to pay down our short-term line of credit. See "Use of Proceeds".
BUSINESS
GENERAL
In 1951, we established our first retail gas distribution system, which provided service to a total of 300 customers in two small Kentucky towns. As a result of acquisitions, as well as expansions of our customer base within our existing service areas, we now provide retail gas distribution service to approximately 40,000 customers. We also transport natural gas for others and produce a relatively small amount of oil and gas.
We operate through two segments, a regulated segment and an unregulated segment.
Through our regulated segment, we sell natural gas to our retail customers in 23 predominately rural communities in central and southeastern Kentucky. Our regulated segment also transports gas to industrial customers on our system who have purchased gas in the open market. Our regulated segment also transports gas on behalf of local producers and other customers not on our distribution system.
We operate our unregulated segment through three wholly-owned subsidiaries. Two of these subsidiaries, Delta Resources, Inc. and Delgasco, Inc., purchase natural gas on the national market and from Kentucky producers. We resell this gas to industrial customers on our system and to others not on our distribution system. Our third subsidiary that is part of the unregulated segment, Enpro, Inc., produces a relatively small amount of natural gas and oil that is sold on the unregulated market.
DISTRIBUTION AND TRANSMISSION OF NATURAL GAS
The economy of our service area is based principally on coal mining, farming and light industry. The communities we serve typically contain populations of less than 20,000. Our three largest service areas are Nicholasville, Corbin and Berea. In Nicholasville we serve approximately 7,000 customers, in Corbin we serve approximately 6,000 customers and in Berea we serve approximately 4,000 customers.
The communities we serve continue to expand, resulting in growth opportunities for us. Developers have built industrial parks in our service areas, and this has resulted in some new industrial customers for us.
Over 99% of our customers are residential and commercial. In fiscal 2002, those customers accounted for 96% of the total volume of gas we sold. Our remaining customers are light industrial, and in fiscal 2002, they accounted for 4% of the total volume of gas we sold.
Factors that affect our revenues include rates we charge our customers, our supply cost for the natural gas we purchase for resale, economic conditions in our service areas, weather and competition.
Although the rules of the Kentucky Public Service Commission permit us to pass through to our customers changes in the price we must pay for our gas supply, increases in our rates to customers may cause our customers to conserve or to use alternative energy sources.
Our retail sales are seasonal and temperature-sensitive, since the majority of the gas we sell is used for heating. Variations in the average temperature during the winter impacts our revenues year-to-year. Public Service Commission regulations, however, provide for us to adjust the rates we charge our customers in response to winter weather that is warmer or colder than normal temperatures.
We compete with alternate sources of energy for our retail customers. These alternate sources include electricity, coal, oil, propane and wood. Our unregulated subsidiaries, which sell gas to industrial customers and others, compete with natural gas producers and natural gas marketers for those customers.
Our industrial customers may be able to bypass our system by purchasing their gas supply from sources other than us. Additionally, some of our industrial customers are able to switch economically to alternative sources of energy. These are competitive concerns that we continue to address.
Some natural gas producers in our service area can access pipeline delivery systems other than ours, which generates competition for our transportation function. We continue our efforts to purchase or transport natural gas that is produced in reasonable proximity to our transportation facilities.
As an active participant in many areas of the natural gas industry, we plan to continue efforts to expand our gas distribution system and customer base. We continue to consider acquisitions of other gas systems, some of which are contiguous to our existing service areas, as well as expansion within our existing service areas.
We anticipate continuing activity in gas production and transportation and plan to pursue and increase these activities wherever practicable. We continue to consider the construction, expansion or acquisition of additional transmission, storage and gathering facilities to provide for increased transportation, enhanced supply and system flexibility.
CONSOLIDATED OPERATING STATISTICS
In the following table, we provide information about our business during the periods indicated. The data for the three months ended September 30, 2002 and 2001 have been derived from our unaudited quarterly financial statements.
FOR THE FOR THE
THREE THREE
MONTHS MONTHS
ENDED ENDED FOR THE FISCAL YEARS ENDED JUNE 30,
SEPT. 30 SEPT. 30 ----------------------------------------------
2002 2001 2002 2001 2000 1999 1998
-------- -------- ------ ------ ------ ------ ------
AVERAGE RETAIL CUSTOMERS SERVED
Residential 32,659 32,386 33,624 33,691 33,251 32,429 31,953
Commercial 5,001 4,927 5,235 5,227 5,110 4,958 4,873
Industrial 61 62 62 65 66 68 70
------ ------ ------ ------ ------ ------ ------
Total 37,721 37,375 38,921 38,983 38,427 37,455 36,896
====== ====== ====== ====== ====== ====== ======
OPERATING REVENUES ($000)
Residential sales 1,589 1,688 23,202 28,088 19,672 17,329 19,969
Commercial sales 1,209 1,256 13,832 17,040 10,952 10,039 11,890
Industrial sales 113 145 1,141 2,046 1,104 1,173 1,576
On-system transportation 858 862 3,826 3,895 4,056 4,107 3,877
Off-system transportation 382 272 1,220 814 522 363 483
Non-regulated sales 2,977 3,002 12,511 18,640 9,431 5,491 6,335
Other 24 33 198 247 190 170 128
------ ------ ------ ------ ------ ------ ------
Total 7,152 7,258 55,930 70,770 45,927 38,672 44,258
====== ====== ====== ====== ======
SYSTEM THROUGHPUT (MILLION CU. FT.)
Residential sales 92 96 2,133 2,614 2,266 2,223 2,377
Commercial sales 101 99 1,389 1,666 1,397 1,401 1,504
Industrial sales 13 16 142 249 174 189 231
------ ------ ------ ------ ------ ------ ------
Total retail sales 206 211 3,664 4,529 3,837 3,813 4,112
On-system transportation 1,207 1,122 4,866 4,768 4,703 4,434 3,467
Off-system transportation 1,090 871 3,590 2,677 1,672 1,144 1,489
------ ------ ------ ------ ------ ------ ------
Total 2,503 2,204 12,120 11,974 10,212 9,391 9,068
====== ====== ====== ====== ====== ====== ======
AVERAGE ANNUAL CONSUMPTION PER AVERAGE RESIDENTIAL
CUSTOMER (THOUSAND CU. FT.) 11 12 63 78 68 69 74
LEXINGTON, KENTUCKY DEGREE DAYS
Actual 1 2 4,137 4,961 4,162 4,188 4,397
Percent of thirty-year average (4,646) 1.8 3.6 89.0 106.8 89.6 90.1 94.6
AVERAGE REVENUE PER Mcf SOLD AT RETAIL ($) 14.13 14.64 10.42 10.42 8.27 7.49 8.13
AVERAGE GAS COST PER Mcf SOLD AT RETAIL ($) 5.12 5.91 5.39 6.07 3.77 3.69 4.60
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GAS SUPPLY
We purchase our natural gas from a combination of interstate and Kentucky sources. In our fiscal year ended June 30, 2002, we purchased approximately 98% of our natural gas from interstate sources.
INTERSTATE GAS SUPPLY
Our commodity requirements agreement with Woodward is for a term that expires on April 30, 2003, but will renew until April 30, 2004, unless either we or Woodward gives written notice at least sixty days before April 30, 2003 not to renew the agreement. Our agreement with Woodward is to supply the interstate gas transported for us by Tennessee Gas Pipeline.
Our agreement with Dynegy, under which we purchase the natural gas transported for us by Columbia Transmission Corporation and Columbia Gulf Transmission, will end April 30, 2003. We intend, prior to April 30, 2003, to negotiate and enter into commodity requirements agreements with one or more other gas marketers to replace Dynegy's current supply obligations to us.
We also purchase additional interstate natural gas from Woodward, as needed, outside of our commodity requirement agreement with Woodward. This spot gas purchasing arrangement is pursuant to an agreement with Woodward that expires on March 31, 2005. We are not obligated to purchase gas from Woodward under this agreement for any periods longer than one month at a time. The price of gas under this agreement is based on current market prices, determined in a similar manner as under the commodity requirements contract with Woodward, with an agreed-to fixed price adjustment per million British Thermal Units purchased.
We also purchase interstate natural gas from other gas marketers as needed at either current market prices, determined by industry publications, or at forward market prices.
TRANSPORTATION OF INTERSTATE GAS SUPPLY
Our interstate natural gas supply is transported to us from production and storage fields by Tennessee Gas Pipeline Company, Columbia Gas Transmission Corporation, Columbia Gulf Transmission Corporation and Texas Eastern Transmission Corporation.
Our agreements with Tennessee Gas Pipeline extend by their terms until 2005 and, unless terminated by one of the parties, automatically renew for subsequent five-year terms. However, Tennessee has represented to us that as a result of Tennessee's Early Renewal Incentive Option Program begun in 1999, our agreements with Tennessee actually extend through 2008 and thereafter automatically renew for subsequent five-year terms unless terminated by one of the parties. Tennessee is obligated under these agreements to transport up to 19,600 Mcf per day for us. During fiscal 2002, Tennessee transported a total of 1,109,000 Mcf for us under these contracts. Annually, approximately 25% of our supply requirements flow through Tennessee Gas Pipeline to our points of receipt. We have gas storage agreements with Tennessee under the terms of which we reserve a defined storage space in Tennessee's production area storage fields and its market area storage fields, and we reserve the right to withdraw up to fixed daily volumes. These gas storage agreements terminate on the same schedule as our transportation agreements with Tennessee.
Under our agreements with Columbia Gas and Columbia Gulf, Columbia Gas is obligated to transport up to 12,500 Mcf per day for us and Columbia Gulf is obligated to transport up to a total of 4,300 Mcf per
day for us. During fiscal 2002, Columbia Gas and Columbia Gulf transported a total of 555,000 Mcf for us under all of our agreements with them. Columbia Gulf also transported additional volumes on behalf of one of our gas marketers to a point of interconnection between Columbia Gulf and us where we purchase the gas to inject into our storage field, as discussed below.
All of our transport agreements with Columbia Gas and Columbia Gulf, except one agreement concerning the transportation of natural gas to supply our Mt. Olivet, Kentucky service area and two agreements concerning the transportation of natural gas to supply our North Middletown, Kentucky service area, extend through 2008 and thereafter continue on a year-to-year basis until terminated by one of the parties. The Mt. Olivet agreement and one of the North Middletown agreements are by their terms continuing on a year-to-year basis until terminated by one of the parties upon at least six months' prior written notice. The other North Middletown agreement is by its terms set to expire October 31, 2004. However, Columbia Gas and Columbia Gulf have orally agreed with us to extend these agreements to 2008 with our other agreements and the parties are in the process of finalizing this extension. While the Mt. Olivet and North Middletown transport agreements are important for these service areas, they involve a relatively small amount of our overall gas supply.
We have no direct agreement with Texas Eastern Transmission Corporation. However, one of our gas marketers from whom we make additional purchases of interstate natural gas supply as needed has an arrangement with Texas Eastern to transport the gas to us that we purchase from that marketer. Consequently, Texas Eastern does transport a small percentage of our interstate gas supply.
KENTUCKY GAS SUPPLY
We also purchased 25,000 Mcf of natural gas from our wholly-owned, unregulated subsidiary, Enpro, during 2002.
We own and operate an underground natural gas storage field that we use to store a significant portion of our winter gas supply needs. The storage gas is delivered during the summer injection season by Columbia Gulf on behalf of one of our marketers to an interconnection point between Columbia Gulf and us where we receive the gas and flow it to our storage field. The marketer arranges transportation of the gas through the Columbia Gulf system to us. This storage capability permits us to purchase and store gas during the non-heating months and then withdraw and sell the gas during the peak usage months. During 2002, we withdrew 1,900,000 Mcf from this storage field.
We continue to seek additional new gas supplies from available sources. We will continue to maintain an active gas supply management program that emphasizes long-term reliability and the pursuit of cost-effective sources of gas for our customers.
REGULATORY MATTERS
The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and our transportation services. The Kentucky Public Service Commission regulation of our business includes setting the rates we are permitted to charge our retail customers and our transportation customers.
We monitor our need to file requests with the Kentucky Public Service Commission for a general rate increase for our retail gas and transportation services. Through these general rate cases, we are able to adjust the sales prices of our retail gas we sell to and transport for our customers.
On December 27, 1999, the Kentucky Public Service Commission approved an annual revenue increase for us of $420,000. We filed this general rate case in July of 1999, and it is our most recent filing of a rate case. The approval of our requests in this rate case included a weather normalization provision that permits us to adjust rates for the billing months of December through April to reflect variations from thirty-year average winter temperatures.
The rates approved for our customers include a gas cost recovery clause, which permits us to adjust the rates charged to our customers to reflect changes in our natural gas supply costs. The gas cost recovery clause requires us to make quarterly filings with the Kentucky Public Service Commission but does not require a general rate case.
During July 2001, the Kentucky Public Service Commission required an independent audit of our gas procurement activities and the gas procurement activities of four other gas distribution companies. This is part of the Kentucky Public Service Commission's investigation of increases in wholesale natural gas prices and their impact on customers. The Kentucky Public Service Commission indicated that Kentucky distributors had generally developed sound planning and procurement procedures for meeting their customers' natural gas requirements and that these procedures had provided customers with a reliable supply of natural gas at reasonable costs. The Kentucky Public Service Commission noted the events of the prior year, including changes in natural gas wholesale markets. It 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 Kentucky Public Service Commission have completed this audit. The final audit report dated November 15, 2002 contains sixteen procedural and reporting-related recommendations for us 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 us and the four other gas distribution companies involved in the audit, including Kentucky natural gas price issues, hedging, gas cost recovery mechanisms, budget billing, uncollectible accounts and forecasting. We intend to comply with the audit report's recommendations and anticipate that our compliance will have no material impact on our financial position or results of operations.
In addition to regulation by the Kentucky Public Service Commission, we may obtain non-exclusive franchises from the cities and communities in which we operate authorizing us to place our facilities in the streets and public grounds. No utility may obtain a franchise until it has obtained approval from the Kentucky Public Service Commission to bid on a local franchise. We hold franchises in four of the cities and seven other communities we serve. In the other cities and communities we serve, either our franchises have expired, the communities do not have governmental organizations authorized to grant franchises, or the local governments have not required or do not want to offer a franchise. We attempt to acquire or reacquire franchises whenever feasible.
Without a franchise, a local government could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city or community. To date, the absence of a franchise has caused no adverse effect on our operations.
PROPERTIES
We own our corporate headquarters in Winchester, Kentucky. We own ten buildings used for field operations in the cities we serve. Also, we own a building in Laurel County used for training and equipment and materials storage.
We own 2,403 miles of natural gas gathering, transmission, distribution, storage and service lines. These lines range in size up to twelve inches in diameter.
We hold leases for the storage of natural gas under 8,000 acres located in Bell County, Kentucky. We developed this property for the underground storage of natural gas.
We use all the properties described in the three paragraphs immediately above principally in connection with our regulated natural gas distribution, transmission and storage segment. See Note 11 of the Notes to Consolidated Financial Statements for a description of our two business segments.
Through our wholly owned subsidiary, Enpro, we produce oil and gas as a part of the unregulated segment of our business.
Enpro owns interests in oil and gas leases on 11,000 acres located in Bell, Knox and Whitley Counties. Forty gas wells and five oil wells are producing from these properties. The remaining proved, developed natural gas reserves on these properties are estimated to be 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 we have performed no reserve studies on these properties. Enpro produced a total of 187,000 Mcf of natural gas during 2002 from all the properties described in this paragraph.
A producer is conducting exploration activities on part of Enpro's undeveloped holdings. Enpro reserved the option to participate in wells drilled by this producer and also retained certain working and royalty interests in any production from future wells.
Our assets have no significant encumbrances.
EMPLOYEES
On December 10, 2002, we had 154 full-time employees. We consider our relationship with our employees to be satisfactory. Our employees are not represented by unions or subject to any collective bargaining agreements.
LEGAL PROCEEDINGS
We are not parties to any legal proceedings that are expected to have a materially adverse impact on our financial condition or our results of operations.
DESCRIPTION OF DEBENTURES
We are offering $20,000,000 of our % Debentures due January 1, 2023.
We currently have outstanding 7.15% Debentures due 2018 in the aggregate principal amount of $24,089,000, 6.625% Debentures due 2023 in the aggregate principal amount of $11,445,000 and 8.30% Debentures due 2026 in the aggregate principal amount of $14,816,000. While we issued these other debentures under indentures different from the indenture under which this offering is made and these other debentures have slightly different terms from the Debentures being offered by this prospectus, the outstanding debentures mainly differ from the Debentures offered by this prospectus as to interest rate and maturity date. These other debentures, along with our short-term line of credit with Branch Banking and Trust Company, which as of December 10, 2002, had an outstanding principal balance of $28,555,000, constitute all our unsubordinated, unsecured debt obligations. These other debentures and our short-term line of credit with Branch Banking and Trust Company will rank equally as our debt obligations to the Debentures offered by this prospectus. As discussed above, we will use part of the proceeds from the sale of the Debentures offered by this prospectus to redeem the 8.30% Debentures due 2026 and the balance to pay a portion of the outstanding balance on the short-term bank line of credit.
We will issue the Debentures under an indenture dated as of December , 2002, between us and Fifth Third Bank, Cincinnati, Ohio, as the trustee. We have filed a copy of the indenture with the SEC.
The indenture is a contract between us and the trustee. The trustee has two main roles. First, the trustee can enforce your rights against us if an "event of default," as that term is described below, occurs. Second, the trustee performs certain administrative duties for us.
The terms of the Debentures include those stated in the indenture and those made a part of the indenture by reference to the Trust Indenture Act of 1939, as in effect on December , 2002. We have summarized below the material provisions of the Debentures and the indenture. However, you should understand that this is only a summary, and we have not included all of the provisions of the Debentures or the indenture. We have filed the indenture with the SEC, and we suggest that you read the indenture. We are incorporating by reference the provisions of the indenture and this summary is qualified in its entirety by the provisions of the indenture.
We do not intend to list the Debentures on a national securities exchange. The Debentures do not presently have a trading market. We can give no assurance that such a market will develop. If a market for the Debentures does develop, there can be no assurance that it will continue to exist.
BOOK-ENTRY ONLY SYSTEM
We will issue the Debentures in the aggregate initial principal amount of $20,000,000. The Debentures will be represented by one global certificate (also known as a global security) issued to The Depository Trust Company, which is known as DTC. DTC will act as securities depository for the Debentures. The Debentures will be issued only as fully-registered securities registered in the name of DTC's nominee, Cede & Co. DTC will maintain the Debentures in denominations of $1,000, and integral multiples $1,000, through its book-entry facilities.
The following is based upon information furnished by DTC:
o DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants (known as direct participants) deposit with DTC. DTC also facilitates the post-trade settlement among direct participants of sales and other securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry transfers and pledges between direct participants' accounts. This eliminates the need for physical movement of securities certificates. Direct participants in DTC include securities brokers and dealers, banks, trust companies, clearing corporations and certain other
organizations. DTC is a wholly-owned subsidiary of Depository Trust & Clearing Corporation, which in turn is owned by a number of direct participants and Members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation and Emerging Markets Clearing Corporation, as well as by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the National Association of Securities Dealers, Inc. Access to the DTC system is also available to others, known as indirect participants, such as securities brokers and dealers, banks, trust companies and clearing corporations that clear transactions through or maintain a custodial relationship with a direct participant. The rules applicable to DTC and its participants are on file with the SEC. More information about DTC can be found at www.dtcc.com.
o Purchases of Debentures within the DTC system must be made by or through direct participants, which will receive a credit for the Debentures on DTC's records. The ownership interest of each actual purchaser of an interest in the Debentures, the owners of which are known as beneficial owners, is in turn to be recorded on the direct and indirect participants' records. Beneficial owners like yourself will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct or indirect participants through which the beneficial owners entered into the transaction. Transfers of the Debentures are to be accomplished by entries made on the books of direct and indirect participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing the Debentures, except in the event that use of the book-entry system for the Debentures is discontinued, as discussed below.
o To facilitate subsequent transfers, all Debentures deposited by participants with DTC are registered in the name of DTC's partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of Debentures with DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the Debentures. DTC's records reflect only the identity of the direct participants to whose accounts the Debentures are credited, which may or may not be the beneficial owners. The direct and indirect participants will remain responsible for keeping account of their holdings on behalf of their customers.
o The delivery of notices and other communications by DTC to direct participants, by direct participants to indirect participants and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Beneficial owners of Debentures like yourself may wish to take certain steps to augment transmission to you of notices of significant events with respect to the Debentures, such as redemptions, tenders and defaults.
o Redemption notices will be sent to Cede & Co., as registered holder of the Debentures. If less than all of the Debentures are being redeemed, DTC's practice is to determine by lot the amount of the interest of each direct participant to be redeemed.
o Neither DTC nor Cede & Co. (nor any other DTC nominee) will itself consent or vote with respect to Debentures. Under its usual procedures, DTC mails an Omnibus Proxy to us as soon as possible after the record date for any event giving holders of Debentures a voting opportunity. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those direct participants to whose accounts the Debentures are credited on the record date (identified in a listing attached to the Omnibus Proxy).
o Principal and interest payments on the Debentures will be made to Cede & Co., or such other nominee as may be requested by DTC. DTC's practice is to credit direct participants' accounts on the relevant payment date in accordance with their respective holdings shown on DTC's records unless DTC has reason to believe that it will not receive payment on such payment date. Payments by direct or indirect participants to beneficial owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such direct or indirect participants and not of DTC, the trustee, you or us, subject to any statutory or regulatory requirements as may be in effect from
time to time. Payment or principal and interest to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) will be the responsibility of the trustee as paying agent under the indenture, disbursement of payments to direct participants will be the responsibility of DTC, and further disbursement of payments to the beneficial owners will be the responsibility of direct and indirect participants.
So long as DTC is the registered owner of the Debentures, we and the trustee will consider DTC as the sole owner or holder of the Debentures for all purposes under the indenture and any applicable laws. As a beneficial owner of interests in the Debentures, you will not be entitled to receive a physical certificate representing your ownership interest and you will not be considered an owner or holder of the Debentures under the indenture, except as otherwise provided below. You, as a beneficial owner, will have the right to sell, transfer or otherwise dispose of an interest in the Debentures and the right to receive the proceeds from the Debentures and all interest, principal and premium payable on the Debentures. Your beneficial interest in the Debentures will be recorded, in integral multiples of $1,000, on the records of DTC's direct participant that maintains your account. In turn, this interest held by DTC's direct participant in the Debentures will be recorded, in integral multiples of $1,000, on the computerized records of DTC. Beneficial ownership of the Debentures may be transferred only by compliance with the procedures of DTC and the DTC direct (or, as applicable, indirect) participant that maintains your account.
All rights of ownership must be exercised through DTC and the book-entry system, except that you are entitled to exercise directly your rights under Section 316(b) of the Trust Indenture Act of 1939 with respect to the payment of interest and principal on the Debentures. Notices that we or the trustee give under the indenture will be given only to DTC. We expect DTC will forward the notices to its participants by its usual procedures, so that its participants may forward the notices to the beneficial owners like yourself. Neither we nor the trustee will have any responsibility or obligation to assure that any notices are forwarded by DTC to its direct participants or by its direct participants to the beneficial owners of the Debentures.
DTC may discontinue providing its services as securities depository for the Debentures at any time by giving reasonable written notice to us and the trustee. Under such circumstances, and in the event that we do not obtain a successor securities depository, we will deliver Debenture certificates to the beneficial owners. We may decide to replace DTC or any successor depository. Additionally, we may decide to discontinue use of the system of book-entry transfers through DTC or a successor depository. In that event, we will print and deliver to the beneficial owners certificates for the Debentures.
According to DTC, the foregoing information with respect to DTC is provided to the financial community for informational purposes only and is not intended to serve as a representation, warranty or contract modification of any kind. The information in this section concerning DTC and DTC's book-entry system and procedures has been obtained from third-party sources that we believe are reliable. Neither we, the underwriter nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership of the Debentures or for maintaining, supervising or reviewing any records relating to the beneficial ownership of Debentures.
Except as provided in this prospectus, you and other beneficial owners of the Debentures may not receive physical delivery of Debentures. Accordingly, you and each other beneficial owner must rely on the procedures of DTC to exercise any rights under the Debentures.
INTEREST AND PAYMENT
The Debentures will mature on January 1, 2023. The Debentures will bear interest from the date of issuance at the annual interest rate stated on the cover page of this prospectus. The amount of interest payable will be calculated on the basis of a 360-day year of twelve 30-day months. Interest will be payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year, beginning on April 1, 2003. Interest will be paid to the persons in whose names the Debentures are registered at the close of business on the 15th day of the month immediately preceding the applicable interest payment date. If any payment date would otherwise be a day that is a holiday under the indenture, which includes each Saturday, Sunday and other bank holidays, the payment will be postponed to the next day that is not a holiday. No interest will
accrue on an interest payment for the period from and after a scheduled payment date that is postponed because of a holiday.
So long as DTC is the registered owner of the Debentures, the trustee as paying agent will make payments of interest, principal and premium on the Debentures to DTC. DTC will be responsible for crediting the amount of the distributions to the accounts of its participants entitled to the distributions, in accordance with DTC's normal procedures. Each of DTC's direct participants will be responsible for disbursing distributions to indirect participants, if applicable, or to you and the other beneficial owners of the interests in Debentures that it represents.
Neither we nor the trustee will have any responsibility or liability for any aspect of:
o the records relating to, notices to, or payments made on account of, beneficial ownership interests in the Debentures, including your interest;
o maintaining, supervising or reviewing any records relating to beneficial ownership interests in the Debentures, including your interest;
o the selection of any beneficial owner, including you, of the Debentures to receive payment in the event of a partial redemption of the global security; or
o consents given or other action taken on behalf of any beneficial owner, including you, of the Debentures.
OPTIONAL REDEMPTION
Under the indenture, we have the option to redeem all or part of the Debentures before their stated maturity. We may redeem all or part of the Debentures at any time on or after , 2007. If we redeem all or part of the Debentures from , 2007 through , 2008, we must pay 102% of the principal amount of the Debentures being redeemed, plus accrued interest on those Debentures up to the date of such redemption. If we redeem all or part of the Debentures from , 2008 through , 2009, we must pay 101% of the principal amount of the Debentures being redeemed, plus accrued interest on those Debentures up to the date of such redemption. If we redeem all or part of the Debentures after , 2009, we must pay 100% of the principal amount of the Debentures being redeemed, plus accrued interest on those Debentures up to the date of such redemption.
If we redeem fewer than all the Debentures, the trustee will select by lot the particular Debentures to be redeemed.
We will give notice of redemption at least thirty days before the date of redemption to each holder of Debentures to be redeemed at the holder's registered address. We may rescind any notice of redemption at any time at least five days prior to the date of redemption.
On and after the date of redemption, interest will cease to accrue on Debentures or portions thereof redeemed. However, interest will continue to accrue if we default in the payment of the amount due upon redemption.
LIMITED RIGHT OF REDEMPTION UPON DEATH OF BENEFICIAL OWNER
Unless the Debentures have been declared due and payable prior to their maturity by reason of an event of default under the indenture, the representative of a deceased beneficial owner of interests in the Debentures has the right at any time to request redemption prior to stated maturity of all or part of his interest in the Debentures. We will redeem these interests in the Debentures subject to the limitations that we will not be obligated to redeem, during the period from the original issue date through and including , 2004 (known as the "initial period"), and during any twelve-month period which ends on and includes each thereafter (each such twelve-month period being known as a "subsequent period"), on behalf of a deceased beneficial owner any interest in the Debentures which exceeds $25,000 principal amount or interests in the Debentures exceeding $400,000 in aggregate principal amount.
We may, at our option, redeem interests of any deceased beneficial owner in the Debentures in the initial period or any subsequent period in excess of the $25,000 limitation. Any such redemption, to the extent that it exceeds the $25,000 limitation for any deceased beneficial owner, will not be included in the computation of the $400,000 aggregate limitation for that initial period or that subsequent period, as the case may be, or for any succeeding subsequent period. We may, at our option, redeem interests of deceased beneficial owners in the Debentures, in the initial period or any subsequent period, in an aggregate principal amount exceeding $400,000. Any redemption so made, to the extent it exceeds the $400,000 aggregate limitation, will not reduce the $400,000 aggregate limitation for any subsequent period. If we elect to redeem Debentures in excess of the $25,000 limitation or the $400,000 aggregate limitation, Debentures so redeemed will be redeemed in the order of the receipt of redemption requests by the trustee.
A request for redemption of an interest in the Debentures may be initiated by the representative of the deceased beneficial owner. For purposes of making a redemption request, the representative of a deceased beneficial owner is any person who is the personal representative or other person authorized to represent the estate of the deceased beneficial owner or the surviving joint tenant or tenant(s) by the entirety or the trustee of a trust. The representative must deliver a request to the participant through whom the deceased beneficial owner owned the interest to be redeemed, in form satisfactory to the participant, together with evidence of the death of the beneficial owner, evidence of the authority of the representative satisfactory to the participant, such waivers, notices or certificates as may be required under applicable state or federal law and such other evidence of the right to redemption as the participant may require. The request will specify the principal amount of the interest in the Debentures to be redeemed. The participant will thereupon deliver to DTC a request for redemption substantially in the form attached as Appendix A to this prospectus (known as the "redemption request"). DTC will, on receipt of a redemption request, forward the redemption request to the trustee. The trustee will maintain records with respect to redemption requests received by it including date of receipt, the name of the participant filing the redemption request and the status of each redemption request with respect to the $25,000 limitation and the $400,000 aggregate limitation. The trustee will immediately file with us each redemption request it receives, together with the information regarding the eligibility of that redemption request with respect to the $25,000 limitation and the $400,000 aggregate limitation. We, DTC and the trustee may conclusively assume, without independent investigation, that the statements contained in each redemption request are true and correct, and will have no responsibility for reviewing any documents submitted to the participant by the representative. We, DTC and the trustee will also have no responsibility for determining whether the applicable decedent is in fact the beneficial owner of the interest in the Debentures to be redeemed or is in fact deceased and whether the representative is duly authorized to request redemption on behalf of the applicable beneficial owner.
Subject to the $25,000 limitation and the $400,000 aggregate limitation, we will, after the death of any beneficial owner, redeem the interest of that beneficial owner in the Debentures within 60 days following our receipt of a redemption request from the trustee. If redemption requests exceed the $400,000 aggregate limitation during the initial period or during any subsequent period, then the excess redemption requests will be applied in the order received by the trustee to successive subsequent periods, regardless of the number of subsequent periods required to redeem such interests. We may, at any time, notify the trustee that we will redeem, on a date not less than 30 or more than 60 days after that notice, all or any lesser amount of Debentures for which redemption requests have been received but which are not then eligible for redemption by reason of the $25,000 limitation or the $400,000 aggregate limitation. If we so elect to redeem excess Debentures, we will redeem these excess Debentures in the order of receipt of redemption requests by the trustee.
The price we will pay for the interests in the Debentures to be redeemed pursuant to a redemption request is 100% of the principal amount of the interests plus accrued but unpaid interest to the date of payment. Subject to arrangements with DTC, payment for interests in the Debentures which are to be redeemed will be made to DTC upon presentation of Debentures to the trustee for redemption in the aggregate principal amount specified in the redemption requests submitted to the trustee by DTC which are to be fulfilled in connection with that payment. The principal amount of any Debentures we acquire or redeem, other than by redemption at the option of any representative of a deceased beneficial owner, will
not be included in the computation of either the $25,000 limitation or the $400,000 aggregate limitation for the initial period or for any subsequent period.
A beneficial owner, for purposes of determining if the representative of a deceased person may make a proper redemption request, is the person who has the right to sell, transfer or otherwise dispose of an interest in a Debenture and the right to receive the proceeds from that interest, as well as the interest and principal payable to the holder of the Debenture. In general, a determination of beneficial ownership in the Debentures will be subject to the rules, regulations and procedures governing DTC and its participants.
Any interest in a Debenture held in tenancy by the entirety, joint tenancy or by tenants in common will be considered to be held by a single beneficial owner and the death of a tenant by the entirety, joint tenant or tenant in common will be considered the death of a beneficial owner. The death of a person who, during his lifetime, was entitled to substantially all of the rights of a beneficial owner of an interest in the Debentures will be considered the death of the beneficial owner, regardless of the recordation of such interest on the records of the participant, if such rights can be established to the satisfaction of the participant. These rights will be considered to exist in typical cases of nominee ownership, ownership under the Uniform Gifts to Minors Act or the Uniform Transfer to Minors Act, community property or other similar joint ownership arrangements, including individual retirement accounts or Keogh [H.R. 10] plans maintained solely by or for the decedent or by or for the decedent and any spouse, trusts and certain other arrangements where one person has substantially all of the rights of a beneficial owner during such person's lifetime.
In the case of a redemption request which is presented on behalf of a deceased beneficial owner and which has not been fulfilled at the time we give notice of our election to redeem the Debentures, the Debentures which are the subject of such pending redemption request will be redeemed prior to any other Debentures.
Any redemption request may be withdrawn by the person(s) presenting the redemption request upon delivery of a written request for withdrawal given by the participant on behalf of that person to DTC and by DTC to the trustee not less than 30 days prior to our payment with respect to that redemption request. We may, at any time, purchase any Debentures for which redemption requests have been received in lieu of redeeming those Debentures. Any Debentures we purchase in this manner will either be re-offered for sale and sold within 180 days after the date of purchase or presented to the trustee for redemption and cancellation.
During any time or times as the Debentures are not represented by a global certificate and are issued in definitive form,
o all references herein to participants and DTC, including DTC's governing rules, regulations and procedures, will be considered deleted,
o all determinations which under this section the participants are required to make will be made by us (including, without limitation, determining whether the applicable decedent is in fact the beneficial owner of the interest in the Debentures to be redeemed or is in fact deceased and whether the representative is duly authorized to request redemption on behalf of the applicable beneficial owner),
o all redemption requests, to be effective, must be delivered by the representative to the trustee, with a copy to us, and must be in the form of a redemption request (with appropriate changes to reflect the fact that the redemption request is being executed by a representative) and, in addition to all documents that are otherwise required to accompany a redemption request, must be accompanied by the Debenture that is the subject of the request.
NO SINKING FUND
The Debentures are not subject to a sinking fund requirement, which means we will not deposit money on a regular basis into any separate custodial account to repay the Debentures.
DEBENTURES NOT CONVERTIBLE
The Debentures are not convertible into any other security.
DEBENTURES UNSECURED
The Debentures are unsecured obligations and are equal in rank to all of our other unsecured and unsubordinated debt that may be outstanding at any time. Subject only to the restrictions described below, the indenture does not limit the amount of debt which we may incur.
RESTRICTIVE COVENANTS
Under the indenture, we agreed to the following restrictions:
o We, and our subsidiaries, may not create, issue, incur, guarantee or assume any long-term debt, which ranks prior to or equal to the Debentures in right of payment, unless, after the creation, issuance, incurrence or assumption of the additional long-term debt, the net book value of all of our and our subsidiaries' physical property is at least equal to all of our and our subsidiaries' then outstanding long-term debt. We are required to include the Debentures outstanding in calculating our long-term debt. For purposes of this debt limitation, long-term debt is generally calculated as any of our or our subsidiaries' indebtedness that is not payable on demand or not required to be paid within one year after the calculation is made. For purposes of this limitation, our and our subsidiaries' physical property is limited to physical property used or useful to us in the business of furnishing or distributing gas service as a public utility. As of June 30, 2002, after giving effect to the issuance of the Debentures and the application of the proceeds from the sale of the Debentures to reduce other long-term debt, the net book value of all of our and our subsidiaries' physical property would have exceeded our and our subsidiaries' long-term debt by $51,628,000.
o We may not declare or pay any dividends or make any other distribution upon our common stock, and we may not apply any of our assets to the redemption, retirement, purchase or other acquisition of any of our capital stock. This restriction does not apply:
* if after the declaration, payment, distribution or application of assets our shareholders' equity, less the book value of our and our subsidiaries' intangible assets, is at least equal to $25,800,000 as reflected on our then latest available balance sheet (our June 30, 2002 balance sheet, after giving effect to the issuance of the Debentures, reflects that our shareholders' equity, less the book value of our and our subsidiaries' intangible assets, is $34,182,277); or
* to dividends and distributions consisting only of shares of our common stock, but not cash or other property; or
* to purchases or redemptions of our preferred stock in compliance with any mandatory sinking fund, purchase fund or redemption requirement.
o We may not issue, assume or guarantee any debt secured by a lien on any property or asset that we own. However, this restriction does not apply, if prior to or at the same time as the issuance, assumption or guarantee of that debt, we equally and ratably secure the Debentures. This restriction is also subject to certain exceptions described in the indenture, which include liens securing debt having an aggregate outstanding principal balance of $5,000,000 or less.
Except as described above, the indenture does not afford any protection to holders of Debentures solely on account of our involvement in highly leveraged transactions.
SUCCESSOR CORPORATION
We agree in the indenture that we will not consolidate with, merge into or transfer or lease all or substantially all of our assets to another corporation, unless immediately after such transaction:
o no default will exist under the indenture;
o the other corporation assumes all of our obligations under the Debentures and the indenture; and
o certain other requirements are met.
EVENTS OF DEFAULT; NOTICE AND WAIVER
The following constitute events of default under the indenture:
o default in the payment of principal of the Debentures when due;
o default in the payment of any interest on the Debentures, when due, if continued for thirty days;
o default in the performance of any other agreement we have made in the Debentures or the indenture, if continued for sixty days after written notice;
o acceleration of certain of our or our subsidiaries' indebtedness for borrowed money under the terms of any instrument under which indebtedness of $100,000 or more is issued or secured; and
o certain events in bankruptcy, insolvency or reorganization involving us.
The trustee is required, within ninety days after the occurrence of a default, to give the holders of Debentures notice of all continuing defaults known to the trustee. However, in the case of a default in the payment of the principal or interest in respect of any of the Debentures, the trustee is protected in not giving notice if it in good faith determines that not giving notice is in the interest of the holders of the Debentures.
If any event of default occurs and is continuing, the trustee or the holders of at least twenty-five percent in principal amount of outstanding Debentures may declare the Debentures immediately due and payable. This acceleration may be rescinded by the holders of a majority in principal amount of the Debentures then outstanding, upon the conditions provided in the indenture.
The holders of a majority in principal amount of the Debentures may waive an existing default and its consequences, upon the conditions provided in the indenture. This right to waive the default and its consequences do not apply to:
o an uncured default in payment of principal or interest on the Debentures; or
o an uncured failure to make any redemption payment; or
o an uncured default of a provision which cannot be modified under the terms of the indenture without the consent of each holder of the Debentures affected.
Each year we must file with the trustee a statement regarding our compliance with the terms of the indenture. This statement must be filed within 120 days after the end of each fiscal year. Further, this statement must specify any defaults of which our officers signing the statement may have knowledge.
MODIFICATION OF THE INDENTURE
We, together with the trustee, may modify and amend the indenture in a manner that materially affects the rights of the holders of the Debentures only if we obtain the consent of the holders of not less than a majority in principal amount of the Debentures then outstanding.
We, together with the trustee, may only modify or amend the indenture in a manner that materially affects the rights of the holders of the Debentures and that:
o changes the stated maturity of any Debenture, or
o reduces the principal amount of or interest rate on any Debenture, or
o changes the interest payment date or otherwise modifies the terms of payment of the principal of or interest on the Debentures, or
o reduces the percentage required for any consent, waiver or modification, or
o modifies certain other provisions of the indenture,
with the consent of each holder of any Debenture affected by the modification or amendment.
DISCHARGE OF THE INDENTURE
The indenture will be discharged and canceled upon payment of all the Debentures. The indenture may also be discharged upon our deposit with the trustee of funds or U.S. Government obligations sufficient to pay the principal of and premium, if any, and interest on the Debentures. We may only deposit funds or U.S. Government obligations to discharge the indenture within a year or less of the maturity or redemption of all Debentures.
TRUSTEE
The indenture entitles the trustee to be indemnified by the holders of Debentures before proceeding to exercise any right or power under the indenture at the request of the holders of Debentures. This indemnification of the trustee is subject to the trustee's duty during default to act with the standard of care required in the indenture. The indenture provides that the holders of a majority in principal amount of the outstanding Debentures may direct the time, method and place of conducting any proceeding and any remedy available to the trustee or exercising any trust or power conferred upon the trustee.
Fifth Third Bank, the trustee and debenture registrar under the indenture, has its corporate trust office in Cincinnati, Ohio. In addition to serving as trustee and debenture registrar under the indenture, Fifth Third Bank serves as:
o registrar, transfer agent and dividend disbursement agent for our common stock,
o plan administrator and agent for our dividend reinvestment and stock purchase plan,
o trustee and debenture registrar for our 7.15% Debentures due 2018, and
o trustee and debenture registrar for our 8.30% Debentures due 2026.
UNDERWRITING
Edward D. Jones & Co., L.P. is the underwriter for this offering. Subject to the terms and conditions of the underwriting agreement, the underwriter has agreed to purchase, and we have agreed to sell to the underwriter, all of the Debentures. We have filed a copy of the underwriting agreement with the SEC.
The underwriting agreement provides that the obligations of the underwriter to purchase the Debentures are subject to the approval of a number of legal matters by its counsel as well as our counsel, and to other conditions. The underwriter is obligated to purchase all of the Debentures if it purchases any of the Debentures.
The underwriter proposes to offer the Debentures directly to the public initially at the public offering prices set forth on the cover page of this prospectus.
The following table shows the underwriting discount we will pay to the underwriter. These amounts show the discount paid per $1,000 purchase of the Debentures and the total for the purchase of all Debentures being offered.
PER $1,000
DEBENTURE TOTAL
---------- --------------
Public Offering Price $1,000.00 $20,000,000.00
Underwriting Discount $ $
Proceeds, Before Our Expenses $ $
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We estimate that our out-of-pocket expenses for this offering that are in addition to discounts we pay to the underwriters will be approximately $80,000.00.
The underwriter intends to make a market in the Debentures. However, the underwriter will have no obligation to make a market in the Debentures and may cease market making activities at any time. The Debentures will not be listed on any exchange.
Until the distribution of the Debentures is completed, the SEC's rules may limit the ability of the underwriter to bid for and purchase the Debentures. As an exception to these rules, the underwriter is permitted to engage in certain transactions that stabilize the price of the Debentures. These transactions consist of placing bids for or effecting purchases of the Debentures for the purpose of pegging, fixing or maintaining the price of the Debentures.
If the underwriter creates a short position in the Debentures in connection with the offering by selling more Debentures than are set forth on the cover page of this prospectus, the underwriter may reduce that short position by purchasing Debentures in the open market. In general, purchases of a security for the purpose of stabilization or to reduce a short position could cause the price of the security to be higher than it might be in the absence of such purchases.
We and the underwriter make no representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Debentures. In addition, we and the underwriter make no representations that the underwriter will engage in these types of transactions or that these transactions, once begun, will not be discontinued without notice.
The offering of the Debentures is made for delivery when, as and if accepted by the underwriter and subject to prior sale and to withdrawal, cancellation or modification of the offer without notice. The underwriter reserves the right to reject any order for the purchase of Debentures in whole or in part.
We have agreed to indemnify the underwriter and persons who control the underwriter against certain liabilities that may be incurred in connection with the offering, including liabilities under the Securities Act of 1933.
LEGAL MATTERS
Our special counsel, Stoll, Keenon & Park, LLP, Lexington, Kentucky, will pass on the validity of the Debentures and will opine that the Debentures, when sold, will be our binding obligations. Certain other matters will be passed upon for the underwriter by its counsel, Armstrong Teasdale LLP, St. Louis, Missouri.
Attorneys in the firm of Stoll, Keenon & Park, LLP, and members of such attorneys' immediate families, own collectively 7,901 shares of our common stock. Attorneys of Stoll, Keenon & Park, LLP participating in this Debenture offering on behalf of the firm account for 7,454 of these shares.
EXPERTS
The financial statements as of June 30, 2002 and for the year ended June 30, 2002, included in this prospectus, and the related financial statement schedule for the year ended June 30, 2002, incorporated by reference in this prospectus, have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports appearing herein and elsewhere in the registration statement, and have been so included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.
Arthur Andersen LLP, independent public accountants, audited our consolidated financial statements and schedules for the fiscal years ending June 30, 2000 and 2001, included and incorporated by reference in this prospectus, and elsewhere in the registration statement filed in connection with this prospectus, as indicated in their reports with respect to those financial statements and schedules. We include those financial statements and schedules in this prospectus in reliance upon the authority of Arthur Andersen LLP as experts in giving those reports. After reasonable efforts we have not been able to obtain the written consent of Arthur Andersen LLP permitting us to name it in this prospectus as having certified our financial statements for the two fiscal years ended June 30, 2001. This lack of consent will limit your ability to assert claims against Arthur Andersen as explained under the heading "Risk Factors."
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and special reports, proxy statements, and other information with the SEC. Instead of repeating the information that we have already filed with the SEC, the SEC allows us to "incorporate by reference" in this prospectus information contained in documents we have filed with the SEC. Those documents form an important part of this prospectus.
We incorporate by reference the following reports that we previously filed with the SEC:
* Our Annual Report on Form 10-K (SEC File Number: 1.000-08788) for the year ended June 30, 2002 and our amendment to our Annual Report on Form 10-K for the year ended June 30, 2002 that we filed with the SEC on September 16, 2002;
* Our Quarterly Report on Form 10-Q (SEC File Number: 1.000-08788) for the quarterly period ended September 30, 2002; and
* Our Current Report on Form 8-K (SEC File Number: 1.000-08788) dated November 22, 2002 that we filed with the SEC on November 22, 2002.
We will provide to each person, including any beneficial owner, to whom this prospectus is delivered, a copy of any or all of the information that has been incorporated by reference in this prospectus but not
delivered with this prospectus. This additional information will be provided upon a written or oral request and at no cost to the requester. Requests for this information should be made to:
Mr. John F. Hall Vice President--Finance, Secretary and Treasurer Delta Natural Gas Company, Inc. 3617 Lexington Road Winchester, Kentucky 40391 Telephone: (859) 744-6171
As allowed by the SEC's rules, we have not included in this prospectus all of the information that is included in the registration statement. At your request, we will provide you, free of charge, with a copy of the registration statement, any of the exhibits to the registration statement, or a copy of any other filing we have made with the SEC. If you want more information, write in care of or call Mr. John F. Hall at the above address.
You may also obtain a copy of any filing we have made with the SEC directly from the SEC. You may either:
o read and copy any materials we file with the SEC at the SEC's public reference rooms at 450 Fifth Street, N.W., Washington, D.C. 20549 and at its offices in New York, New York and Chicago, Illinois; or
o visit the SEC's Internet site at http://www.sec.gov, which contains reports, proxy and information statements, and other information regarding issuers that file electronically.
You can obtain more information about the SEC's public reference room by calling the SEC at 1-800-SEC-0330.
REPORT OF INDEPENDENT AUDITORS
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 subsidiaries (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. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of the Company as of June 30, 2001 and for each of the two years in the period then ended were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated August 10, 2001.
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.
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 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.
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
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
Deferred (advance recovery of)
gas cost 368,648 (4,518,953) (1,124,219)
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
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 1,461,440 --
(Note 4)
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
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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:
2002 2001
----- -----
REGULATORY ASSETS ($000)
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
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
=========== ===========
|
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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%
==== ==== ====
|
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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.
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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.
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 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.
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(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 Delta 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 transportation revenue 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
====== ======= =======
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DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
($000) 2002 2001 2000
------- ------- -------
OTHER INCOME AND DEDUCTIONS
Regulated 17 31 43
Non-regulated -- -- --
------- ------- -------
Total other income and deductions 17 31 43
======= ======= =======
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
======= ======= =======
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DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(12) QUARTERLY FINANCIAL DATA (UNAUDITED)
The quarterly data reflect, 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
QUARTER ENDED REVENUES INCOME (LOSS) SHARE(a)
------------- ----------- ---------- ----------- ---------------
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.
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DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
THREE MONTHS ENDED TWELVE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- -----------------------------
2002 2001 2002 2001
---------- ---------- ----------- -----------
OPERATING REVENUES...................... $7,153,282 $7,258,892 $55,824,171 $71,306,859
---------- ---------- ----------- -----------
OPERATING EXPENSES
Purchased gas....................... $3,626,250 $3,647,286 $30,136,188 $44,598,018
Operation and maintenance........... 2,444,638 2,282,667 9,847,719 10,007,653
Depreciation and depletion.......... 1,042,502 977,311 4,146,135 3,834,062
Taxes other than income taxes....... 364,826 347,723 1,372,015 1,426,896
Income taxes........................ (556,543) (475,400) 2,168,357 2,391,275
---------- ---------- ----------- -----------
Total operating expenses........ $6,921,673 $6,779,587 $47,670,414 $62,257,904
---------- ---------- ----------- -----------
OPERATING INCOME........................ $ 231,609 $ 479,305 $ 8,153,757 $ 9,048,955
OTHER INCOME AND DEDUCTIONS, NET........ 11,273 5,551 22,739 23,502
---------- ---------- ----------- -----------
INCOME BEFORE INTEREST CHARGES.......... $ 242,882 $ 484,856 $ 8,176,496 $ 9,072,457
INTEREST CHARGES........................ 1,145,759 1,263,181 4,664,335 5,159,078
---------- ---------- ----------- -----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE... $ (902,877) $ (778,325) $ 3,512,161 $ 3,913,379
CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE (NOTE 3)......... (88,370) -- (88,370) --
---------- ---------- ----------- -----------
NET INCOME (LOSS)....................... $ (991,247) $ (778,325) $ 3,423,791 $ 3,913,379
========== ========== =========== ===========
BASIC AND DILUTED EARNINGS (LOSS) PER
COMMON SHARE BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE... $ (.36) $ (.31) $ 1.39 $ 1.57
CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE.................. (.03) -- (.03) --
---------- ---------- ----------- -----------
BASIC AND DILUTED EARNINGS (LOSS) PER
COMMON SHARE.......................... $ (.39) $ (.31) $ 1.36 $ 1.57
========== ========== =========== ===========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING (BASIC AND DILUTED)....... 2,537,691 2,502,139 2,523,041 2,487,268
DIVIDENDS DECLARED PER COMMON SHARE..... $ .295 $ .29 $ 1.165 $ 1.145
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DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
SEPTEMBER 30, 2002 JUNE 30, 2002 SEPTEMBER 30, 2001
------------------ ------------- ------------------
ASSETS
GAS UTILITY PLANT............................ $158,780,385 $156,305,063 $150,247,189
Less-Accumulated provision for
depreciation........................... (50,140,256) (49,142,976) (46,348,616)
------------ ------------ ------------
Net gas plant........................ $108,640,129 $107,162,087 $103,898,573
------------ ------------ ------------
CURRENT ASSETS
Cash and cash equivalents................ $ 287,667 $ 225,236 $ 645,947
Accounts receivable--net................. 1,781,760 2,884,025 2,024,498
Gas in storage........................... 8,662,990 5,216,772 9,986,633
Deferred gas costs....................... 4,944,273 4,076,059 6,264,749
Materials and supplies................... 545,014 523,756 578,204
Prepayments.............................. 399,222 388,794 308,998
------------ ------------ ------------
Total current assets................. $ 16,620,926 $ 13,314,642 $ 19,809,029
------------ ------------ ------------
OTHER ASSETS
Cash surrender value of officers' life
insurance.............................. $ 344,687 $ 344,687 $ 354,891
Note receivable from officer............. 152,000 158,000 122,000
Prepaid pension benefit cost............. 2,092,344 2,325,944 2,178,508
Unamortized debt expense and other....... 4,607,915 4,643,165 3,324,921
------------ ------------ ------------
Total other assets................... $ 7,196,946 $ 7,471,796 $ 5,980,320
------------ ------------ ------------
Total assets......................... $132,458,001 $127,948,525 $129,687,922
============ ============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CAPITALIZATION
Common shareholders' equity.............. $ 32,748,493 $ 34,182,277 $ 31,489,678
Long-term debt........................... 48,547,000 48,600,000 49,151,940
------------ ------------ ------------
Total capitalization................. $ 81,295,493 $ 82,782,277 $ 80,641,618
------------ ------------ ------------
CURRENT LIABILITIES
Notes payable............................ $ 26,945,000 $ 19,355,000 $ 25,130,000
Current portion of long-term debt........ 1,750,000 1,750,000 2,450,000
Accounts payable......................... 2,878,974 4,077,983 4,079,618
Accrued taxes............................ (143,789) 673,873 392,369
Refunds due customers.................... 69,658 73,973 114,023
Customers' deposits...................... 433,663 440,568 430,866
Accrued interest on debt................. 1,542,860 1,162,956 1,568,222
Accrued vacation......................... 558,066 558,066 538,595
Other accrued liabilities................ 401,818 503,178 315,628
------------ ------------ ------------
Total current liabilities............ $ 34,436,250 $ 28,595,597 $ 35,019,321
------------ ------------ ------------
DEFERRED CREDITS AND OTHER
Deferred income taxes.................... $ 14,078,273 $ 14,078,273 $ 12,851,457
Investment tax credits................... 404,600 404,600 449,800
Regulatory liability..................... 555,650 562,025 626,350
Additional minimum pension liability..... 1,461,440 1,461,440 --
Advances for construction and other...... 226,295 64,313 99,376
------------ ------------ ------------
Total deferred credits and other..... $ 16,726,258 $ 16,570,651 $ 14,026,983
------------ ------------ ------------
Total liabilities and
shareholders' equity........... $132,458,001 $127,948,525 $129,687,922
============ ============ ============
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DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
THREE MONTHS ENDED TWELVE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------- -------------------------------
2002 2001 2002 2001
----------- ----------- ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)................ $ (991,247) $ (778,325) $ 3,423,791 $ 3,913,379
Adjustments to reconcile net
income (loss) to net cash from
operating activities
Cumulative effect of a change
in accounting principle.... 88,370 -- 88,370 --
Depreciation, depletion and
amortization............... 1,082,525 1,029,639 4,311,088 4,042,141
Deferred income taxes and
investment tax credits..... (6,375) (6,375) 1,110,916 2,332,458
Other, net................... 136,731 169,100 563,526 685,551
(Increase) decrease in assets.... (2,995,112) (3,585,815) 1,466,218 (8,368,666)
Increase (decrease) in
liabilities.................... (1,705,121) (1,442,997) (227,468) 385,441
----------- ----------- ------------ ------------
Net cash provided by (used
in) operating activities... $(4,390,229) $(4,614,773) $ 10,736,441 $ 2,990,304
----------- ----------- ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures............. $(2,641,803) $(2,627,824) $ (9,435,745) $ (8,221,229)
----------- ----------- ------------ ------------
Net cash used in investing
activities................. $(2,641,803) $(2,627,824) $ (9,435,745) $ (8,221,229)
----------- ----------- ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on common stock........ $ (748,957) $ (725,895) $ (2,939,481) $ (2,848,103)
Issuance of common stock, net.... 306,420 239,338 774,505 678,133
Repayment of long-term debt...... (53,000) (119,000) (1,309,000) (703,000)
Issuance of notes payable........ 11,610,000 12,940,000 35,530,000 54,815,000
Repayment of notes payable....... (4,020,000) (4,610,000) (33,715,000) (46,485,000)
----------- ----------- ------------ ------------
Net cash provided by (used
in) financing activities... $ 7,094,463 $ 7,724,443 $ (1,658,976) $ 5,457,030
----------- ----------- ------------ ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................... $ 62,431 $ 481,846 $ (358,280) $ 226,105
CASH AND CASH EQUIVALENTS, BEGINNING
OF PERIOD.......................... 225,236 164,101 645,947 419,842
----------- ----------- ------------ ------------
CASH AND CASH EQUIVALENTS, END OF
PERIOD............................. $ 287,667 $ 645,947 $ 287,667 $ 645,947
=========== =========== ============ ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION
Cash paid during the period for
Interest....................... $ 725,565 $ 833,078 $ 4,528,537 $ 5,160,986
Income taxes (net of refunds).... $ 301,900 $ 47,700 $ 1,384,766 $ 145,712
|
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(1) Delta Natural Gas Company, Inc. has three wholly-owned subsidiaries. Delta Resources, Inc. 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 of our subsidiaries are included in the consolidated financial statements. Intercompany balances and transactions have been eliminated.
(2) In our opinion, all adjustments necessary for a fair presentation of the unaudited results of operations for the three and twelve months ended September 30, 2002 and 2001, respectively, are included. All such adjustments are accruals of a normal and recurring nature. The results of operations for the period ended September 30, 2002 are not necessarily indicative of the results of operations to be expected for the full year. The accompanying financial statements are unaudited and should be read in conjunction with the financial statements, which are incorporated herein by reference to our Annual Report on Form 10-K for the year ended June 30, 2002. Certain reclassifications have been made to prior-period amounts to conform to the 2002 presentation.
(3) In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, entitled Accounting for Asset Retirement Obligations, and Delta adopted this statement effective July 1, 2002. Statement No. 143 addresses financial accounting for legal obligations associated with the retirement of long-lived assets. Upon adoption of this statement, we recorded $178,000 of asset retirement obligations in the balance sheet primarily representing the current estimated fair value of our obligation to plug oil and gas wells at the time of abandonment. Of this amount, $47,000 was recorded as incremental cost of the underlying property, plant and equipment. The cumulative effect on earnings of adopting this new statement was a charge to earnings of approximately $88,000 (net of income taxes of approximately $55,000), representing the cumulative amounts of depreciation and changes in the asset retirement obligation due to the passage of time for historical accounting periods. The adoption of the new standard did not have a significant impact on income (loss) before cumulative effect of a change in accounting principle for the three and twelve months ended September 30, 2002. Pro forma net income and earnings per share have not been presented for the three months ended September 30, 2001 and for the twelve months ended September 30, 2002 and 2001 because the pro forma application of Statement No. 143 to prior periods would result in pro forma net income and earnings per share not materially different from the actual amounts reported for those periods in the accompanying consolidated statements of income.
(4) In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 144, entitled Accounting for the Impairment or Disposal of Long-Lived Assets. Statement No. 144 addresses accounting and reporting for the impairment or disposal of long-lived assets. Statement No. 144 was effective July 1, 2002. The impact of implementation on our financial position or results of operations was not material.
(5) In June 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 146, entitled Accounting for Costs Associated with Exit or Disposal Activities. Statement No. 146 addresses financial reporting and accounting for costs associated with exit or disposal activities. This statement requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and is effective for exit or disposal activities that are initiated after December 31, 2002. We have not committed to any such exit or disposal plan. Accordingly, this new statement will not presently have any impact on us.
(6) The American Institute of Certified Public Accountants has issued an exposure draft Statement of Position, entitled Accounting for Certain Costs and Activities Related to Property, Plant and Equipment. This proposed statement will apply to all nongovernmental entities that acquire, construct or replace tangible property, plant, and equipment. A significant element of the statement requires that entities use component accounting to the extent future component replacement will be capitalized. At adoption, entities would have the option to apply component accounting retroactively for all such assets, to the extent
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
applicable, or to apply component accounting as an entity incurs capitalizable costs that replace all or a portion of property, plant and equipment. We are currently analyzing the impact of this proposed statement, which has a proposed effective date of January 1, 2003.
(7) In September 2002, our Board of Directors approved an amendment to our Company's Defined Benefit Retirement Plan, effective November 1, 2002. The plan amendment reduced the formula for benefits paid under the plan for future service and restricted participants from taking lump-sum distributions from the plan. Monthly pension expense is currently $71,000. After the amendment becomes effective, monthly pension expense will be $26,000.
(8) During July 2001, the Kentucky Public Service Commission 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 Kentucky Public Service Commission indicated that Kentucky distributors had generally developed sound planning and procurement procedures for meeting their customers' natural gas requirements and that these procedures had provided customers with a reliable supply of natural gas at reasonable costs. The Kentucky Public Service Commission 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 Kentucky Public Service Commission are currently completing this audit. We have received a draft of the consultants' report and have reviewed it and commented 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, gas cost recovery mechanisms, budget billing, uncollectible accounts and forecasting. We cannot predict how the Kentucky Public Service Commission will interpret or act on any audit recommendations. As a result, we cannot predict the impact of this regulatory proceeding on our financial position or results of operations.
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (CONTINUED)
(9) External and intersegment revenues and net income (loss) by business segment are shown below:
THREE MONTHS ENDED TWELVE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
($000) --------------------- ---------------------
2002 2001 2002 2001
------- ------- ------- -------
Revenues
Regulated
External customers........................... 3,466 3,535 40,303 48,901
Intersegment................................. 709 723 3,036 3,265
------- ------- ------- -------
Total regulated.......................... 4,175 4,258 43,339 52,166
------- ------- ------- -------
Non-regulated
External customers........................... 3,687 3,724 15,521 22,406
Intersegment................................. -- 996 694 5,527
------- ------- ------- -------
Total non-regulated...................... 3,687 4,720 16,215 27,933
------- ------- ------- -------
Eliminations for intersegment.................... (709) (1,719) (3,730) (8,792)
------- ------- ------- -------
Total operating revenues................. 7,153 7,259 55,824 71,307
======= ======= ======= =======
Net Income (Loss)
Regulated........................................ (1,114) (1,108) 2,614 2,719
Non-regulated.................................... 123 330 810 1,194
------- ------- ------- -------
Total net income (loss).................. (991) (778) 3,424 3,913
======= ======= ======= =======
|
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 for the three and twelve months ending September 30, 2002.
THIS PAGE INTENTIONALLY LEFT BLANK
APPENDIX A
FORM OF REDEMPTION REQUEST
DELTA NATURAL GAS COMPANY, INC.
% DEBENTURES DUE JANUARY 1, 2023
(THE "DEBENTURES")
CUSIP NO.
The undersigned, (the "Participant"), does hereby certify, pursuant to the provisions of that certain Indenture dated as of January 1, 2003 (the "Indenture") made by Delta Natural Gas Company, Inc. (the "Company") and Fifth Third Bank, as Trustee (the "Trustee"), to The Depositary Trust Company (the "Depositary"), the Company, and the Trustee that:
1. [Name of deceased Beneficial Owner] is deceased.
2. [Name of deceased Beneficial Owner] had a $ interest in the above referenced Debentures.
3. [Name of Representative] is [Beneficial Owner's personal representative/other person authorized to represent the estate of the Beneficial Owner/surviving joint tenant/surviving tenant by the entirety/trustee of a trust] of [Name of deceased Beneficial Owner] and has delivered to the undersigned a request for redemption in form satisfactory to the undersigned, requesting that $ principal amount of said Debentures be redeemed pursuant to said Indenture. The documents accompanying such request, all of which are in proper form, are in all respects satisfactory to the undersigned and the [Name of Representative] is entitled to have the Debentures to which this Request relates redeemed.
4. The Participant holds the interest in the Debentures with respect to which this Redemption Request is being made on behalf of [Name of deceased Beneficial Owner].
5. The Participant hereby certifies that it will indemnify and hold harmless the Depositary, the Trustee and the Corporation (including their respective officers, directors, agents, attorneys and employees), against all damages, loss, cost, expense (including reasonable attorneys' and accountants' fees), obligations, claims or liability (collectively, the "Damages") incurred by the indemnified party or parties as a result of or in connection with the redemption of Debentures to which this Request relates. The Participant will, at the request of the Corporation, forward to the Corporation, a copy of the documents submitted by [Name of Representative] in support of the request for redemption.
IN WITNESS WHEREOF, the undersigned has executed this Redemption Request as of , .
[PARTICIPANT NAME]
THIS PAGE INTENTIONALLY LEFT BLANK
THIS PAGE INTENTIONALLY LEFT BLANK
WE HAVE NOT AUTHORIZED ANY DEALER, SALESPERSON OR OTHER PERSON TO GIVE ANY INFORMATION OR REPRESENT ANYTHING NOT CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION. IF ANYONE PROVIDES YOU WITH DIFFERENT OR INCONSISTENT INFORMATION, YOU SHOULD NOT RELY ON IT. THIS PROSPECTUS DOES NOT OFFER TO SELL ANY SECURITIES IN ANY JURISDICTION WHERE IT IS UNLAWFUL. THE INFORMATION IN THIS PROSPECTUS IS CURRENT AS OF THE DATE SHOWN ON THE COVER PAGE.
TABLE OF CONTENTS
PAGE
----
Prospectus Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Forward Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . 7
Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . 10
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Description of Debentures. . . . . . . . . . . . . . . . . . . . . . . . . . 23
Underwriting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Legal Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Experts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Where You Can Find More Information. . . . . . . . . . . . . . . . . . . . . 33
Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . . F-1
|
DELTA NATURAL GAS COMPANY, INC.
[DELTA LOGO]
$20,000,000 OF
% DEBENTURES DUE 2023
PROSPECTUS
EDWARD D. JONES & CO.,L.P.
, 2002
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following table sets forth all expenses in connection with the issuance and distribution of the securities being registered, other than underwriting discounts and commissions. Except for the registration fee, NASD filing fee and initial trustee fee, all the amounts shown are estimates.
Registration Fee..................................... $ 1,840.00
NASD Filing Fee...................................... 2,500.00
Blue Sky Fees and Expenses........................... 3,000.00
Accounting Fees...................................... 20,000.00
Legal Fees........................................... 35,000.00
Printing............................................. 10,000.00
Initial Trustee Fee.................................. 5,000.00
Miscellaneous Expenses............................... 2,660.00
----------
Total.............................................. $80,000.00
==========
|
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Indemnification of directors and officers of Kentucky corporations is governed by Sections 271B.8-500 through 271B.8-580 of the Kentucky Revised Statutes (the "Act"). The Act permits a corporation to provide insurance for directors and officers against claims arising out of their services in those capacities. The registrant provides its Directors and Officers with indemnification insurance coverage with limits up to $10,000,000.00.
Under the Act, a corporation may indemnify an individual against judgments, amounts paid in settlement, penalties, fines and reasonable expenses (included attorneys' fees) incurred by the individual in connection with any threatened or pending suit or proceeding or any appeal thereof (other than (1) an action by or in the right of the corporation in which the individual is adjudged liable to the corporation or (2) any proceeding charging improper personal benefit to the individual), whether civil or criminal, by reason of the fact that the individual is or was a director or officer of the corporation (or is or was serving at the request of the corporation as a director or officer, employee or agent of another corporation of any type or kind), if such director or officer:
(1) acted in good faith for a purpose;
(2) which the director or officer reasonably believed:
(a) to be in the best interest of the corporation; and
(b) in all cases not involving conduct in the director's or officer's official capacity, that the director's or officer's acts were at least not opposed to the best interest of the corporation; and
(3) in criminal actions or proceedings only, the director or the officer must have had no reasonable cause to believe his or her conduct was unlawful.
A Kentucky corporation's indemnification of a director or officer in connection with a proceeding by or in the right of the corporation is limited to reasonable expenses (including attorneys' fees) incurred in connection with the proceeding.
The registrant, under agreements with its Officers, has agreed to indemnify the Officers against liability for actions taken by them in good faith while performing services for the registrant and has agreed to pay legal expenses arising from any such proceedings.
Further, the registrant's bylaws have provisions requiring the registrant to indemnify its Officers and Directors, to the extent the Act permits such indemnification. Article VII of the registrant's Bylaws, entitled INDEMNIFICATION, provides as follows:
II-1
ARTICLE VII
Indemnification
7.1 Definitions. As used in this Article VII:
(a) "Proceeding" means any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, and whether formal or informal;
(b) "Party" includes a person who was, is or is threatened to be made a named defendant or respondent in a Proceeding;
(c) "Expenses" include attorneys' fees;
(d) "Officer" means any person serving as Chairman of the Board of Directors, President, Vice-President, Treasurer, Secretary or any other officer of the Corporation; and
(e) "Director" means an individual who is or was a director of the Corporation or an individual who, while a director of the Corporation, is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another foreign or domestic corporation, partnership, limited liability company, registered limited liability partnership, joint venture, association, trust, employee benefit plan or other enterprise. A Director shall be considered serving an employee benefit plan at the request of the Corporation if his or her duties to the Corporation also impose duties on, or otherwise involve services by, him or her to the plan or to participants in or beneficiaries of the plan. "Director" includes, unless the context requires otherwise, the estate or personal representative of a director.
7.2 Indemnification by Corporation.
(a) The Corporation shall indemnify any Officer or Director who is made a Party to any Proceeding by reason of the fact that such person is or was an Officer or Director if:
(1) Such Officer or Director conducted himself in good faith; and
(2) Such Officer or Director reasonably believed:
(i) In the case of conduct in his official capacity with the Corporation, that his conduct was in the best interests of the Corporation; and
(ii) In all other cases, that his conduct was at least not opposed to the best interests of the Corporation; and
(3) In the case of any criminal Proceeding, he had no reasonable cause to believe his conduct was unlawful.
(b) A Director's conduct with respect to an employee benefit plan for a purpose he reasonably believes to be in the interest of the participants in and beneficiaries of the plan shall be conduct that satisfies the requirement of Section 7.2 (a)(2)(ii).
(c) Indemnification shall be made against judgments, penalties, fines, settlements and reasonable expenses, including legal expenses, actually incurred by such Officer or Director in connection with the Proceeding, except that if the Proceeding was by or in the right of the Corporation, indemnification shall be made only against such reasonable Expenses and shall not be made in respect of any Proceeding in which the Officer or Director shall have been adjudged to be liable to the Corporation. The termination of any Proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, by itself, be determinative that the Officer or Director did not meet the requisite standard of conduct set forth in this Section 7.2.
(d) (1) Reasonable Expenses incurred by an Officer or Director as a Party to a Proceeding with respect to which indemnity is to be provided under this Section 7.2 shall be paid or reimbursed by the Corporation in advance of the final disposition of such Proceeding provided:
(i) The Corporation receives (I) a written affirmation by the
Officer or Director of his good faith belief that he has
met the requisite standard of conduct set forth in this
Section 7.2, and (II) the Corporation receives a written
undertaking by or on behalf of the Officer or Director to
II-2
repay such amount if it shall ultimately be determined that he has not met such standard of conduct; and
(ii) The Corporation's Board of Directors (or other appropriate decision maker for the Corporation) determines that the facts then known to the Board of Directors (or decision maker) would not preclude indemnification under Kentucky law.
(2) The undertaking required herein shall be an unlimited general obligation of the Officer or Director but shall not require any security and shall be accepted without reference to the financial ability of the Officer or Director to make repayment.
(3) Determinations and authorizations of payments under
this Section 7.2(d) shall be made in the manner specified in
Section 7.2(e) of these Bylaws.
(e) (1) The Corporation shall not indemnify an Officer or Director under this Section 7.2 unless authorized in the specific case after a determination has been made that indemnification of the Officer or Director is permissible in the circumstances because he has met the standard of conduct set forth in this Section 7.2.
(2) Such determination shall be made:
(i) By the Corporation's Board of Directors by majority vote of a quorum consisting of directors not at the time Parties to the Proceeding;
(ii) If a quorum cannot be obtained under Section 7.2(e)(2)(i), by majority vote of a committee duly designated by the Corporation's Board of Directors (in which designation directors who are Parties may participate), consisting solely of two (2) or more directors not at the time Parties to the Proceeding; or
(iii) By special legal counsel:
(I) Selected by the Corporation's Board of Directors or its committee in the manner prescribed in Sections 7.2(e)(2)(i) and (ii); or
(II) If a quorum of the Board of Directors cannot be obtained under Section 7.2(e)(2)(i) and a committee cannot be designated under Section 7.2(e)(2)(ii), selected by a majority vote of the full Board of Directors (in which selection directors who are Parties may participate); or
(3) Authorization of indemnification and evaluation as to reasonableness of expenses shall be made in the same manner as the determination that indemnification is permissible, except that if the determination is made by special legal counsel, authorization of indemnification and evaluation as to reasonableness of Expenses shall be made by those entitled under Section 7.2(e)(2)(iii) to select counsel.
7.3 Further Indemnification. Notwithstanding any limitation imposed by
Section 7.2 or elsewhere and in addition to the indemnification set forth in
Section 7.2, the Corporation, to the full extent permitted by law, may agree
by contract or otherwise to indemnify any Officer or Director and hold him
harmless against any judgments, penalties, fines, settlements and reasonable
expenses actually incurred or reasonably anticipated in connection with any
Proceeding in which any Officer or Director is a Party, provided the Officer
or Director was made a Party to such Proceeding by reason of the fact that
he is or was an Officer or Director of the Corporation or by reason of any
inaction, nondisclosure, action or statement made, taken or omitted by or on
behalf of the Officer or Director with respect to the Corporation or by or
on behalf of the Officer or Director in his capacity as an Officer or
Director.
7.4 Insurance. The Corporation may, in the discretion of the Board of Directors, purchase and maintain or cause to be purchased and maintained insurance on behalf of all Officers and Directors against any liability asserted against them or incurred by them in their capacity or arising out of their status as an Officer or Director, to the extent such insurance is reasonably available. Such insurance shall provide such coverage for the Officers and Directors as the Board of Directors may deem appropriate.
II-3
ITEM 16. EXHIBITS.
EXHIBIT
-------
1(a)* Form of Underwriting Agreement.
4(a) The Indenture dated September 1, 1993, in respect of 6.625%
Debentures, due 2023, is incorporated herein by reference to
Exhibit 4(d) to Registrant's Form S-2 dated September 2, 1993.
4(b) The Indenture dated July 1, 1996, in respect of 8.30% Debentures,
due 2026, is incorporated herein by reference to Exhibit 4(c) to
Registrant's Form S-2 dated June 21, 1996.
4(c) The Indenture dated April 1, 1998 in respect of 7.15% Debentures,
due 2018, is incorporated herein by reference to Exhibit 4(d) to
Registrant's Form S-2 dated March 11, 1998.
4(d)* Form of Indenture between Registrant and Fifth Third Bank, as Trustee
(including the Form of Global Security and Form of Debenture).
5* Opinion of Stoll, Keenon & Park, LLP concerning legality.
10(a) Employment agreements between Registrant and five officers, those
being John B. Brown, Johnny L. Caudill, John F. Hall, Alan L. Heath
and Glenn R. Jennings, are incorporated herein by reference to
Exhibit 10(k) to Registrant's Form 10-Q for the period ended
March 31, 2000.
10(b) Agreement between Registrant and Harrison D. Peet, Chairman of the
Board, is incorporated herein by reference to Exhibit 10(l) to
Registrant's Form 10-Q for the period ended March 31, 2000.
10(c)** Gas Sales Agreement, dated May 1, 2000, by and between the Registrant
and Woodward Marketing, L.L.C.
10(d)** Gas Sales Agreement, dated November 1, 1993, by and between the
Registrant and Dynegy Marketing and Trade (formerly known as Natural
Gas Clearinghouse) with First Amendment to Gas Sales Agreement and
Second Amendment to Gas Sales Agreement.
10(e)** Gas Transportation Agreement (Service Package 9069), dated December
19, 1994, by and between Tennessee Gas Pipeline Company and Registrant.
10(f)** GTS Service Agreement (Service Agreement No.: 37815), dated November 1,
1993, by and between Columbia Gas Transmission Corporation and Registrant.
10(g)** FTS1 Service Agreement (Service Agreement No.: 4328), dated October 4,
1994, by and between Columbia Gulf Transmission Company and Registrant.
10(h) Promissory Note, in the original principal amount of $40,000,000, made
by Registrant to the order of Branch Banking and Trust Company is
incorporated herein by reference to Exhibit 10(a) to Registrant's
Form 10-Q for the period ended September 30, 2002.
10(i)** Loan Agreement, dated October 31, 2002, by and between Branch
Banking and Trust Company and Registrant.
12** Computation of the consolidated ratio of earnings to fixed charges.
13(a) Registrant's Form 10-K for the period ended June 30, 2002, is
incorporated herein by reference.
16 Letter dated May 22, 2002 from Arthur Andersen LLP to the Securities
and Exchange Commission is incorporated herein by reference as
Exhibit 16 to Registrant's Form 8-K dated May 22, 2002.
23(a)** Independent Auditors' Consent and Report on Schedules of Deloitte &
Touche LLP.
23(c) Consent of Stoll, Keenon & Park is contained in its opinion letter
filed as Exhibit 5.
24* Power of Attorney is included with the signature page in Part II
of this Registration Statement.
25* Statement of eligibility of trustee.
---------
* Previously filed.
**As filed herewith.
|
II-4
ITEM 17. UNDERTAKINGS.
(a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to Directors, Officers and controlling persons of the registrant pursuant to the provisions referred to in Item 15, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a Director, Officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted against the registrant by such Director, Officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
(b) The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
II-5
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form S-2 and has duly caused this Pre-Effective Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Winchester, State of Kentucky, on the 13th day of December, 2002.
DELTA NATURAL GAS COMPANY, INC.
By: /s/ GLENN R. JENNINGS
------------------------------------------
Glenn R. Jennings
President and Chief Executive Officer
|
POWER OF ATTORNEY
Pursuant to the requirements of the Securities Act of 1933, this Pre-Effective Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
(i) Principal Executive Officer:
/s/ GLENN R. JENNINGS President, Chief Executive December 13, 2002 ------------------------ Officer and Vice Chairman (Glenn R. Jennings) of the Board |
(ii) Principal Financial Officer:
/s/ JOHN F. HALL Vice-President - Finance, December 13, 2002
------------------------ Secretary and Treasurer
(John F. Hall)
|
(iii) Principal Accounting Officer:
/s/ JOHN B. BROWN Controller December 13, 2002
------------------------
(John B. Brown)
|
(iv) A Majority of the Board of Directors:
* Chairman of the Board December 13, 2002
------------------------
(H. D. Peet)
* Director December 13, 2002
------------------------
(Donald R. Crowe)
* Director December 13, 2002
------------------------
(Jane Hylton Green)
II-6
|
Director , 2002
------------------------
(Lanny D. Greer)
* Director December 13, 2002
------------------------
(Billy Joe Hall)
* Director , 2002
------------------------
(Michael J. Kistner)
* Director December 13, 2002
------------------------
(Lewis N. Melton)
Director , 2002
------------------------
(Arthur E. Walker, Jr.)
* Director December 13, 2002
------------------------
(Michael R. Whitley)
*By: /s/ GLENN R. JENNINGS
---------------------
Glenn R. Jennings
Attorney-in-fact
|
II-7
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
---------- -----------
1(a)* Form of Underwriting Agreement.
4(a) The Indenture dated September 1, 1993, in respect of 6.625%
Debentures, due 2023, is incorporated herein by reference to
Exhibit 4(d) to Registrant's Form S-2 dated September 2, 1993.
4(b) The Indenture dated July 1, 1996, in respect of 8.30% Debentures,
due 2026, is incorporated herein by reference to Exhibit 4(c) to
Registrant's Form S-2 dated June 21, 1996.
4(c) The Indenture dated April 1, 1998 in respect of 7.15% Debentures,
due 2018, is incorporated herein by reference to Exhibit 4(d) to
Registrant's Form S-2 dated March 11, 1998.
4(d)* Form of Indenture between Registrant and Fifth Third Bank, as Trustee
(including the Form of Global Security and Form of Debenture).
5* Opinion of Stoll, Keenon & Park, LLP concerning legality.
10(a) Employment agreements between Registrant and five officers, those
being John B. Brown, Johnny L. Caudill, John F. Hall, Alan L. Heath
and Glenn R. Jennings, are incorporated herein by reference to
Exhibit 10(k) to Registrant's Form 10-Q for the period ended
March 31, 2000.
10(b) Agreement between Registrant and Harrison D. Peet, Chairman of the
Board, is incorporated herein by reference to Exhibit 10(l) to
Registrant's Form 10-Q for the period ended March 31, 2000.
10(c)** Gas Sales Agreement, dated May 1, 2000, by and between the Registrant
and Woodward Marketing, L.L.C.
10(d)** Gas Sales Agreement, dated November 1, 1993, by and between the
Registrant and Dynegy Marketing and Trade (formerly known as Natural
Gas Clearinghouse) with First Amendment to Gas Sales Agreement and
Second Amendment to Gas Sales Agreement.
10(e)** Gas Transportation Agreement (Service Package 9069), dated December
19, 1994, by and between Tennessee Gas Pipeline Company and Registrant.
10(f)** GTS Service Agreement (Service Agreement No.: 37815), dated November 1,
1993, by and between Columbia Gas Transmission Corporation and Registrant.
10(g)** FTS1 Service Agreement (Service Agreement No.: 4328), dated October 4,
1994, by and between Columbia Gulf Transmission Company and Registrant.
10(h) Promissory Note, in the original principal amount of $40,000,000, made
by Registrant to the order of Branch Banking and Trust Company is
incorporated herein by reference to Exhibit 10(a) to Registrant's
Form 10-Q for the period ended September 30, 2002.
10(i)** Loan Agreement, dated October 31, 2002, by and between Branch
Banking and Trust Company and Registrant.
12** Computation of the consolidated ratio of earnings to fixed charges.
13(a) Registrant's Form 10-K for the period ended June 30, 2002, is
incorporated herein by reference.
16 Letter dated May 22, 2002 from Arthur Andersen LLP to the Securities
and Exchange Commission is incorporated herein by reference as
Exhibit 16 to Registrant's Form 8-K dated May 22, 2002.
23(a)** Independent Auditors' Consent and Report on Schedules of Deloitte &
Touche LLP.
23(c) Consent of Stoll, Keenon & Park is contained in its opinion letter
filed as Exhibit 5.
24* Power of Attorney is included with the signature page in Part II
of this Registration Statement.
25* Statement of eligibility of trustee.
---------
* Previously filed.
**As filed herewith.
|
II-8
Exhibit 10(c)
THIS GAS SALES AGREEMENT made and entered into to be effective the 1st day of May, 2000, by and between the DELTA NATURAL GAS COMPANY, INC., a Kentucky corporation, hereinafter referred to as "Buyer", and WOODWARD MARKETING, L.L.C., a Delaware corporation, hereinafter referred to as "Seller".
WHEREAS, Buyer and Seller have entered into a Gas Sales Agreement ("Agreement"), to be effective May 1, 2000, providing for the purchase by the Buyer and sale by Seller on a firm basis of 100% of the natural gas requirements of Buyer's residential and small commercial customers and providing for certain other services of Seller to Buyer, and
WHEREAS, for the purpose of setting forth the terms of said agreements, the parties have agreed to this Agreement.
NOW, THEREFORE, for and in consideration of the covenants and agreements set forth herein, the parties agree as follows:
Unless expressly stated otherwise, the following terms as used in this Agreement shall mean:
1.1 The term "Btu" shall mean British Thermal Unit(s) which shall mean that amount of heat energy required to raise the temperature of one avoirdupois pound of water from fifty-nine-degrees Fahrenheit (59 F) to sixty-degrees Fahrenheit (60 F) at standard atmospheric pressure, as determined on a dry basis. All prices and charges paid hereunder shall be computed on a "dry" Btu basis.
1.2 The term "day" shall mean the period of time beginning at 9:00
a.m., Central Time Zone, on a calendar day and ending at 9:00 a.m., Central
Time Zone, on the following calendar day, or such other definition of day,
as may change from time to time, set forth in the tariff of Tennessee Gas
Pipeline Company ("Tennessee") on file with the Federal Energy Regulatory
Commission, or any successor agency.
1.3 The term "Delivery Point(s)" is defined in Article IV.
1.4 The term "gas" shall include casinghead gas, natural gas from gas wells, and residue gas resulting from processing casinghead gas and gas well gas.
1.5 The term "Liquefiable Hydrocarbons" means all hydrocarbons (except those hydrocarbons separated from the gas stream by conventional single-stage mechanical field separation methods) or any mixture thereof that may be extracted from the gas sold hereunder other than methane (except for the nominal quantities lost during such processing operations) including, but not limited to, natural gasolines, butane's, propane and ethane.
1.6 The term "Liquid Hydrocarbons" means any hydrocarbons which, in their natural state, are liquids and which shall include any Liquefiable Hydrocarbons that condense out of the gas stream during production or transportation.
1.7 The term "Mcf" shall mean one thousand (1,000) cubic feet at a pressure of fourteen and seventy-three-hundredths (14.73) pounds per square inch absolute and at a temperature of sixty degrees (60 F) Fahrenheit, with correction from Boyle's Law.
1.8 The Term "MEAC" means Municipal Energy Acquisition Corporation, an energy acquisition corporation as defined in Title 7, Chapter 39 of the Tennessee Code annotated, as amended.
1.9 The term "MMBtu" shall mean one million (1,000,000) Btu's.
1.10 The term "month" shall mean the period of time beginning on the first calendar day of each calendar month and ending on the first day of the following calendar month.
1.11 The term "year" shall mean a period of twelve (12) consecutive months, commencing on the first day of the month following the Effective Date, as defined in Article VI, and each subsequent twelve (12) month period; provided that the first year will include the period from the Effective Date until the first day of the following month if the Effective Date is not on the first day of a month.
requirements subject to section 2.2. Seller expressly acknowledges that a large percentage of the industrial/large commercial end users on Buyer's systems do not purchase gas from Buyer and arrange for their own gas supplies. Volumes flowing at the Delivery Point(s) for these end users shall be the first gas through Tennessee's meters, and Buyer's acceptance of these volumes on behalf of the end user(s) shall not constitute a violation of Seller's exclusive supplier provisions under this Agreement.
(a) If Seller fails to deliver to Buyer its
natural gas requirements up to the MDQ on any day, for reasons other than
(i) imbalances or variations under transportation agreements or operational
balancing agreements, which are governed by Article V or (ii) an event of
force majeure or an event described in Section 5.5, then Seller shall
reimburse or credit to Buyer for the following:
(1) Seller will reimburse Buyer for the sum of (a) the difference, if positive, between (i) the price Buyer pays for a substitute supply of gas or other alterative fuel such as propane and (ii) the prices set forth in Section 3.1.1 of this Agreement (calculated based upon Buyer's actual load factor under this Agreement) multiplied by the quantity Seller failed to deliver in accordance with this subsection, (b) any reasonable incremental costs and expenses incurred in transporting the substitute supplies and (c) any reasonable incidental expenses incurred in purchasing the substitute supplies. Buyer agrees to act in good faith in purchasing such
substitute supplies so as to minimize Seller's
obligations to Buyer hereunder; or
(2) If Buyer, through reasonable efforts, is unable
to obtain substitute supplies, then Seller shall
provide Buyer the difference between the highest
commodity price that was paid by Buyer for the
purchase of gas or an alterative fuel, such as
propane, during the last two years (not to exceed
$10 per MMBtu) and the prices set forth in
Section 3.1.1 of this Agreement (calculated based
upon Buyer's actual load factor under this
Agreement) multiplied by the quantity of gas
Seller failed to deliver in accordance with the
above.
the gas sold by Seller hereunder, including without limitation any volumetric transition costs, GRI charges, or ACA charges that are incurred under such contracts or any injection or withdrawal charges that are incurred under the Firm Storage Contracts that are required to build inventory levels for Buyer or to serve Buyer's daily requirements, (3) any transportation costs paid by Seller to Tennessee to transport the gas delivered to and from storage under the Firm Storage Contract, to the interconnection of Tennessee's facilities (herein referred to as the "IT Transportation Contract"), (4) any fuel and loss costs incurred under the Firm Transportation Contracts, the IT Transportation Contract and the Firm Storage Contracts, such costs to be equal to the amount of fuel and loss quantities that Seller provided to Tennessee pursuant to such contracts during the applicable month times the Commodity Price and (5) any other costs, expenses or charges incurred by Seller under such contracts (as such contracts and the associated tariff provisions and charges may change from time to time) that would have been incurred by Buyer if Buyer had administered such contracts. To the extent that Seller is reimbursed by Buyer in accordance with this section, Seller will indemnify and hold Buyer harmless from any claims made by Tennessee for the failure to make payments under the Firm Transportation Contracts or the Firm Storage Contracts. Seller shall be responsible for any charges incurred in connection with its utilization of Buyer's Firm Transportation or Firm Storage Contracts for purposes other than providing gas supply to Buyer. Seller shall credit Buyer 90% of revenue derived from third-party release of Buyer's Firm capacity as posted on Transporteras Electronic Bulletin Board.
thereto) are made timely to Tennessee and that such nominations reflect the actual expected deliveries and receipts.
expiration of the primary term, this Agreement will be extended for an additional year, unless on or before 60 days prior to the expiration of the primary term, either Party gives written notice to the other Party that it does not desire to extend the primary term.
Seller may process the gas to remove any Liquid Hydrocarbons or Liquefiable Hydrocarbons prior to the delivery of the gas to Buyer at the Delivery Point(s). In the event Seller elects to process the gas, any hydrocarbons so removed shall be Seller's sole responsibility and all costs (including associated transportation cost(s) shall be paid by Seller and Seller shall indemnify, defend and hold Buyer harmless therefrom.
Buyer: Delta Natural Gas Company, Inc. 3617 Lexington Road Winchester, KY 40391 Attention: Mr. Brian Ramsey Phone: 606-744-6171 Ext. 158 Fax: 606-744-3623 Email: bramsey@deltagas.com Seller: Nominations: Woodward Marketing, L.L.C. Woodward Marketing, L. L. C. 377 Riverside Drive, Suite 109 11251 Northwest Freeway, Suite 400 Franklin, TN 37064 Houston, TX 77092 Attention: Mr. Rob Ellis Attention: Mr. Rick Sullivan Phone: 615-595-2878 Phone: 713-688-7771 Fax: 615-794-0947 Fax: 713-688-5124 |
Either Buyer or Seller may choose one or more of its addresses for receiving invoices, statements, notices and payments by notifying the other in the manner as provided above. All written notices, requests, statements and invoices shall be considered transmitted at the time of delivery, if hand delivered, or, if delivered by mail, on the next working day after mailing; if transmitted by telephone or other oral means or by telecopy or other form of electronic or telegraphic communication, all such notices shall be considered transmitted at the time of oral communication or at the time the telecopy or other form of electronic or telegraphic communication was sent.
change will not otherwise affect the lawful obligations that arise under this Agreement.
IN WITNESS WHEREOF, this Agreement is executed in multiple counterparts, each of which is an original as of April 24, 2000.
DELTA NATURAL GAS COMPANY, INC. WOODWARD MARKETING, L.L.C.
By: /s/ ALAN L. HEATH By: /s/ ROB ELLIS
------------------------------ -----------------------------
Name: Alan L. Heath Name: Rob Ellis
--------------------------- --------------------------
Title: V.P. OPPS. & ENG. Title: Sr. Vice President
-------------------------- -----------------------
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BUYER: Delta Natural Gas Company, Inc.
Pursuant to the Gas Sales Agreement between Seller and Buyer, the Tennessee Gas Pipeline Company delivery points) for the natural gas service are as follows:
Delivery Points Meter Number --------------- ------------ Nicholasville 020248 Berea 020208 Jeffersonville 020430 Salt Lick 020212 Farmers 020462 Kinder Hilda 020733 Westbend 020813 Richmond 020895 |
BUYER: Delta Natural Gas Company, Inc.
Pursuant to the Gas Sales Agreement between Seller and Buyer, the Tennessee Gas Pipeline Company Pipeline and Storage contracts are as follows:
TGP Pipeline Capacity:
FT-G FT-A Total
---- ---- -----
January 16,211 1,400 17,611
February 16,211 1,400 17,611
March 11,050 1,400 12,450
April 8,075 1,400 9,475
May 6,150 1,400 7,550
June 4,276 1,400 5,676
July 4,248 1,400 5,648
August 4,248 1,400 5,648
September 4,246 1,400 5,826
October 7,144 1,400 8,544
November 10,275 1,400 11,675
December 16,211 1,400 17,611
TGP Storage Capacity:
MSQ MDWQ MDIQ
Production Area: 186,757 1,524 1,245
Market Area: 387,622 8,636 2,585
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Exhibit 10(d)
This Agreement is made and entered into as of the 1st day of November, 1993 by and between Delta Natural Gas Company, Inc. ("Buyer"), and Natural Gas Clearinghouse ("Seller"), both Buyer and Seller sometimes referred to collectively as "Parties" or singularly as "Party".
1.1 "Agreement" means the provisions of this document and those contained in Exhibits "A" "B" and "C" attached hereto, as such may be amended from time to time.
1.2 "Btu" (British Thermal Unit) means the amount of heat energy required to raise the temperature of one pound of Water from fifty-nine- degrees Fahrenheit (59 degrees F) to sixty degrees (60 degrees F), as determined on a dry basis.
1.3 "Columbia Gas" shall mean Columbia Gas Transmission Corporation.
1.4 "Columbia Gulf" shall mean Columbia Gulf Transmission Company.
1.5 "Day" shall mean that period of 24 consecutive hours beginning and ending at 8:00 a.m. Eastern Time.
1.6 "FERC" means the Federal Energy Regulatory Commission or any successor government authority.
1.7 "Gas" or "Natural Gas" means the effluent vapor stream (including Liquid Hydrocarbons) in its natural state produced from wells, including all hydrocarbon and nonhydrocarbon constituents and including casinghead gas produced with crude oil, and residue gas resulting from the processing of gas well gas or casinghead gas.
1.9 "Mcf" shall mean one thousand (1,000) cubic feet of Gas as determined on the measurement basis set forth in this Agreement.
1.10 "MMBtu" means one million (1,000,000) Btu. One MMBtu is equivalent to one Dth.
1.11 "Month" shall mean the period commencing at 8:00 a.m. Eastern Time on the first Day of a calendar month and ending at 8:00 a.m. Eastern Time on the first Day of the immediately following calendar month.
1.12 "Transporter" means Columbia Gulf and, where appropriate, Columbia Gas.
2.1 Subject to the other provisions of this Agreement, Seller shall sell and deliver and Buyer shall purchase and receive, on a firm basis, a maximum daily quantity of gas up to 12,070 MMBtu ("MDQ"). Buyer shall purchase, and Seller shall supply, one hundred percent of Buyer's gas requirements for system supply on Columbia Gas from Seller pursuant to this Agreement. Buyer shall be permitted to receive, and to transport through its facilities, Gas from other suppliers, solely to the extent that such Gas is received and transported by Buyer for industrial and commercial end-users behind Buyer's citygate.
Notwithstanding the foregoing, Buyer shall not utilize Gas purchased from Seller under this Agreement to supply new industrial load added after November 1, 1993. In the event Buyer adds a new industrial customer(s) after November 1, 1993, Buyer and Seller shall negotiate in good faith with respect to the price and terms at which Seller would provide Gas to supply such load. Buyer may also negotiate with other suppliers to supply such new load. If Buyer and Seller do not agree on the terms and price for supply to serve the new load, Buyer may make whatever arrangements it deems appropriate to provide supply to such new load.
2.2(a) No later than forty-eight hours prior to the earlier of the first-of-the-month nomination deadline for Transporter or such other pipeline designated by the parties, Buyer shall notify Seller of the quantity of Gas that Buyer desires to purchase from Seller on each Day of the coming Month (the "Daily Nominated Quantity").
2.2(b) On or before 4:00 pm Eastern Time on the day prior to Transporter's nomination deadline for the next day, Buyer may adjust its Daily Nominated Quantity prospectively for any day during the remainder of that month.
2.2(c) Buyer may nominate quantities in excess of the MDQ, and Seller shall exercise its best efforts to deliver the excess quantities, provided that the Parties agree, prior to delivery, on the price of the excess quantity and the terms and conditions of its delivery.
2.2(d) At the time of nomination pursuant to sections 2.2(a) and 2.2(b) of this Agreement, Buyer may direct Seller to cause Gas sold hereunder to be delivered under Columbia Gas' Rate Schedule ITS, in lieu of causing such Gas to be delivered under Columbia Gas' Rate Schedule GTS. Notwithstanding the foregoing, Seller shall have the authority to determine whether sufficient ITS capacity exists to permit delivery of Daily Nominated Quantities. In the event Seller reasonably determines that sufficient ITS capacity is not available to permit delivery of Nominated Quantities, Seller is authorized to cause Buyer's Gas to be delivered under Columbia Gas' Rate Schedule GTS.
2.2(e) Nominations required hereunder may be provided in writing (including by facsimile transmission) or orally. Oral nominations shall be confirmed in writing as soon as practicable.
2.3 The rules, guidelines, and policies of the Transporter(s) actually transporting Gas under this Agreement, as may be changed from time to time by agreement of the parties, shall define and set forth the manner in which the Gas purchased and sold is transported. Buyer and Seller recognize that the receipt and delivery on Transporter's pipeline facilities of gas purchased and sold under this Agreement shall be subject to the operational procedures of Transporter, as set forth in Transporter's then effective Federal Energy Regulatory Commission Gas Tariff. Buyer and Seller shall be obligated to use their best efforts to avoid imposition by Transporter of penalties, scheduling fees, cash-out costs or similar charges for imbalances or as a result of violations of Operational Flow Orders, as permitted by Transporter's tariff ("Imbalance Charges"). If during any month Buyer or Seller receives an invoice from Transporter that includes an Imbalance Charge, both parties shall be obligated to use their best efforts to determine the validity as well as the cause of such Imbalance Charge. If the parties determine that the Imbalance Charge was imposed as a result of Buyer's actions (which shall include, but shall not be limited to, Buyer's failure to accept a daily quantity of Gas equal to Buyer's nomination of its daily volume requirements), then Buyer shall pay for such Imbalance Charge. If the parties determine that the Imbalance Charge was imposed as a result of Seller's actions (which shall include, but not be limited to, Seller's failure to deliver a daily quantity of gas equal to Buyer's nomination
of its daily quantity requirements), then Seller shall pay such Imbalance Charge.
2.4(a) If Seller fails to sell and deliver the quantity of Gas
nominated by Buyer pursuant to this Agreement, and such failure is not
otherwise excused under this Agreement, then Buyer's sole remedy shall be to
obtain alternate supplies of Gas to cover the quantity of Gas not delivered
by Seller (such alternate supplies obtained by Buyer are referred to as
"Deficiency Gas") and collect from Seller an amount equal to any additional
costs Buyer incurs to obtain Deficiency Gas, including, without limitation,
(i) the difference, if positive, between the price Buyer pays for a
substitute supply and the commodity charge applicable under section 3.2
hereof; (ii) any reasonable incremental expenses incurred in purchasing such
substitute supplies; and (iii) penalties charged by any pipeline that would
have transported the Gas Seller fails to deliver. Buyer shall use its best
efforts to obtain Deficiency Gas at the lowest reasonable cost available.
All other remedies Buyer may have at law and equity arising from Seller's
unexcused failure to deliver Gas nominated by Buyer are waived.
2.4(b) Buyer's obtaining of Deficiency Gas and recovery of Buyer's costs from Seller, as specified in Paragraph 2.4(a), shall be limited to those quantities underdelivered and to the period of underdelivery. Buyer's recovery from Seller may be, at Buyer's choice, either a credit against future purchases or a cash payment in accordance with Article IV.
2.5 The delivery of Gas from Seller to Buyer shall be made at the Delivery Point(s) into Columbia Gulf designated in Exhibit A, as supplemented by mutual written agreement of the Parties from time to time. Title to Gas delivered under this Agreement shall pass to Buyer at the Delivery Point(s).
2.6 Contemporaneously with the execution of this Agreement, Buyer will delegate to Seller full responsibility for the administration, management and operation of Buyer's firm transportation service agreement with Columbia Gulf and Buyer's Rate Schedule GTS service agreement with Columbia Gas pursuant to an Agency and Delegation Agreement acceptable to Buyer, Seller, Columbia Gulf, and Columbia Gas. Seller shall assume full responsibility for the nomination, scheduling and balancing of Gas transported and stored under Buyer's transportation and GTS agreements with Columbia Gulf and Columbia Gas. Seller's responsibility under the Agency and Delegation Agreement shall commence upon delivery of Gas to the Delivery Point(s) on Columbia Gulf, apply to the injection and withdrawal of Gas from Columbia Gas' storage facilities, and continue until Gas is delivered to Buyer's citygate delivery points designated in Exhibit A. Seller will indemnify and hold Buyer harmless from all costs, expenses and liability, including any liability under the Minimum Fixed Cost Contribution set forth in Columbia Gas' Rate Schedule GTS, arising from: (i) Seller's failure to follow Buyer's instructions under the Agency and
Delegation Agreement; or (ii) Seller's unauthorized violation of any term or condition contained in Buyer's transportation or Rate Schedule GTS agreements with Columbia Gulf or Columbia Gas. Notwithstanding the foregoing sentence, Buyer will indemnify and hold Seller harmless from any costs, expenses and liability, including, without limitation, Imbalance Charges as defined in Section 2.3, and Minimum Fixed Cost Contribution under Columbia Gas' Rate Schedule GTS, resulting from any act or omission of Seller undertaken in accordance with Buyer's nominations, other instruction(s) or any other information supplied to Seller under this Agreement or the Agency and Delegation Agreement.
2.7 Subject to Seller's acceptance of Buyer's creditworthiness, which will not be unreasonably withheld, Seller shall finance the Storage Inventory Transfer from Columbia Gas to Buyer pursuant to Section 43 of the General Terms and Conditions of Columbia Gas' FERC Gas Tariff in accordance with the terms set forth in Exhibit C to this Agreement.
3.1 Buyer shall pay Seller each Month a commodity charge for each MMBtu nominated by Buyer and caused to be delivered by Seller at Buyer's citygate, calculated as follows:
3.2(a) For the period commencing November 1, 1993 and ending October 31, 1994, the monthly commodity charge for each MMBtu of Gas nominated by Buyer and delivered by Seller under this Agreement shall equal the sum of (A) the Index Price, as defined in section 1.8 hereof, and (B) $0.05 per MMBtu.
3.2(b) For the period November 1, 1994 through April 30, 1996, and for any extension of the Initial Term as defined in Article VII of this Agreement, the monthly commodity charge for each MMBTU of Gas nominated by Buyer and delivered by Seller under this Agreement shall equal the sum of (A) the Index Price, as defined in section 1.8 hereof, and (B) $0.01 per MMBtu.
3.3 Subject to Seller's obligation to indemnify and hold Buyer harmless under Section 2.6 of this Agreement, Buyer shall be responsible for and shall pay all charges, costs and expenses incurred in transportation and storage of the Gas from the Delivery Point(s) to Buyer's citygate receipt points, including any Minimum Fixed Cost Contribution liability under Columbia Gas' Rate Schedule GTS. Buyer shall receive bills directly from Columbia Gas and Columbia Gulf and shall pay such bills directly. Seller shall be responsible for any charges incurred in connection with its utilization of Buyer's Rate Schedule GTS rights on Columbia Gas for purposes other than providing Gas supply to Buyer, and for any commodity charges incurred in connection with
its use of Buyer's Rate Schedule FTS rights on Columbia Gulf for purposes other than providing Gas supply to Buyer. In the event Buyer identifies such charges from Columbia Gas and Columbia Gulf that do not relate to Seller providing Gas supply to Buyer, Buyer shall submit a statement to Seller for reimbursement, in accordance with the provisions of section 4.5 of this Agreement.
3.4 If any publication used to calculate the Index Price is no longer available, or is not available for a given month, or if the Parties shall agree that the published Index Price no longer reflects the spot market for Gas at the delivery location, the Parties will agree on a substitute publication or index. The substitute publication or index shall be recognized in the industry as a measure of prices paid each month for short term sales of Gas in the market region containing the Delivery Point(s). Until a substitute publication or index can be agreed on, the Index Price shall be computed on the remaining publication(s) or index.
3.5 In the event that Buyer is not permitted by the applicable state or local regulatory body having jurisdiction to recover from its customers any portion of the purchase price paid to Seller under this Agreement, Buyer shall promptly notify Seller of such disallowance. Within 15 days of such notice, the Parties shall meet and attempt, in good faith, to agree on a mutually acceptable course of action. If no resolution is reached within 30 days of Buyer's notice, Buyer shall have the right, in its sole discretion, to terminate the contract by notifying Seller in writing. Such termination shall take effect on the first day of the Month following Buyer's written notice of termination.
4.1 On or before the tenth (10th) Day of each Month, Seller shall render to Buyer a statement setting forth the charges for the total MMBtu of Gas nominated and delivered to Buyer at the Delivery Point(s) during the immediately preceding Month. Invoices shall be sent to Buyer at:
Attn.: Steve Billings
Delta Natural Gas Company, Inc.
3617 Lexington Road
Winchester, KY 40391
Phone: (606) 744-6171 ext. 158
Fax: (606) 744-3623
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Buyer shall pay the amounts invoiced on or before the twentieth (20th) day of the Month. If presentation of a statement by Seller is delayed after the tenth (10th) day of the Month, then the time for payment shall be extended a corresponding period of time, unless Buyer is responsible for such delay.
Payments shall be made to Seller by check or by wire transfer. Payment by check shall reach Seller by the 20th day of the Month. Payment by wire transfer shall be made direct to:
NationsBank-Dallas, Texas
ABA #111000025
Account #2261523836
Account Title: Natural Gas Clearinghouse
Payment by check shall be made to:
NationsBank
Credit Natural Gas Clearinghouse
P.O. Box 840795
Dallas, TX 75284-0795
4.2 If Buyer presents to Seller reasonable evidence supporting Buyer's good faith belief that the amount of the invoice is incorrect, Buyer shall pay the undisputed amount. If Seller can to Buyer's reasonable satisfaction, that Buyer's is incorrect, Buyer shall immediately pay any remaining amount owed. Late payments and all amounts withheld by Buyer and subsequently acknowledged or determined to be owing shall bear interest running from the original due date until paid at the lower of the Prime Rate of interest established by the Chase Manhattan Bank plus two percent (2%) or the maximum applicable non-usurious rate.
4.3 If either Party discovers an error in the amount billed any statement or payment rendered under this Agreement, such error shall be adjusted within thirty (30) days of the discovery of the error, together with interest at the rate provided for in Section 4.2. No adjustments claimed within twenty-four (24) months of the date of the original statement. A Party's rights under termination of this Agreement.
4.4 The Parties shall each preserve all test data, meter records, charts and other similar records within their custody or control pertaining to Gas sold and delivered under this Agreement for a period of at least three (3) years following their creation. Upon at least twenty-four (24) hours advance notice, each Party shall have the right during normal business hours to examine the books and records of the other Party to the extent necessary to verify the accuracy of any statement, charge, computation, or demand made under or pursuant to this Agreement. A Party's rights under this paragraph shall survive termination of this Agreement.
4.5. In the event Buyer elects to be reimbursed by cash payment for obtaining Deficiency Gas pursuant to section 2.4 of this Agreement, or seeks reimbursement in accordance with section 3.3 of this Agreement, Buyer shall render Seller a statement by the 10th day of the Month following the Month in which Buyer obtained the Deficiency Gas. Seller shall pay the amount invoiced by the 20th day of the Month. Payment shall be by wire transfer or check at Buyer's option. If presentation of a statement by Buyer is delayed beyond the 10th day of the Month, then the time for payment shall be extended a corresponding period of time, unless Seller is responsible for such delay. Any disputes regarding the amounts invoiced by Buyer shall be resolved pursuant to the procedures set forth in section 4.2 hereof. Billing errors shall be governed by section 4.3 hereof.
5.1 Prior to commencement of deliveries, or during the term of this Agreement if Buyer has failed to make timely payment of undisputed amounts on more than one occasion, Seller may require Buyer to supply Seller with credit information including, but not limited to, bank references, financial statements and names of persons with whom Seller may make reasonable inquiry into Buyer's creditworthiness and obtain adequate assurance of Buyer's solvency and ability to perform.
6.1 Except as provided in the Agency and Delegation Agreement described in Section 2.6 of this Agreement, all charges, expenses, fees, taxes, damages, injuries, and other costs incurred in or attributable to the handling or transportation of the Gas delivered in accordance with this Agreement prior to delivery to Buyer at the Delivery Point(s) shall be the responsibility of Seller, as between the Parties, and Seller shall indemnify, defend, and hold Buyer harmless from all such costs.
6.2 Except as provided in the Agency and Delegation Agreement described in Section 2.6 of this Agreement, all charges, expenses, fees, taxes (including sales, or transfer taxes and any other taxes levied on or in connection with the transactions under this Agreement by the state, or other government subdivision, in which the Gas is consumed or otherwise used), damages, injuries, and other costs incurred in or attributable to the purchase and transfer, transportation, and handling of the Gas from and after delivery to the Delivery Point(s) shall be the responsibility of Buyer, as between the Parties, and Buyer shall indemnify, defend, and hold harmless Seller from all such costs. In the event Seller is required by law to collect any such taxes, and Buyer claims an exemption from the taxes, Buyer shall, upon Seller's request, furnish Seller with a copy of Buyer's exemption certificate.
6.3 Except as provided in Article XIII herein, Buyer warrants that it has all necessary regulatory approvals and authorizations for the purchase of Gas by Buyer hereunder.
7.1 This Agreement shall become effective upon the date of execution by both Parties ("Effective Date") and shall continue for a term extending through April 30, 1996 ("Initial Term"). Following the Initial Term, this Agreement shall continue in effect on a year-to-year basis unless either Party gives written notice to the other of its intention not to extend the Agreement, provided, however, such written notice must be given at least six (6) months prior to the expiration of the Initial Term or any subsequent one year extension.
7.2 If, upon termination of this Agreement, either pursuant to this Article VII or to the election of Buyer under Section 3.5 hereof, there remains in Buyer's storage account under Rate Schedule GTS, Gas which Seller has caused to be injected but which has not been delivered to Buyer's citygate, Buyer shall pay Seller for such Gas a price per MMBtu equal to the greater of: (i) Seller's actual cost for the volumes of Gas that have not been delivered, plus 15 cents; or (ii) the Index Price for the Month in which the contract termination takes effect.
8.1 Buyer agrees to purchase nominated quantities of Gas delivered by Seller to the Delivery Point(s) meeting the quality and pressure specifications set forth in Transporter's Gas Tariff on file with the FERC. If Gas delivered by Seller to the Delivery Point(s) is rejected by Transporter for failure to meet its quality specifications, Buyer shall be relieved of the obligation to receive and pay for such Gas, including any applicable reservation charges. To the extent that Transporter accepts Gas tendered by Seller for Buyer's account at the Delivery Point(s), Seller shall be deemed to have complied with the quality specifications set forth herein.
8.2 Buyer and Seller agree that the volume and heating value of Gas sold and delivered hereunder will be measured at or near the Delivery Point(s) by Transporter, using equipment owned or controlled by, and measuring procedures employed by Transporter. The measurements made by Transporter shall be accepted by Buyer and Seller, provided, however, the measuring
equipment and procedures used conform to Transporter's filed tariffs and to generally recognized industry standards.
8.3 All Gas sold and delivered hereunder shall be measured as provided for in the General Terms and Conditions of Transporter's FERC Gas Tariff on file with the FERC.
9.1 Subject to the quality specifications of Article VIII, Seller
may process the Gas to remove any Liquid Hydrocarbons or Liquefiable
Hydrocarbons prior to and after the delivery of the Gas to Buyer at the
Delivery Point(s). In the event Seller elects to process the Gas, any
hydrocarbons so removed shall be Seller's sole responsibility and all costs
(including additional transportation costs attributable to such processing)
shall be paid by the Seller. The volumes delivered to Buyer shall be net of
any "plant volume reduction" as that phrase, or its equivalent, is defined
in pertinent gas processing agreements.
arrests, strikes, lockouts or other industrial disturbances, explosions, breakage, accidents to equipment, facilities or lines of pipe used to enable Seller to deliver or Buyer to receive Gas under this Agreement, the refusal or inability of Transporter to transport Gas under an existing transportation agreement, imposition by a regulatory agency, court or other governmental authority having jurisdiction of binding laws, conditions, limitations, orders, rules or regulations that prevent or prohibit either Party from performing, provided such governmental action has been resisted in good faith by all reasonable legal means, or any other cause of a similar type.
11.1 Any notice, request, demand or statement which either Party may desire to give to the other, shall be in writing and may be mailed by registered or certified mail, return receipt requested, to the post office address of the Parties shown below, or by facsimile transmission followed by written confirmation by regular mail, unless otherwise provided in this Agreement:
SELLER: Notices
-------
Natural Gas Clearinghouse
Attn: Vincent T. McConnell
13430 Northwest Freeway, #1200
Houston, Texas 77040
Phone (713) 744-1715
Telecopy (713) 744-6180
Billing Inquiries
-----------------
Natural Gas Clearinghouse
Attn: Vincent T. McConnell
13430 Northwest Freeway, #1200
Houston, Texas 77040
Phone (713) 744-1715
Telecopy (713) 744-6180
BUYER: Notices and Billing Inquiries
Attn.: -----------------------------
Brian Ramsey
Steve Billings
Delta Natural Gas Company, Inc.
3617 Lexington Road
Winchester, KY 40391
Phone: (606) 744-6171 ext. 158
Fax: (606) 744-3623
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Notice shall be deemed received five business days following mailing if by registered or certified mail or upon sender's receipt of transmission confirmation if by facsimile transmission.
11.2 Either of the Parties may from time to time designate a different address. Routine communications may be delivered by registered, certified or ordinary mail, or by telephone or telecopy if the Parties agree.
12.1 Seller warrants title to all Gas sold by it to Buyer and that such Gas is free from all liens and adverse claims. Seller agrees to indemnify Buyer from, and with respect to, all suits, actions, debts, accounts, damages, costs, losses and expenses (including only reasonable attorneys' fees) arising from or out of any adverse claims of any and all persons related to such Gas or taxes or charges thereon prior to the time the Gas is delivered at the Delivery Point(s). Buyer agrees to indemnify Seller from and with respect to, all suits, actions, debts, accounts, damages, costs, losses and expenses (including only reasonable attorneys' fees) arising from or out of any adverse claims of any and all persons related to such Gas or taxes or charges thereon at the time the Gas is delivered at the Delivery Point(s) or thereafter.
13.1 This Agreement shall be subject to all valid and applicable laws of the United States and to the applicable valid rules, regulations or orders of any regulatory agency or governmental authority having jurisdiction, and the Parties shall be entitled to regard all applicable laws, rules and regulations (federal, state or local) as valid and may act in accordance therewith until such time as the same may be declared invalid by final judgment of a court of competent jurisdiction and such judgment is not subject to appeal.
13.2 Upon execution of this Agreement, each of the Parties agrees to seek such government certificates, permits, licenses and authorizations which, in its sole discretion, it deems necessary to perform its obligations under this Agreement.
13.3 Upon execution of this Agreement, and from time to time through out its term, each of the Parties shall make all filings required by any regulatory bodies having jurisdiction over the activities covered by this Agreement and upon request of the other Party shall promptly provide copies of such to the other Party.
13.4 Neither Party will knowingly enter into agreements or undertake any activities or filings that would interfere with or frustrate the other Party's efforts to obtain the necessary regulatory approvals to fulfill its obligations under this Agreement.
14.1 Either Party may, without relieving itself of any obligations under this Agreement, assign any of its rights under this Agreement to any corporation, partnership, joint venture, or other entity with which it is affiliated. Either Party, may also assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture or similar instrument. But neither Party shall otherwise assign this Agreement or any of its rights, duties or obligations unless it shall have first obtained the consent in writing of the other Party, which consent shall not be unreasonably withheld. This Agreement shall be binding upon, and inure to the benefit of, the respective successors and assigns of the Parties.
15.1 The terms of this Agreement, including but not limited to, the price paid for Gas, the quantities of Gas purchased, and all other material terms of this Agreement shall be kept confidential by the Parties except to the extent that any information must be disclosed for the purpose of effectuating transportation of the Gas, obtaining regulatory approval(s), complying with a directive of any applicable regulatory body having jurisdiction, or as required by law.
16.1 No waiver by either Party of any one or more defaults by the other in the performance of any provisions of this Agreement shall operate or be constructed as a waiver of any other default or defaults, whether of a like or of a different character.
16.2 THIS AGREEMENT SHALL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS.
16.3 This Agreement constitutes the entire agreement between the Parties pertaining to the subject matter hereof, supersedes all prior agreements
and understandings, whether oral or written, which the Parties may have had in connection herewith and may not be modified except by written agreement executed by authorized representatives of the Parties.
16.4 Except as otherwise stated herein, any article or provision declared or rendered unlawful by a court of law or regulatory agency with jurisdiction over the Parties or deemed unlawful because of a statutory change shall not otherwise affect the lawful obligations that arise under this Agreement.
16.5 Neither Party shall be liable to the other for any consequential, incidental, punitive, or exemplary damages as a result of any act or omission under this Agreement or relating in any fashion to this Agreement.
17.1 All disputes arising under this Agreement shall be resolved through arbitration. All such arbitration shall be conducted pursuant to the procedures set forth in Exhibit B hereto.
IN WITNESS WHEREOF, the Parties have duly executed this Agreement as of the day and year written below.
SELLER: BUYER:
ACCEPTED and AGREED to this ACCEPTED and AGREED to this
28th day of October, 1993 21st day of October, 1993
NATURAL GAS CLEARINGHOUSE DELTA NATURAL GAS COMPANY,
INC.
By: /s/ [illegible signature] By: /s/ ALAN L. HEATH
--------------------------------- ----------------------------
Alan L. Heath
Title: SR. VICE PRESIDENT Title: Vice President
------------------------------ -------------------------
Operations & Engineering
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EXHIBIT B
ARBITRATION PROCEDURE
1. Arbitration under the Agreement shall be governed by the Federal Arbitration Act, 9 U.S.C. Section 1, et seq., and will not be governed by the arbitration acts, statutes or rules of any other jurisdiction.
2. Either party may request arbitration by submitting a written notice to the other. The notice shall name the noticing party's arbitrator and shall contain a statement of the issue presented for arbitration. Within fifteen (15) days of receipt of a notice of arbitration, the other party shall name its arbitrator by written notice and may designate any additional issues for arbitration. The two named arbitrators shall select the third arbitrator within fifteen (15) days after the date on which the second arbitrator was named. Should the two arbitrators fail to agree on the selection of the third arbitrator, either party shall be entitled to request the Senior Judge of the United States District Court of the District of Houston to select the third arbitrator. All arbitrators shall be qualified by education or experience within the natural gas industry to decide the issues presented for arbitration and shall be licensed attorneys. No arbitrator shall be: a current or former director, officer or employee of either party, or its affiliates; an attorney (or member of a law firm) who has rendered legal services to either party, or its affiliates, within the preceding three years; or an owner of any of the common stock of either party, its affiliates or direct competitors.
3. The three arbitrators shall commence the arbitration hearing within
twenty-five (25) days following the appointment of the third arbitrator. The
proceeding shall be held at a mutually acceptable site. If the parties are
unable to agree on a site, the arbitrators shall select a site other than
the State of Texas or the State of [Kentucky/Ohio]. Each party shall have an
opportunity to present its evidence at the hearing. The arbitrators may call
for the submission of pre-hearing statements of position and legal
authority, but no post-hearing briefs shall be submitted. After the
presentation of the evidence has concluded, each party shall submit to the
arbitration panel a final offer of its proposed resolution of the dispute. A
majority of the arbitrators shall approve the final offer of one party
without modification, and reject the offer of the other party. The
arbitration panel shall not have the authority to award punitive or
exemplary damages. The arbitrators' decision must be rendered within thirty
(30) days following the conclusion of the hearing or submission of evidence,
but no later than 90 days after appointment of the third arbitrator.
4. The decision of the arbitrators or a majority of them, shall be in writing and shall be final and binding upon the parties as to the issue submitted. Each
party shall bear the expense and cost of its arbitrator and one-half of the expense and cost of the third arbitrator.
5. The arbitrators shall have the authority to establish rules and procedures governing the arbitration hearing, except that there shall be no pre-hearing discovery unless the parties mutually agree that discovery will be permitted. Either party shall be entitled to insist that no discovery shall be had, or that discovery be limited to one or more of the devices authorized by the Federal Rules of Civil Procedure.
EXHIBIT C
STORAGE INVENTORY TRANSFER FINANCING
1. Seller shall pay Columbia Gas the amount billed to Buyer by Columbia Gas pursuant to Section 43 of the General Terms and Conditions of Columbia Gas' FERC Gas Tariff for the "Conversion Transfer" of storage inventory, as defined in that section.
2. Buyer shall reimburse Seller for the amount paid under paragraph 1, plus carrying charges calculated at 5% annual interest, over a 12 month period, commencing the first month after Seller makes the payment under paragraph 1.
3. Seller shall bill Buyer for amounts due under this Exhibit C in 12 equal monthly payments, beginning in the first month after the payment in paragraph 1 is made. Such amounts shall be separately stated on Seller's invoice. The provisions of Article IV of the Agreement shall govern billing and payment under this Exhibit C.
FIRST AMENDMENT TO GAS SALES AGREEMENT
This Amendment is executed as of this 14th day of March, 1997, but made effective May 1, 1997 except as indicated in Item 4 of this amendment, by and between Delta Natural Gas Company, Inc. ("Buyer") and Natural Gas Clearinghouse ("Seller").
WHEREAS, Seller and Buyer entered into a Gas Sales Agreement effective as of November 1, 1993, Natural Gas Clearinghouse Contract No. 93-11-532 (herein "Agreement");
WHEREAS, Seller and Buyer wish to amend the Agreement in certain particulars;
NOW THEREFORE, in consideration of the mutual covenants contained herein, Seller and Buyer agree as follows:
1. Article 1.5 of the Agreement is deleted in its entirety and replaced with the following:
"1.5 `Day' shall mean a period of 24 consecutive hours, coextensive with a `day' as defined by the Transporter in a particular transaction."
2. Article 1.11 of the Agreement is deleted in its entirety and replaced with the following:
"1.11 `Month' shall mean the period beginning on the first Day of the calendar month and ending immediately prior to the commencement of the first Day of the next calendar month."
3. Article 1.8 of the Agreement shall be deleted in its entirety and replaced with the following:
1.8 "Index Price" shall mean the price as published in the first issue each month of Inside FERC's Gas Market Report in the table titled "Prices of Spot Gas Delivered to Pipelines" under the heading "Columbia Gulf/onshore", plus the applicable transportation from onshore to Rayne, Louisiana, plus $0.01 per MMBtu. In the event Seller arranges transportation on Columbia Gas to facilitate deliveries to Buyer, applicable transportation charges on Columbia Gas will be added to the price in addition to any charges incurred on Columbia Gulf as stated above.
4. The first sentence of Article 2.1 shall be deleted and replaced with the following: "Subject to the other provisions of this Agreement, Seller shall sell and deliver and Buyer shall purchase and receive, on a firm basis, a maximum daily quantity of gas up to 12,380 MMBtu ("MDQ")."
5. Article 2.2(d) of the Agreement shall be deleted and replaced with the following:
2.2(d) Buyer and Seller agree that Seller shall cause Gas to be sold and delivered to Buyer under Columbia Gas' Rate Schedule GTS up to the respective Minimum Fixed Cost Contribution (MFCC) threshold level(s) under Buyer's GTS agreements with Columbia Gas. After satisfying Buyer's MFCC requirements under Columbia Gs' Rate Schedule GTS, Seller shall endeavor to acquire released firm or interruptible transportation capacity or other transportation service less costly than GTS on the Columbia Gas system on Buyer's behalf and as Buyer's agent in accordance with the terms and conditions of the Limited Agency Agreement dated November 1, 1993.
6. Article 3.3 of the Agreement shall be deleted and replaced with the following:
3.3 Subject to Seller's obligation to indemnify and hold Buyer harmless under Section 2.6 of this Agreement, Buyer shall be responsible for and shall pay all charges, costs and expenses incurred in transportation and storage of the Gas from the Delivery Point(s) to Buyer's citygate receipt points, including any Minimum Fixed Cost Contribution liability under Columbia Gas' Rate Schedule GTS. Buyer shall receive bills directly from the Transporter(s) and shall pay such bills directly. Seller shall be responsible for any charges incurred in connection with its utilization of Buyer's Rate Schedule GTS rights on Columbia Gas for purposes other than providing Gas Supply to Buyer. In the event Buyer identifies such charges from Columbia Gas and Columbia Gulf that do not relate to Seller providing Gas supply to Buyer, Buyer shall submit a statement to Seller for reimbursement, in accordance with the provisions of section 4.5 of this Agreement. Effective June 1, 1996, if Seller utilizes Buyer's Rate Schedule FTS rights on Columbia Gulf for purposes other than providing Gas supply to Buyer, Seller shall pay to Buyer (1) an amount equal to the posted transportation rate or (2) in lieu of paying the posted rate, Buyer and Seller may agree on a monthly basis prior to the beginning of the month to share (eighty percent (80%) to Buyer and twenty percent (20%) to Seller) in any savings obtained by Seller reselling any released capacity and associated gas. This savings will be calculated by taking the market price of the repackaged gas as compared to the delivered price to Buyer
of the gas Seller would have otherwise delivered pursuant to the terms and conditions of this Agreement less transportation commodity charges and related costs.
7. In Article 4.1 of the Agreement, Seller's payment addresses shall be deleted and replaced with the following:
Payment by wire transfer: Payment by check: ------------------------ ---------------- First National Bank of Chicago Natural Gas Clearinghouse Chicago, IL P.O. Box 730508 Account Title: Natural Gas Clearinghouse Dallas, TX 75373-0508 Account Number: 55-53911 ABA Number: 071000013 |
8. Article 7.1 of the Agreement shall be deleted and replaced with the following:
7.1 This Agreement shall become effective as of November 1, 1993 ("Effective Date") and shall continue in full force and effect, unless terminated earlier under the provisions hereof, until April 30, 2000 ("Initial Term"). Following the Initial Term, this Agreement shall continue in effect on an annual basis unless either party provides written notice to the other of its intention not to extend the Agreement, provided, however, such written notice must be given at least six (6) months prior to the expiration of the Initial Term or any subsequent one year extension.
9. Article 11.1 of the Agreement shall be revised by substituting the following Notice address for Seller:
10. Exhibit A to the Agreement shall be amended by adding the following:
GTS Service Agreement No. 37948 Columbia Gulf Service Agreement No. 44375 Quantity: 310 Dth/Day
11. All other provisions of the Agreement shall remain in full force and effect.
IN WITNESS WHEREOF, Seller and Buyer execute this agreement effective on the date first written above.
"SELLER" "BUYER"
NATURAL GAS CLEARINGHOUSE, DELTA NATURAL GAS COMPANY, INC.
a Colorado general partnership
BY: /s/ [illegible signature] BY: /s/ GEORGE S. BILLINGS
--------------------------------- -----------------------
TITLE: Vice President TITLE: MGR. - GAS SUPPLY
----------------------------- -----------------
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SECOND AMENDMENT TO GAS SALES AGREEMENT AND FIRST
AMENDMENT TO LIMITED AGENCY AGREEMENT
This Amendment is made and entered into as of the 1st day June, 2002 by and between DYNEGY MARKETING AND TRADE ("Seller") and DELTA NATURAL GAS COMPANY ("Buyer").
WHEREAS, Seller, as successor to Natural Gas Clearinghouse, and Buyer are parties to a Gas Sales Agreement dated November 1, 1993, as amended (Seller's Contract No. 6) ("Sales Agreement") and a related Limited Agency Agreement dated November 1, 1993 ("Limited Agency Agreement"); and
WHEREAS, Seller and Buyer desire to amend the Sales Agreement and the Limited Agency Agreement to provide for the addition of gas delivered at the Mt. Olivet Delivery Point.
NOW, THEREFORE, in consideration of the mutual covenants contained herein, the parties hereto agree as follows:
I.
The first sentence of Article 2.1 of the Sales Agreement is deleted and replaced with the following: "Subject to the other provisions of this Agreement, Seller shall sell and deliver and Buyer shall purchase and receive, on a firm basis, a maximum daily quantity of gas up to 12,880 MMBtu ("MDQ").
II.
Exhibit A to the Sales Agreement is deleted and the Exhibit A attached hereto is substituted therefor.
The third "WHEREAS" clause of the Limited Agency Agreement is changed and amended to read in its entirety as follows:
"WHEREAS, Buyer has arranged for firm transportation of the supply of Gas it will purchase from Seller under the Gas Contract on Columbia Gulf Transmission Company pursuant to the terms of Service Agreements 43827, 43828, 43829, 44375, and 43332 ("Assignment Agreements") and transportation and storage of such Gas pursuant to the terms of Rate Schedule GTS Service Agreements ("GTS Agreements") Nos. 37813, 37814, 37815, 37948, 37954, and with Columbia Gas Transmission Corporation (the Columbia companies being referred (to herein collectively as "Columbia"); and"
IV.
This Amendment shall be effective as of June 1, 2002.
IN WITNESS WHEREOF, Seller and Buyer have executed this Agreement as of the date first hereinabove written.
DYNEGY MARKETNG AND TRADE DELTA NATURAL GAS COMPANY
By: /s/ LANCE C. JORDAN By: /s/ GEORGE S. BILLINGS
--------------------------- -----------------------------
Name: Lance C. Jordan Name: George S. Billings
------------------- ------------------
Title: Vice President Title: MGR - GAS SUPPLY
------------------- ----------------
Energy Trading
--------------
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EXHIBIT A
Attached to and made a part of Gas Sales Agreement dated November 1, 1993 between Dynegy Marketing and Trade, as Seller, and Delta Natural Gas Company, as Buyer.
Columbia Gas Transmission Columbia Gulf Transmission MDQ
Delivery Point Co. GTS Service Agreement No. Co. Service Agreement No. MMBtu
-------------- ----------------------------- -------------------------- -----
Cumberland 37813 43828 5,400
Stanton 37814 43827 2,530
Winchester 37815 43829 4,140
N. Middletown 37948 44375 310
Mt. Olivet 37954 43322 500
------
Total MDQ: 12,880
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Exhibit 10(e)
Service Package 9069
Amendment No. 0
GAS TRANSPORTATION AGREEMENT
(For Use Under FT-G Rate Schedule)
THIS AGREEMENT is made and entered into as of the 19th day of December, 1994 by and between TENNESSEE GAS PIPELINE COMPANY, a Delaware Corporation, hereinafter referred to as "Transporter" and DELTA NATURAL GAS COMPANY INC, a KENTUCKY Corporation, hereinafter referred to as "Shipper." Transporter and Shipper shall collectively be referred to herein as the "Parties."
ARTICLE I
DEFINITIONS
1.1 TRANSPORTATION QUANTITY (TQ) - shall mean the maximum daily quantity (MDQ) of gas which Transporter agrees to receive and transport on a firm basis, subject to Article II herein, for the account of Shipper hereunder on each day during each month of each year during the term hereof. Shipper shall elect a Transportation Quantity (TQ) for each month of the year and specify the delivery point meters to which service under this Rate Schedule applies. Any limitations of the quantities to be delivered to each Point of Delivery shall be as specified on Exhibit A attached hereto.
1.2 EQUIVALENT QUANTITY - shall be as defined in Article I of the General Terms and Conditions of Transporter's FERC Gas Tariff.
ARTICLE II
TRANSPORTATION
Transportation Service - Transporter agrees to accept and receive daily on a firm basis in accordance with Rate Schedule FT-G, at the Point(s) of Receipt from Shipper or for Shipper's account such quantity of gas as Shipper makes available up to the Transportation Quantity, and to deliver to or for the account of Shipper to the Point(s) of Delivery an Equivalent Quantity of gas.
ARTICLE III
POINT(S) OF RECEIPT AND DELIVERY
The Primary Receipt and Delivery Points shall be those points specified on Exhibit "A" attached hereto.
ARTICLE IV
All facilities are in place to render the service provided for in this Agreement.
ARTICLE V
QUALITY SPECIFICATIONS AND STANDARDS FOR MEASUREMENT
For all gas received, transported and delivered hereunder the Parties agree
to the Quality Specifications and Standards for Measurement as specified in
the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No.
l. To the extent that no new measurement facilities are installed to provide
service hereunder, measurement operations will continue in the manner in
which they have previously been handled. In the event that such facilities
are not operated by Transporter or a downstream pipeline, then
responsibility for operations shall be deemed to be Shipper's.
ARTICLE VI
RATES AND CHARGES FOR GAS TRANSPORTATION
6.1 TRANSPORTATION RATES - Commencing upon the effective date hereof, the rates, charges and surcharges to be paid by Shipper to Transporter for the transportation service provided herein, including compensation for system fuel and losses, shall be in accordance with Transporter's Rate Schedule FT-G and the General Terms and Conditions of Transporter's FERC Gas Tariff.
6.2 INCIDENTAL CHARGES - Shipper agrees to reimburse Transporter for any filing or similar fees, which have not been previously paid by Shipper, which Transporter incurs in rendering service hereunder.
6.3 CHANGES IN RATES AND CHARGES - Shipper agrees that Transporter shall have the unilateral right to file with the appropriate regulatory authority and make effective changes in (a) the rates and charges applicable to service pursuant to Transporter's Rate Schedule FT-G (b) the rate schedule(s) pursuant to which service hereunder is rendered, or (c) any provision of the General Terms and Conditions applicable to those rate schedules. Transporter agrees that Shipper may protest or contest the aforementioned filings, or may seek authorization from duly constituted regulatory authorities for such adjustment of Transporter's existing FERC Gas Tariff as may be found necessary to assure Transporter just and reasonable rates.
ARTICLE VII
BILLINGS AND PAYMENTS
Transporter shall bill and Shipper shall pay all rates and charges in accordance with Articles V and VI, respectively, of the General Terms and Conditions of Transporter's FERC Gas Tariff.
ARTICLE VIII
GENERAL TERMS AND CONDITIONS
This Agreement shall be subject to the effective provisions of Transporter's Rate Schedule FT-G and to the General Terms and Conditions incorporated therein, as the same may be changed or superseded from time to time in accordance with the rules and regulations of the FERC.
ARTICLE IX
REGULATION
9.1 This Agreement shall be subject to all applicable and lawful governmental statutes, orders, rules and regulations and is contingent upon the receipt and continuation of all necessary regulatory approvals or authorizations upon terms acceptable to Transporter. This Agreement shall be void and of no force and effect if any necessary regulatory approval is not so obtained or continued. All Parties hereto shall cooperate to obtain or continue all necessary approvals or authorizations, but no Party shall be liable to any other Party for failure to obtain or continue such approvals or authorizations.
9.2 The transportation service described herein shall be provided subject to Subpart B, Part 284 of the FERC Regulations.
ARTICLE X
RESPONSIBILITY DURING TRANSPORTATION
Except as herein specified, the responsibility for gas during transportation shall be as stated in the General Terms and Conditions of Transporter's FERC Gas Tariff Volume No. l.
ARTICLE XI
WARRANTIES
11.1 In addition to the warranties set forth in Article IX of the
General Terms and Conditions of Transporter's FERC Gas Tariff,
Shipper warrants the following:
(a) Shipper warrants that all upstream and downstream transportation
arrangements are in place, or will be in place as of the requested
effective date of service, and that it has advised the upstream and
downstream transporters of the receipt and delivery points under
this Agreement and any quantity limitations for each point as
specified on Exhibit "A" attached hereto. Shipper agrees to
indemnify and hold Transporter harmless for refusal to transport
gas hereunder in the event any upstream or downstream transporter
fails to receive or deliver gas as contemplated by this Agreement.
(b) Shipper agrees to indemnify and hold Transporter harmless from
all suits, actions, debts, accounts, damages, costs, losses and
expenses (including reasonable attorneys fees) arising from or out
of breach of any warranty by Shipper herein.
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11.2 Transporter shall not be obligated to provide or continue service
hereunder in the event of any breach of warranty.
ARTICLE XII
TERM
12.1 This Agreement shall be effective as of the 19th day of December,
1994, and shall remain in force and effect until 31st day of
December, 1995 ("Primary Term") and on a month to month basis
thereafter unless terminated by either Party upon at least thirty
(30) days prior written notice to the other Party provided,
however, that if the Primary Term is one year or more, then unless
Shipper elects upon one year's prior written notice to Transporter
to request a lesser extension term, the Agreement shall
automatically extend upon the expiration of the Primary Term for a
term of five years; and shall automatically extend for successive
five year terms thereafter unless Shipper provides notice as
described above in advance of the expiration of a succeeding term;
provided further, if the FERC or other governmental body having
jurisdiction over the service rendered pursuant to this Agreement
authorizes abandonment of such service, this Agreement shall
terminate on the abandonment date permitted by the FERC or such
other governmental body.
12.2 Any portions of this Agreement necessary to correct or cash-out
imbalances under this Agreement as required by the General Terms
and Conditions of Transporter's FERC Gas Tariff Volume No. 1 shall
survive the other parts of this Agreement until such tune as such
balancing has been accomplished; provided, however, that
Transporter notifies Shipper of such imbalance no later than twelve
months after the termination of this Agreement.
12.3 This Agreement will terminate automatically upon written notice
from Transporter in the event Shipper fails to pay all of the
amount of any bill for service rendered by Transporter hereunder in
accord with the terms and conditions of Article VI of the General
Terms and Conditions of Transporter's FERC Tariff.
ARTICLE XIII
NOTICE
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Except as otherwise provided in the applicable to this Agreement, any notice
in writing and mailed to the post office to receive the same, as follows:
General Terms and Conditions under this Agreement shall be address of the
Party intended as follows:
TRANSPORTER: TENNESSEE GAS PIPELINE COMPANY
P. O. Box 2511
Houston, Texas 77252-2511
Attention: Transportation Marketing
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SHIPPER:
NOTICES: DELTA NATURAL GAS COMPANY INC
3617 LEXINGTON ROAD
WINCHESTER, KY 40391-9797
Attention: GEORGE S. BILLINGS
BILLING: DELTA NATURAL GAS COMPANY INC
3617 LEXINGTON ROAD
WINCHESTER, KY 40391-9797
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Attention: BRIAN S. RAMSEY
or to such other address as either Party shall designate by formal written notice to the other.
ARTICLE XIV
ASSIGNMENTS
14.1 Either Party may assign or pledge this Agreement and all rights and
obligations hereunder under the provisions of any mortgage, deed of
trust, indenture, or other instrument which it has executed or may
execute hereafter as security for indebtedness. Otherwise, Shipper
shall not assign this Agreement or any of its rights hereunder,
except in accord with Article III, Section 11 of the General Terms
and Conditions.
14.2 Any person which shall succeed by purchase, merger, or
consolidation to the properties, substantially as an entirety, of
either Party hereto shall be entitled to the rights and shall be
subject to the obligations of its predecessor in interest under
this Agreement.
ARTICLE XV
MISCELLANEOUS
15.1 The interpretation and performance of this Agreement shall be in
accordance with and controlled by the laws of the State of Texas,
without regard to the doctrines governing choice of law.
15.2 If any provisions of this Agreement is declared null and void, or
voidable, by a court of competent jurisdiction, then that provision
will be considered severable at either Party's option; and if the
severability option is exercised, the remaining provisions of the
Agreement shall remain in full force and effect.
15.3 Unless otherwise expressly provided in this Agreement or
Transporter's Gas Tariff, no modification of or supplement to the
terms and provisions stated in this Agreement shall be or become
effective, until Shipper has submitted a request for
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change through the TENN-SPEED 2 System and Shipper has been
notified through TENN-SPEED 2 of Transporter's agreement to such
change.
15.4 Exhibit "A" attached hereto is incorporated herein by reference and
made a part hereof for all purposes.
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IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed in several counterparts as of the date first hereinabove written.
TENNESSEE GAS PIPELINE COMPANY
BY: /S/ JAMES L. BUJNOCH
----------------------
Director, Transportation Services
Central Region
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DELTA NATURAL GAS COMPANY INC.
BY: /s/ GEORGE S. BILLINGS
-----------------------
TITLE: MGR. - GAS SUPPLY
-----------------
DATE: 2-20-95
-------
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GAS TRANSPORTATION AGREEMENT
(For Use Under FTG Rate Schedule)
EXHIBIT "A"
AMENDMENT #0 TO GAS TRANSPORTATION AGREEMENT
DATED DECEMBER 19, 1994
BETWEEN
TENNESSEE GAS PIPELINE COMPANY AND DELTA NATURAL GAS COMPANY INC.
MONTHLY MDQS: (01) January 250 (04) April 75 (07) July 50 (10) October 100
(02) February 250 (05) May 50 (08) August 50 (11) November 175
(03) March 150 (06) June 50 (09) September 100 (12) December 250
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TO BILLABLE-TO MONTH
----------------------------------------------------------------------------------------------------------------------------------
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 250 250 01
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 250 250 02
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 150 150 03
20744 STA 542 POOLING POINT NOXUBEE MS O1 R 500 75 75 04
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 50 50 O5
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 50 50 06
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 50 50 07
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 50 50 O8
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 100 100 09
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 100 100 10
20744 STA 542 POOLING POINT NOXUBEE MS 01 R 500 175 175 11
20744 STA 542 POOLING POINT NOXUBEE MS O1 R 500 250 250 12
Total Receipt To: 1,550 1,550
0813 WEST BEND SALES POWELL KY 02 D 087 250 250 O1
0813 WEST BEND SALES POWELL KY 02 D 087 250 250 02
0813 WEST BEND SALES POWELL KY 02 D 087 150 150 03
0813 WEST BEND SALES POWELL KY 02 D 087 75 75 04
0813 WEST BEND SALES POWELL KY 02 D 087 50 50 05
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GAS TRANSPORTATION AGREEMENT
(For Use Under FTG Rate Schedule)
(EXHIBIT "A" Cont.)
METER METER NAME INTERCONNECT PARTY NAME COUNTY ST ZONE R/D LEG METER-TO BILLABLE-TO MONTH
----------------------------------------------------------------------------------------------------------------------------------
0813 WEST BEND SALES POWELL KY 02 D 087 50 50 06
0813 WEST BEND SALES POWELL KY 02 0 087 5O 50 07
0813 WEST BEND SALES POWELL KY 02 D 087 50 50 O8
0813 WEST BEND SALES POWELL KY 02 D 087 100 100 09
0813 WEST BEND SALES POWELL KY 02 D 087 100 100 10
0813 WEST BEND SALES POWELL KY 02 D 087 175 175 11
0813 WEST BEND SALES POWELL KY 02 D 087 250 250 12
Total Delivery To: 1,550 1,550
NUMBER OF RECEIPT POINTS AFFECTED: 1
NUMBER OF DELIVERY POINTS AFFECTED: 1
Note: Exhibit "A" is a reflection of the contract and all amendments as of the amendment effective date.
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SCHEDULE OF OTHER GAS TRANSPORTATION AGREEMENTS
This is a schedule of other Gas Transportation Agreements substantially identical to this exhibit in all material respects. The other Gas Transportation Agreements to which the Registrant is a party are set forth below with the material details that differ from this Exhibit:
1. Gas Transportation Agreement (contract No. 2448), dated September 1, 1993, by and between Tennessee Gas Pipeline Company and the Registrant. Materially different details: Maximum Daily Quantities for any given month are up to 1,500 Dekatherms for months of January, February and December; Initial Term expired November 1, 2000, but has same five year renewal periods as in exhibit.
2. Gas Transportation Agreement (contract No. 2515), dated September 1, 1993, by and between Tennessee Gas Pipeline Company and the Registrant. Materially different details: Maximum Daily Quantities for any given month are up to 5,500 Dekatherms for months of January, February and December; Initial Term expired November 1, 2000, but has same five year renewal periods as in exhibit.
3. Gas Transportation Agreement (contract No. 2555), dated September 1, 1993, by and between Tennessee Gas Pipeline Company and the Registrant. Materially different details: Maximum Daily Quantities for any given month are up to 8,561 Dekatherms for months of January, February and December; Initial Term expired November 1, 2000, but has same five year renewal periods as in exhibit.
4. Gas Transportation Agreement (Contract No. 2516), dated September 1, 1993, by and between Tennessee Gas Pipeline Company and the Registrant. Materially different details: Maximum Daily Quantities for any given month are up to 400 Dekatherms for months of January, February and December; Initial Term expired November 1, 2000, but has same five year renewal periods as in exhibit.
5. Gas Transportation Agreement (Contract No. 2747), dated September 1, 1993, by and between Tennessee Gas Pipeline Company and the Registrant. Materially different details: Rates, charges and surcharges to be paid by Registrant governed by Tennessee's Rate Schedule FT-A and not FT-G; Maximum Daily Quantities are 1,400 Dekatherms regardless of month, for months of January, February and December; Initial Term expired November 1, 2000, but has same five year renewal periods as in exhibit.
Exhibit 10(f)
Service Agreement No. 37815
Control No. 930905-013
GTS SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 1st day of November, 1993, by and between COLUMBIA GAS TRANSMISSION CORPORATION ("Seller") and DELTA NATURAL GAS CO., INC. - WINCHESTER ("Buyer").
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
Service Agreement No. 37815 Control No. 930905-013
GTS SERVICE AGREEMENT (Cont'd)
SGS Service Agreement No. 31086, effective February 4, 1985, as it may have been amended, providing for a bundled sales, transportation and storage service under the SGS Rate Schedule.
The terms of Service Agreement No. 37815 shall become effective as of the effective date hereof, however, the parties agree that neither the execution nor the performance of Service Agreement 37815 shall prejudice any recoupment or other rights that Buyer may have under or with respect to the above-referenced Service Agreements.
DELTA NATURAL GAS CO., INC./WINCHESTER COLUMBIA GAS TRANSMISSION CORPORATION
By: /s/ ALAN L. HEATH By: /s/ [illegible signature]
----------------- -------------------------
Title: V.P. OPNS. & ENG. Title: Vice President
----------------- --------------
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Appendix A to Service Agreement No. 37815 Under Rate Schedule GTS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (Buyer) DELTA NATURAL GAS CO INC
Transportation Demand 4,140 Dth/day Storage Contract Quantity 136,207 Dth Annual GTS Quantity 75,288 Dth/Year |
Scheduling Scheduling Measuring Measuring Maximum Daily
Point No. Point Name Point No. Point Name Quantity (Dth/Day)
------------------
8 0 1 T C 0 - L E A C H 8 0 1 1,380
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Appendix A to Service Agreement No. 37815 Under Rate Schedule GTS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION
and (Buyer) DELTA NATURAL GAS CO INC
Primary Delivery Points
-----------------------
Maximum Daily
Delivery Maximum Delivery
Scheduling Measuring Measuring Obligation Pressure
Scheduling Point Point Name Point No. Point Name (Dth/Day) Obligation (PSIG)
---------------------------------------------------------------------------------------------------------------------------
38 DELTA NATRL WINCHST 800809 KINGSTON TERRELL 2,270 200
---------------------------------------------------------------------------------------------------------------------------
803544 DELTA FRENCHBURG 280 150
---------------------------------------------------------------------------------------------------------------------------
803545 DELTA OWINSGSVILLE 1,030 400
---------------------------------------------------------------------------------------------------------------------------
803563 DELTA CARMARGO 340 150
---------------------------------------------------------------------------------------------------------------------------
803564 DELTA SHARPSBURG 220 100
---------------------------------------------------------------------------------------------------------------------------
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Appendix A to Service Agreement No. 37815 Under Rate Schedule GTS
Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION and (Buyer) DELTA NATURAL GAS CO INC
S1 / IF A MAXIMUM PRESSURE IS NOT SPECIFICALLY STATED, THEN SELLER'S
OBLIGATION SHALL BE AS STATED IN SECTION 13 (DELIVERY PRESSURE)
OF THE GENERAL TERMS AND CONDITIONS.
GFNT / UNLESS STATION SPECIFIC MODOS ARE SPECIFIED IN A SEPARATE
FIRM SERVICE AGREEMENT BETWEEN SELLER AND BUYER, SELLER'S
AGGREGATE MAXIMUM DAILY DELIVERY OBLIGATION, UNDER THIS AND ANY
OTHER SERVICE AGREEMENT BETWEEN SELLER AND BUYER, AT THE
STATIONS LISTED ABOVE SHALL NOT EXCEED THE MDD0 QUANTITIES SET
FORTH ABOVE FOR EACH STATION. ANY STATION SPECIFIC MDDOS IN A
SEPARATE FIRM SERVICE AGREEMENT BETWEEN SELLER AND BUYER SHALL
BE ADDITIVE TO THE INDIVIDUAL STATION MDDOS SET FORTH ABOVE.
DELTA NATURAL GAS CO INC.
Appendix A to Service Agreement No. 37815 Under Rate Schedule GTS
By /s/ ALAN L. HEATH Between (Seller) COLUMBIA GAS TRANSMISSION CORPORATION Its V.P. OPNS. & ENG. and (Buyer) DELTA NATURAL GAS CO INC Date April 11, 1994 |
COLUMBIA GAS TRANSMISSION CORPORATION
By /s/ [illegible signature] The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions of Seller's Tariff is incorporated herein by reference for the purposes of listing valid secondary interruptible receipt points. |
Its Vice President
Date 4-72-94
Service changes pursuant to this Appendix A shall become effective as of NOVEMBER 01, 1993. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A, to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
SCHEDULE OF OTHER GTS SERVICE AGREEMENTS
This is a schedule of other GTS Service Agreements substantially identical to this exhibit in all material respects. The other GTS Service Agreements to which the Registrant is a party are set forth below with the material details that differ from this Exhibit:
1. GTS Service Agreement No. 37813, dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Delta Natural Gas. Co., Inc. - Cumberland. Materially different details: Transportation Demand - 5,400 Dekatherms/day; Storage Contract Quantity - 177,662 Dekatherms; Annual GTS Quantity - 98,200 Dekatherms/year; Maximum Daily Quantity - 1,800 Dekatherms/day; Maximum Daily Delivery Obligation - 5,400 Dekatherms/day.
2. GTS Service Agreement No. 37814, dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Delta Natural Gas. Co., Inc. - Stanton. Materially different details: Transportation Demand - 2,530 Dekatherms/day; Storage Contract Quantity - 83,254 Dekatherms; Annual GTS Quantity - 48,009 Dekatherms/year; Maximum Daily Quantity - 843 Dekatherms/day; Maximum Daily Delivery Obligation - 2,530 Dekatherms/day.
3. GTS Service Agreement No. 37954, dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Delta Natural Gas Co., Inc. (as successor by assignment to Mt. Olivet Natural Gas Co.). Materially different details: Initial term expired November 1, 1993 and agreement currently continues on a year-to-year basis unless terminated by a party upon six months' written notice prior to end of yearly renewal term; Transportation Demand - 500 Dekatherms/day; Storage Contract Quantity - 18,434 Dekatherms; Annual GTS Quantity - 20,127 Dekatherms/year; Maximum Daily Quantity - 187 Dekatherms/day; Maximum Daily Delivery Obligation -500 Dekatherms/day.
4. GTS Service Agreement No. 37954, dated November 1, 1993, by and between Columbia Gas Transmission Corporation and Delta Natural Gas Co., Inc. (as successor by assignment to City of North Middletown). Materially different details: Initial term expired November 1, 1993 and agreement currently continues on a year-to-year basis unless terminated by a party upon six months' written notice prior to end of yearly renewal term; Transportation Demand - 310 Dekatherms/day; Storage Contract Quantity - 10,218 Dekatherms; Annual GTS Quantity - 12,000 Dekatherms/year; Maximum Daily Quantity - 103 Dekatherms/day; Maximum Daily Delivery Obligation -310 Dekatherms/day.
Exhibit 10(g)
SERVICE AGREEMENT NO. 43828
CONTROL NO. 1994-07-02 - 0041
FTS 1 SERVICE AGREEMENT
THIS AGREEMENT, made and entered into this 4th day of October, 1994 by and between:
COLUMBIA GULF TRANSMISSION COMPANY
("TRANSPORTER")
AND
DELTA NATURAL GAS CO INC
("SHIPPER")
WITNESSETH: That in consideration of the mutual covenants herein contained, the parties hereto agree as follows:
until changed by either party by written notice.
DELTA NATURAL GAS CO INC
By: /s/ ALAN L. HEATH
-----------------
Name: Alan L. Heath
-------------
Title: Vice President - Oper. & Eng.
-----------------------------
Date: September 30, 1994
------------------
|
COLUMBIA GULF TRANSMISSION COMPANY
By: /s/ S. M. WARNICK
-----------------
Name: S. M. Warnick
-------------
Title: Vice President
--------------
Date: 10-11-94
--------
|
Appendix A to Service Agreement No. 43828
Under Rate Schedule FTS1
Between (Transporter) COLUMBIA GULF TRANSMISSION COMPANY
and (Shipper) DELTA NATURAL GAS CO INC
Transportation Demand 1,836 Dth/day
Primary Receipt Points
----------------------
Measuring Measuring Maximum Daily
Point No. Point Name Quantity (Dth/Day)
----------------------------------------------------------------------------
2700010 CGT-RAYNE 1,836
|
Appendix A to Service Agreement No. 43828
Under Rate Schedule FTS1
Between (Transporter) COLUMBIA GULF TRANSMISSION COMPANY
and (Shipper) DELTA NATURAL GAS CO INC
The Master List of Interconnects (MLI) as defined in Section 1 of the General Terms and Conditions is incorporated herein by reference for purposes of listing valid secondary interruptible receipt points and delivery points.
Service changes pursuant to this Appendix A shall become effective as of NOVEMBER 01, 1994. This Appendix A shall cancel and supersede the previous Appendix A effective as of N/A , to the Service Agreement referenced above. With the exception of this Appendix A, all other terms and conditions of said Service Agreement shall remain in full force and effect.
DELTA NATURAL GAS CO INC
By: /s/ ALAN L. HEATH
-----------------
Name: Alan L. Heath
-------------
Title: Vice President - Oper. & Eng.
-----------------------------
Date: September 30, 1994
------------------
|
COLUMBIA GULF TRANSMISSION COMPANY
By: /s/ S. M. WARNICK
-----------------
Name: S. M. Warnick
-------------
Title: Vice President
--------------
Date: 10-11-94
--------
|
SCHEDULE OF OTHER FTS1 SERVICE AGREEMENTS
This is a schedule of other FTS1 Service Agreements substantially identical to this exhibit in all material respects. The other FTS1 Service Agreements to which the Registrant is a party are set forth below with the material details that differ from this Exhibit:
1. FTS1 Service Agreement No. 43829, dated October 4, 1994, by and between Columbia Gulf Transmission Company and Delta Natural Gas Co., Inc. Materially different details: Transportation Demand - 1,407 Dekatherms/day; Maximum Daily Quantity for both receipt and delivery points - 860 Dekatherms/day.
2. FTS1 Service Agreement No. 43827, dated October 4, 1994, by and between Columbia Gulf Transmission Company and Delta Natural Gas Co., Inc. Materially different details: Transportation Demand - 860 Dekatherms/day; Maximum Daily Quantity for receipt and delivery points - 860 Dekatherms/day.
3. FTS1 Service Agreement No. 44375, dated November 1, 1999, by and between Columbia Gulf Transmission Company and Delta Natural Gas Co., Inc. Materially different details: the Agreement states that its initial term will expire October 31, 2004; Transportation Demand - 105 Dekatherms/day; Maximum Daily Quantity for receipt and delivery points - 105 Dekatherms/day.
4. FRS1 Service Agreement No. 43322, dated November 1, 1994, by and between Columbia Gulf Transmission Company and Delta Natural Gas Co., Inc. Materially different details: the Agreement states that its initial term will expire October 31, 2004; Transportation Demand - 170 Dekatherms/day; Maximum Daily Quantity for receipt and delivery points - 170 Dekatherms/day.
Exhibit 10(i)
BB&T
LOAN AGREEMENT
This Loan Agreement (the "Agreement") is made this 31st day of October, 2002 by and between BRANCH BANKING AND TRUST COMPANY, a North Carolina banking corporation ("Bank"), and:
DELTA NATURAL GAS COMPANY, INC., a Kentucky corporation ("Borrower"), having its chief executive office at Winchester, Kentucky.
The Borrower has applied to Bank for and the Bank has agreed to make, subject to the terms of this Agreement, the following loan(s) (hereinafter referred to, singularly or collectively, if more than one, as "Loan"):
LINE OF CREDIT ("Line of Credit" or "Line") in the maximum principal amount not to exceed $40,000,000 at any one time outstanding for the purpose of Working Capital which shall be evidenced by the Borrower's Promissory Note dated on or after the date hereof which shall mature October 31, 2003, when the entire unpaid principal balance then outstanding plus accrued interest thereon shall be paid in full. Prior to maturity or the occurrence of any Event of Default hereunder and subject to any Borrowing Base limitations, as applicable, the Borrower may borrow, repay, and reborrow under the Line of Credit through maturity. The Line of Credit shall bear interest at the rate set forth in any such Note evidencing all or any portion of the Line of Credit, the terms of which are incorporated herein by reference.
SECTION 1 CONDITIONS PRECEDENT
The Bank shall not be obligated to make any disbursement of Loan proceeds until all of the following conditions have been satisfied by proper evidence, execution, and/or delivery to the Bank of the following items in addition to this Agreement, all in form and substance satisfactory to the Bank and the Bank's counsel in their sole discretion:
NOTE(S): The Note(s) evidencing the Loans(s) duly executed by the Borrower.
CORPORATE RESOLUTION: A Corporate Resolution duly adopted by the Board of
Directors of the Borrower authorizing the execution, delivery, and
performance of the Loan Documents on or in a form provided by or
acceptable to Bank.
ARTICLES OF INCORPORATION: A copy of the Articles of Incorporation and all
other charter documents of the Borrower, all filed with and certified
by the Secretary of State of the State of the Borrower's incorporation.
BY-LAWS: A copy of the By-Laws of the Borrower, certified by the Secretary
of the Borrower as to their completeness and accuracy.
CERTIFICATE OF INCUMBENCY: A certificate of the Secretary of the Borrower
certifying the names and true signatures of the officers of the
Borrower authorized to sign the Loan Documents.
CERTIFICATE OF EXISTENCE: A certification of the Secretary of State (or
other government authority) of the State of the Borrower's
Incorporation or Organization as to the existence or good standing of
the Borrower and its charter documents on file.
OPINION OF COUNSEL: An opinion of counsel for the Borrower satisfactory to
the Bank and the Bank's counsel.
ADDITIONAL DOCUMENTS: Receipt by the Bank of other approvals, opinions, or
documents as the Bank may reasonably request.
SECTION 2 REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants to Bank that:
2.01. FINANCIAL STATEMENTS. The balance sheet of the Borrower and its
subsidiaries, if any, and the related Statements of Income and Retained
Earnings of the Borrower and its subsidiaries, the accompanying
footnotes together with the accountant's opinion thereon, and all other
financial information previously furnished to the Bank, are in all
material respects true and correct and fairly reflect the financial
condition of the Borrower and its subsidiaries as of the dates thereof,
including all contingent liabilities of every type required under
Generally Accepted Accounting Principles (GAAP) to be included
thereunder, and the financial condition of the Borrower and its
subsidiaries as stated therein has not changed materially and adversely
since the date thereof.
2.02. NAME, CAPACITY AND STANDING. The Borrower's exact legal name is
correctly stated in the initial paragraph of the Agreement. The
Borrower warrants and represents that it is duly organized and validly
existing under the laws of its respective state of incorporation or
organization; that it and/or its subsidiaries, if any, are duly
qualified and in good standing in every other state in which the nature
of their business shall require such qualification, and are each duly
authorized by their board of directors to enter into the Agreement.
2.03. NO VIOLATION OF OTHER AGREEMENTS. The execution of the Loan
Documents, and the performance by the Borrower thereunder will not
violate any material provision, as applicable, of its articles of
incorporation, by-laws, articles of organization, operating agreement,
agreement of partnership, limited partnership or limited liability
partnership, or, of any law, other agreement, indenture, note, or other
instrument binding upon the Borrower, or give cause for the
acceleration of any of the respective obligations of the Borrower.
2.04. AUTHORITY. All authority from and approval by any federal, state,
or local governmental body, commission or agency necessary to the
making, validity, or enforceability of this Agreement and the other
Loan Documents has been obtained.
2.05. ASSET OWNERSHIP. The Borrower has good and marketable title to all
of the properties and assets reflected on the balance sheets and
financial statements furnished to the Bank, and all such properties and
assets are free and clear of mortgages, deeds of trust, pledges, liens,
and all other encumbrances except as otherwise disclosed by such
financial statements.
2.06. DISCHARGE OF LIENS AND TAXES. The Borrower and its subsidiaries,
if any, have filed, paid, and/or discharged all taxes or other claims
which may become a lien on any of their respective properties or
assets, excepting to the extent that such items are being appropriately
contested in good faith and for which an adequate reserve (in an amount
acceptable to Bank) for the payment thereof is being maintained.
2.07. REGULATION U. None of the Loan proceeds shall be used directly or
indirectly for the purpose of purchasing or carrying any margin stock
in violation of the provisions of Regulation U of the Board of
Governors of the Federal Reserve System.
2.08. ERISA. Each employee benefit plan, as defined by the Employee
Retirement Income Security Act of 1974, as amended ("ERISA"),
maintained by the Borrower or by any subsidiary of the Borrower meets
in all material respects, as of the date hereof, the minimum funding
standards of Section 302 of ERISA, all applicable requirements of ERISA
and of the Internal Revenue Code of 1986, as amended, and no
"Reportable Event" nor "Prohibited Transaction" (as defined by ERISA)
has occurred with respect to any such plan.
2.09. LITIGATION. There is no claim, action, suit or proceeding
pending, (to the knowledge of Borrower) threatened or reasonably
anticipated before any court, commission, administrative agency,
whether State or Federal, or arbitration which will materially
adversely affect the financial condition, operations, properties, or
business of the Borrower or its subsidiaries, if any, or the ability of
the Borrower to perform its obligations under the Loan Documents.
2.10. OTHER AGREEMENTS. The representations and warranties made by
Borrower to Bank in the other Loan Documents are true and correct in
all material respects on the date hereof.
2.11. BINDING AND ENFORCEABLE. The Loan Documents, when executed, shall
constitute valid and binding obligations of the Borrower, the execution
of such Loan Documents has been duly authorized by the parties thereto,
and are enforceable in accordance with their terms, except as may be
limited by bankruptcy, insolvency, moratorium, or similar laws
affecting creditors' rights generally and by general equitable
principles.
2.12. COMMERCIAL PURPOSE. The Loan(s) are not "consumer transactions",
as defined in the Kentucky Uniform Commercial Code.
BB&T
LOAN AGREEMENT
SECTION 3 AFFIRMATIVE COVENANTS
The Borrower covenants and agrees that from the date hereof and until
payment in full of all indebtedness and performance of all obligations owed
under the Loan Documents, Borrower shall:
3.01. MAINTAIN EXISTENCE AND CURRENT LEGAL FORM OF BUSINESS. (a)
Maintain its existence and good standing in the state of its
incorporation or organization, (b) maintain its current legal form of
business indicated above, and, (c), as applicable, qualify and remain
qualified as a foreign corporation, general partnership, limited
partnership, limited liability partnership or limited liability company
in each jurisdiction in which such qualification is required.
3.02. MAINTAIN RECORDS. Keep adequate records and books of account, in
which complete entries will be made in accordance with GAAP
consistently applied, reflecting all financial transactions of the
Borrower.
3.03. MAINTAIN PROPERTIES. Maintain, keep, and preserve all of its
properties (tangible and intangible) including the collateral necessary
or useful in the conduct of its business in good working order and
condition, ordinary wear and tear excepted.
3.04. CONDUCT OF BUSINESS. Continue to engage in a business of the same
general type as now conducted.
3.05. MAINTAIN INSURANCE. Maintain insurance with financially sound and
reputable insurance companies or associations in such amounts and
covering such risks as are usually carried by companies engaged in the
same or a similar business, and business interruption insurance if
required by Bank, which insurance may provide for reasonable
deductible(s).
3.06. COMPLY WITH LAWS. Comply in all material respects with all
applicable laws, rules, regulations, and orders including, without
limitation, paying before the delinquency of all taxes, assessments,
and governmental charges imposed upon it or upon its property, and all
environmental laws.
3.07. RIGHT OF INSPECTION. Permit the officers and authorized agents of
the Bank, at any reasonable time or times in the Bank's sole
discretion, to examine and make copies of the records and books of
account of, to visit the properties of the Borrower, and to discuss
such matters with any officers, directors, managers, members or
partners, limited or general of the Borrower, and the Borrower's
independent accountant as the Bank deems necessary and proper.
3.08. REPORTING REQUIREMENTS. Furnish to the Bank:
QUARTERLY FINANCIAL STATEMENTS: As soon as available and not more
than forty five (45) days after the end of each quarter, balance
sheets, statements of income, cash flow, and retained earnings
for the period ended and a statement of changes in the financial
position, all in reasonable detail, and all prepared in
accordance with GAAP consistently applied and certified as true
and correct by an officer of the Borrower, as appropriate.
ANNUAL FINANCIAL STATEMENTS: As soon as available and not more
than one hundred twenty (120) days after the end of each fiscal
year, balance sheets, statements of income, and retained earnings
for the period ended and a statement of changes in the financial
position, all in reasonable detail, and all prepared in
accordance with GAAP consistently applied. The financial
statements must be of the following quality or better: Audited.
NOTICE OF LITIGATION: Promptly after the receipt by the Borrower
of notice or complaint of any action, suit, and proceeding before
any court or administrative agency of any type which, if
determined adversely, could have a material adverse effect on the
financial condition, properties, or operations of the Borrower.
NOTICE OF DEFAULT: Promptly upon discovery or knowledge thereof,
notice of the existence of any event of default under this
Agreement or any other Loan Documents.
OTHER INFORMATION: Such other information as the Bank may from
time to time reasonably request.
3.09. DEPOSIT ACCOUNTS. Maintain substantially all of its demand
deposit/operating accounts with the Bank.
3.10. SENIOR MANAGEMENT: No change in senior management shall occur
that is unacceptable to the Bank.
SECTION 4 EVENTS OF DEFAULT
The following shall be "Events of Default" by Borrower:
4.01. The failure to make prompt payment of any installment of
principal or interest on any of the Note(s) in accordance with the
terms and conditions of the Note(s).
4.02. Should any representation or warranty made in the Loan Documents
prove to be false or misleading in any material respect.
4.03 Should any report, certificate, financial statement, or other
document furnished prior to the execution of or pursuant to the terms
of this Agreement prove to be false or misleading in any material
respect.
4.04. Should the Borrower default on the performance of any other
obligation of indebtedness to the Bank or to any third party when due
or in the performance of any obligation incurred in connection with
money borrowed, and the default remains uncured for a period of ten
(10) days after notice from Bank to Borrower.
4.05. Should the Borrower breach any material covenant, condition, or
agreement made under any of the Loan Documents, and the breach remains
uncured for a period of ten (10) days after notice from Bank to
Borrower.
4.06. Should a custodian be appointed for or take possession of any or
all of the assets of the Borrower, or should the Borrower either
voluntarily or involuntarily become subject to any insolvency
proceeding, including becoming a debtor under the United States
Bankruptcy Code, any proceeding to dissolve the Borrower, any
proceeding to have a receiver appointed, or should the Borrower make an
assignment for the benefit of creditors, or should there be an
attachment, execution, or other judicial seizure of all or any portion
of the Borrower's assets, including an action or proceeding to seize
any funds on deposit with the Bank, and such seizure is not discharged
within 30 days.
4.07. Should final judgment for the payment of money be rendered
against the Borrower in excess of $100,000 which is not covered by
insurance and shall remain undischarged for a period of 30 days unless
such judgment or execution thereon be effectively stayed.
4.08. Upon the death of, or termination of existence of, or dissolution
of, any Borrower.
4.09. Should the Bank in good faith deem itself, its liens and security
interests, if any, or any debt thereunder unsafe or insecure, or should
the Bank believe in good faith that the prospect of payment of any debt
or other performance by the Borrower is impaired.
SECTION 5 REMEDIES UPON DEFAULT
Upon the occurrence of any of the above listed Events of Default, the Bank may at any time thereafter, at its option, take any or all of the following actions, at the same or at different times:
5.01. Declare the balance(s) of the Note(s) to be immediately due and
payable, both as to principal and interest, without presentment,
demand, protest, or notice of any kind, all of which are hereby
expressly waived by Borrower, and such balance(s) shall accrue interest
at the Default Rate as provided herein until paid in full;
5.02. Require the Borrower to pledge collateral to the Bank from the
Borrower's assets and properties, the acceptability and sufficiency of
such collateral to be determined in the Bank's sole discretion;
5.03. Take immediate possession of and foreclose upon any or all
collateral which may be granted to the Bank as security for the
indebtedness and obligations of Borrower under the Loan Documents;
5.04. Exercise any and all other rights and remedies available to the
Bank under the terms of the Loan Documents and applicable law,
including the Kentucky Uniform Commercial Code; and
5.05. Any obligation of the Bank to advance funds to the Borrower or
any other Person under the terms of the Note(s) and all other
obligations, if any, of the Bank under the Loan Documents shall
immediately cease and terminate unless and until Bank shall reinstate
such obligation in writing.
BB&T
LOAN AGREEMENT
SECTION 6 NEGATIVE COVENANTS
The Borrower covenants and agrees that from the date hereof and until
payment in full of all indebtedness and performance of all obligations owed
under the Loan Documents, Borrower shall not:
6.01 DISPOSITION OF ASSETS. Sell, assign, lease, convey or transfer or
otherwise dispose of a material portion of its assets other than in the
ordinary course of its business.
6.02 CONSOLIDATIONS AND MERGERS. Merge, consolidate with or into any
other entity or otherwise dispose of substantially all of its assets.
6.03 ISSUANCE OF STOCK. Issue any of its stock to the public or in an
exempt transaction whereby such issuances in the aggregate exceed
thirty-five percent (35%) of the Borrower's currently authorized and
outstanding shares of common stock.
6.04 ACCUMULATION OF STOCK. Have any person or entity or a group of
affiliated persons or entities, hold more than twenty percent (20%) of
the then outstanding shares of Borrower common stock
SECTION 7 MISCELLANEOUS PROVISIONS
7.01. DEFINITIONS.
"DEFAULT RATE" shall mean a rate of interest equal to Bank's
Prime Rate plus five percent (5%) per annum (not to exceed the
legal maximum rate) from and after the date of an Event of
Default hereunder which shall apply, in the Bank's sole
discretion, to all sums owing, including principal and interest,
on such date.
"LOAN DOCUMENTS" shall mean this Agreement including any schedule
attached hereto, the Note(s), and all other documents,
certificates, and instruments executed in connection therewith,
and all renewals, extensions, modifications, substitutions, and
replacements thereto and therefore.
"PERSON" shall mean an individual, partnership, corporation,
trust, unincorporated organization, limited liability company,
limited liability partnership, association, joint venture, or a
government agency or political subdivision thereof.
"GAAP" shall mean generally accepted accounting principles as
established by the Financial Accounting Standards Board or the
American Institute of Certified Public Accountants, as amended
and supplemented from time to time.
"PRIME RATE" shall mean the rate of interest per annum announced
by the Bank from time to time and adopted as its Prime Rate,
which is one of several rate indexes employed by the Bank when
extending credit, and may not necessarily be the Bank's lowest
lending rate.
"COMMITTED LINE AMOUNT" shall mean the amount of Forty Million
Dollars ($40,000,000) or in the event the Borrower exercises its
option to reduce the amount of the line under Section 7.16
hereof, it shall be the amount of Forty Million Dollars
($40,000,000) less the reduction amount.
"TERM" shall mean a period of time commencing on the execution of
this Agreement and continuing through October 31, 2003 unless
earlier terminated or extended in accordance with the terms and
conditions hereof.
7.02. NON-IMPAIRMENT. If any one or more provisions contained in the
Loan Documents shall be held invalid, illegal, or unenforceable in any
respect, the validity, legality, and enforceability of the remaining
provisions contained therein shall not in any way be affected or
impaired thereby and shall otherwise remain in full force and effect.
7.03. APPLICABLE LAW. The Loan Documents shall be construed in
accordance with and governed by the laws of the Commonwealth of
Kentucky without reference to its principles of conflicts of law or
choice of law.
7.04. WAIVER. Neither the failure or any delay on the part of the Bank
in exercising any right, power or privilege granted in the Loan
Documents shall operate as a waiver thereof, nor shall any single or
partial exercise thereof preclude any other or further exercise of any
other right, power, or privilege which may be provided by law.
7.05. MODIFICATION. No modification, amendment, or waiver of any
provision of any of the Loan Documents shall be effective unless in
writing and signed by the Borrower and Bank.
7.06. STAMPS AND FEES. The Borrower shall pay all federal or state
stamps, taxes, or other fees or charges, if any are payable or are
determined to be payable by reason of the execution, delivery, or
issuance of the Loan Documents or any security granted to the Bank; and
the Borrower agrees to indemnify and hold harmless the Bank against any
and all liability in respect thereof.
7.07. ATTORNEYS' FEES. In the event the Borrower shall default in any
of its obligations hereunder and the Bank believes it necessary to
employ an attorney to assist in the enforcement or collection of the
indebtedness of the Borrower to the Bank, to enforce the terms and
provisions of the Loan Documents, to modify the Loan Documents, or in
the event the Bank voluntarily or otherwise should become a party to
any suit or legal proceeding (including a proceeding conducted under
the Bankruptcy Code), the Borrower agrees to pay the reasonable
attorneys' fees of the Bank and all related costs of collection or
enforcement that may be incurred by the Bank. The Borrower shall be
liable for such attorneys' fees and costs whether or not any suit or
proceeding is actually commenced.
7.08. RIGHT OF OFFSET. Any indebtedness owing from Bank to Borrower may
be set off and applied by Bank on any indebtedness or liability of
Borrower to Bank, at any time and from time to time after maturity,
whether by acceleration or otherwise, and without demand or notice to
Borrower. Bank may sell participations in or make assignments of any
Loan made under this Agreement, and Borrower agrees that any such
participant or assignee shall have the same right of setoff as is
granted to the Bank herein.
7.09. MODIFICATION AND RENEWAL FEES. Bank may, at its option, charge
any fees for modification, renewal, extension, or amendment of any
terms of the Note(s) not prohibited by Kentucky law, and as otherwise
permitted by law if Borrower is located in another state.
7.10. CONFLICTING PROVISIONS. If provisions of this Agreement shall
conflict with any terms or provisions of any of the Note(s), the
provisions of such Note(s) shall take priority over any provisions in
this Agreement.
7.11. NOTICES. Any notice permitted or required by the provisions of
this Agreement shall be deemed to have been given when delivered in
writing to the City Executive or any Vice President of the Bank at its
offices in Winchester, Kentucky, and to the Chief Financial Officer of
the Borrower at its offices in Winchester, Kentucky, when sent by
certified mail and return receipt requested.
7.12. CONSENT TO JURISDICTION. Borrower hereby irrevocably agrees that
any legal action or proceeding arising out of or relating to this
Agreement may be instituted in any Kentucky state court or federal
court sitting in the state of Kentucky, or in such other appropriate
court and venue as Bank may choose in its sole discretion. Borrower
consents to the jurisdiction of such courts and waives any objection
relating to the basis for personal or in rem jurisdiction or to venue
which Borrower may now or hereafter have in any such legal action or
proceedings.
7.13. COUNTERPARTS. This Agreement may be executed by one or more
parties on any number of separate counterparts and all of such
counterparts taken together shall be deemed to constitute one and the
same instrument.
7.14. FEES. Payment quarterly of an unused availability fee equal to
three tenths of one percent (0.30%) of the unused availability of the
Line of credit. Unused availability is calculated by subtracting the
average outstanding principal balance for the previous ninety (90) days
from the Committed Line Amount. In addition, Borrower shall pay all
attorneys' and related legal fees and other costs, if any, incurred by
Bank in connection with the making, documenting and closing of the
Line.
7.15. ADVANCES AND REPAYMENT. Funds shall be advanced under the Line at
the request of an authorized officer of the Borrower, which shall be
made in writing in a form acceptable to the Bank. Prior to maturity or
an Event of Default hereunder, Borrower may borrow, repay, and
re-borrow under the Loan.
BB&T
LOAN AGREEMENT
7.16. OPTION TO REDUCE AMOUNT AVAILABLE. At the Borrower's option, the
Borrower has a one-time option to reduce the amount of the "Line"
offered hereunder at any time during the Term. Written notice of such
exercise, including the amount of such reduction, shall be delivered by
the Borrower to the Bank. Notwithstanding the provisions afforded under
the paragraph ADVANCES AND REPAYMENT above, the Committed Line Amount
will be reduced by the amount of the reduction, thereby amending the
Committed Line Amount available to the Borrower for the remaining Term.
At no time shall the Committed Line Amount fall below $30 million.
Exercising this Option will reduce the unused availability fee on that
portion of the Line no longer available to the Borrower, effective with
the date the Borrower's written notice, if any, is received by the
Bank.
7.17. INDEMNIFICATION BY BORROWER. Except for claims, damages,
liabilities and expenses arising from Bank's gross negligence or
misconduct, Borrower agrees to indemnify and hold harmless Bank from
and against any and all claims, damages, liabilities and expenses which
may be incurred by or asserted against Bank in connection with any
proceeding arising out of this commitment or Borrower's use of the
proceeds of the Line.
7.18. ENTIRE AGREEMENT. The Loan Documents embody the entire agreement
between Borrower and Bank with respect to the Loans, and there are no
oral or parol agreements existing between Bank and Borrower with
respect to the Loans which are not expressly set forth in the Loan
Documents.
IN WITNESS WHEREOF, the Bank and Borrower have caused this Agreement to be duly executed under seal all as of the date first above written.
BORROWER:
DELTA NATURAL GAS COMPANY, INC.
----------------------------------------------------------------
Name of Corporation
Attest: /s/ JOHN F. HALL By: /s/ GLENN R. JENNINGS
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Glenn R. Jennings
Title: Chief Financial Officer Title: President
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BRANCH BANKING AND TRUST COMPANY
Attest: By: /s/ WILLIAM W. JAMES
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William W. James
Title: Title: City Executive and Senior Vice President
---------------------------------------------------------
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EXHIBIT 12
DELTA NATURAL GAS COMPANY, INC. AND SUBSIDIARY COMPANIES
COMPUTATION OF THE CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES
For the Three Months Ended
--------------------------
September 30, For the Years Ended June 30,
------------- ----------------------------
2002 2001 2002 2001 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Earnings:
Net Income $ (991,247) $ (778,325) $ 3,636,713 $ 3,635,895 $ 3,464,857 $2,150,794 $2,451,272
Provisions for income taxes (556,543) (475,400) 2,249,500 2,232,500 2,068,500 1,239,100 1,401,000
Fixed charges 1,145,759 1,263,181 4,781,757 5,116,965 4,754,731 4,534,936 4,348,498
---------- ---------- ----------- ----------- ----------- ---------- ----------
Total $ (402,031) $ 9,456 $10,667,970 $10,985,360 $10,288,088 $7,924,830 $8,200,770
========== ========== =========== =========== =========== ========== ==========
Fixed Charges:
Interest on debt $1,105,469 $1,222,891 $ 4,620,597 $ 4,955,805 $ 4,593,571 $4,373,776 $4,223,946
Amortization of debt expense 40,290 40,290 161,160 161,160 161,160 161,160 124,552
---------- ---------- ----------- ----------- ----------- ---------- ----------
$1,145,759 $1,263,181 $ 4,781,757 $ 5,116,965 $ 4,754,731 $4,534,936 $4,348,498
========== ========== =========== =========== =========== ========== ==========
Ratio of Earnings to
Fixed Charges:
Actual (.35x) .01x 2.23x 2.15x 2.16x 1.75x 1.89x
Pro Forma:
Actual fixed charges 1,145,759 4,781,757
Pro forma interest on debt to be
Sold, assuming a rate of 7.25% 362,500 1,450,000
Actual interest on debt to
be retired (334,655) (1,338,618)
Pro forma fixed charges 1,173,604 4,893,139
Pro forma ratio of earnings to
fixed charges (.32x) 2.20x
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EXHIBIT 23(a)
INDEPENDENT AUDITOR'S CONSENT AND REPORT ON SCHEDULE
We consent to the use in this Pre-Effective Amendment No. 1 to the Registration Statement of Delta Natural Gas Company, Inc. on Form S-2 (File No. 333-100852) of our report dated August 19, 2002, appearing in this Prospectus, which is part of this Registration Statement. We also consent to the reference to us under the heading "Experts" in such Prospectus.
Our audit of the 2002 financial statements referred to in our aforementioned report also included the 2002 financial statement schedule of Delta Natural Gas Company, Inc., listed in Item 8 of the Annual Report on Form 10-K of the Delta Natural Gas Company, Inc. for the year ended June 30, 2002 and incorporated by reference in this Pre-Effective Amendment No. 1 to the Registration Statement of Delta Natural Gas Company, Inc. on Form S-2. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audit. In our opinion, such financial statement schedule, when considered in relation to the 2002 basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Cincinnati, Ohio
December 10, 2002