CTG RESOURCES INC, 10-K405, 1999-12-14

CTG RESOURCES INC
10-K405, 1999-12-14
NATURAL GAS DISTRIBUTION

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549
FORM 10-K

(X)ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999

OR,

( )TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____________________

to _______________________

CTG Resources, Inc.
(Exact name of registrant as specified in its charter)

Connecticut (State or other jurisdiction of incorporation or organization)		06-1466463 (I.R.S. Employer Identification No.)

100 Columbus Blvd. P.O. Box 1500 Hartford, Connecticut (Address of principal executive offices)		06144-1500 (Zip code)

Registrant's telephone number, including area code (860) 727-3010

Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Common Stock - No Par		Name of Each Exchange on Which Registered New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]

State the aggregate market value of the voting stock held by nonaffiliates of the registrant. (The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within 60 days prior to the date of filing.)

The aggregate market value of the voting stock held by nonaffiliates of the Registrant on November 1, 1999 was
$317,734,027.

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (applicable only to corporate registrants).

Number of shares of common stock outstanding as of the close of business on November 1, 1999 was 8,648,029.

DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the Part of the Form 10-K into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes.

None

PART I

ITEM 1. BUSINESS

General

CTG Resources, Inc. ("the Company" or "CTG") is a Connecticut corporation organized as a holding company with two wholly-owned subsidiaries: Connecticut Natural Gas Corporation ("CNG") and The Energy Network, Inc. ("TEN"). CNG is an energy provider engaged in the regulated distribution, sale and transportation of natural gas. TEN holds and operates, through divisions or wholly-owned subsidiaries, CTG's unregulated, diversified businesses, which are primarily engaged in district heating and cooling ("DHC") and also include the Company's equity investments in two partnerships, the Iroquois Gas Transmission System Limited Partnership ("Iroquois") and the Downtown Cogeneration Associates Limited Partnership ("DCA").

CTG's headquarters are in Hartford, Connecticut. At September 30, 1999, the Company employed 547 people. The Company's common stock is traded on the New York Stock Exchange, under the symbol CTG. Preferred stock of CNG is traded on the over-the-counter market.

CTG's principal business is the distribution, transportation and sale of natural gas through CNG. This business is subject to extensive regulation. CTG's diversified businesses are unregulated and provide energy-related products and services, primarily district heating and cooling. The activities of Iroquois are regulated at the Federal level.

Segment information for all relevant periods is included in the Notes to the Financial Statements filed in Part II, Item 8 of this report.

Merger with Energy East

On June 29, 1999, CTG announced that it had entered into an Agreement and Plan of Merger with Energy East Corporation, a New York corporation ("Energy East"), and Oak Merger Co. ("Oak"), a wholly-owned subsidiary of Energy East, pursuant to which CTG will merge with and into Oak (the "Merger"). The Merger is contingent, among other things, upon the approvals of CTG's shareholders, the Connecticut Department of Public Utility Control ("DPUC"), the United States Securities and Exchange Commission, the Federal Trade Commission and the Federal Communications Commission. Energy East and CTG anticipate that these approvals will be obtained by mid-year 2000. CTG's shareholders approved the Merger on October 18, 1999. The DPUC is scheduled to issue a decision on the Merger in January 2000. Federal filings are also in progress.

Seasonality

The Company's operations are seasonal. Most of the Company's gas revenues and related operating expenses occur during the winter heating season, November to March. Natural gas usage in the Company's service area is greater for heating purposes in winter and less for cooling in summer. Natural gas usage for nonheating purposes remains steady throughout the year. Accordingly, earnings are highest during the first and second quarters of the fiscal year, which begins October 1, and the third and fourth quarters frequently show a net loss. The impact of seasonality on cash flows is discussed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The Company's unregulated district heating and cooling businesses experience peak loads during both the winter heating and summer cooling seasons.

Competition

In recent years, the natural gas industry has undergone structural changes in response to Federal regulatory policy intended to increase competition. In 1992, the Federal Energy Regulatory Commission ("FERC") issued Order 636, which required all interstate gas pipelines to provide "unbundled," or separate, gas transportation and storage services and to discontinue their bundled merchant sales operations, which included the gas acquisition function. The impact of the FERC Order 636 and the resulting deregulation of the gas industry has continued to heighten competition and has changed the nature of the Company's business.

At the local level, as a result of FERC Order 636 and Connecticut deregulation, the Company continues to face increasing competitive pressures as other providers of gas seek opportunities to make gas sales to the Company's commercial and industrial customers. Similarly, the Company has offered firm transportation rate tariffs to nonresidential customers, since April of 1996. The Company's transportation tariffs are designed to recover a margin on each transaction that is comparable to the margin that the Company would have received if it were making an on-system sale of natural gas.

The Company also competes with suppliers of oil, electricity and propane for cooking, heating, air conditioning and other purposes. Competition is greatest among the large commercial and industrial customers who have the capability of using alternative fuels. The volatile effect of this price-sensitive load is somewhat overcome through the use of flexible rate schedules, which allow gas pricing to meet alternative-fuel competition.

The unregulated, diversified businesses own and operate DHC systems, which distribute and sell steam, hot water and chilled water to office complexes and other large buildings in the City of Hartford. The extent of competition to the DHC business from alternate fuels is diminished after a customer has made its commitment to DHC because of the cost of the equipment necessary to utilize an alternative energy source. Similarly, the diversified businesses own and operate cogeneration facilities, which distribute thermal energy and electricity to hospitals, universities and other large commercial and industrial users.

Regulatory Jurisdiction

CNG's principal business is the distribution of natural gas, and this business is subject to regulation by the Connecticut Department of Public Utility Control ("DPUC") as a public service company. The scope of this regulation encompasses rates, standards of service, issuance of certain securities, safety practices and other matters. Retail sales of gas by the Company and deliveries of gas owned by others are made pursuant to rate schedules and contracts filed with and subject to DPUC approval. In general, the firm rate schedules provide for some reductions in the unit price of gas as greater quantities are used. The rate schedules contain purchased gas adjustment provisions as described in Note 1 to the Financial Statements (included in Part II, Item 8 herein).

Businesses operated by TEN are not public service companies under state law, and hence they are not subject to regulation by the DPUC. However, intercompany transactions between CNG and its affiliates are subject to review and/or approval by the DPUC.

The Company makes off-system sales and/or pipeline capacity releases in interstate commerce under authorizations provided by FERC Order 636 pursuant to blanket certificates. The FERC regulates the Company's pipeline gas suppliers and transporters, and the Company closely follows and participates in numerous proceedings before FERC. Through an unregulated subsidiary of TEN, TEN Transmission Company ("TEN Transmission"), the Company is an equity partner in Iroquois which is subject to regulation by FERC.

Natural Gas Business (Regulated)

CNG is a Connecticut corporation organized in 1848 and headquartered in Hartford, Connecticut. CNG is engaged in the distribution, transportation and sale of natural gas in Greenwich, Connecticut and in Hartford and 21 other cities and towns in central Connecticut. This business is subject to extensive regulation. Many aspects of this traditional business have changed or are expected to change as deregulation of the industry occurs. Other sections of this document address these changes (See "Competition" (above) and "Regulatory Matters" (below) in this Part I).

Consolidated gas operating revenues were $262,060,000 for the fiscal year ended September 30, 1999 and were derived approximately 49% from residential customers, 18% from commercial firm customers, 1% from industrial firm customers, 16% from interruptible customers, 14% from off-system sales and 2% from the aggregate of transportation of customer-owned gas and other gas-related revenues. There were $2,181,000 of revenues from sales to affiliated companies. The gas distribution business contributed 92% of consolidated revenues over the three fiscal years ending 1999. During the fiscal year ended September 30, 1999, the peak-day sendout of gas was 289,637 thousands of cubic feet ("mcf"), which occurred on January 14, 1999.

CNG has one wholly-owned subsidiary, CNG Realty Corp. ("CNGR"), which was formed in 1977. CNGR is a single purpose corporation, which owns the Company's Operating and Administrative Center located on a 3.5-acre site in downtown Hartford, Connecticut. This facility is leased to CNG. CNGR engages in no other business activity.

Gas Supply

The Company's current gas supply contract portfolio reflects the results of a continuing supply diversification strategy. The purpose of such a strategy is to hold a secure, flexible, best-cost gas supply portfolio, which allows the Company to respond quickly and appropriately as customer needs change.

The Company purchases natural gas on a long-term and seasonal basis from producers and, when economics dictate, on a short-term basis in the spot market. Pipeline services purchased include firm and interruptible transportation service. Gas storage service in the northeast and in the southeast production area is purchased from both pipelines and storage contractors.

The Company's principal and most economical source of gas is pipeline-delivered natural gas. Because of limited transportation capacity, pipelines may be unable to meet all of the Company's needs during the coldest periods of the year. Therefore, the Company also utilizes liquefied natural gas ("LNG") and, to a much lesser extent, propane mixed with air ("LP-Air"). LNG and LP-Air are usually more expensive than natural gas. Therefore, they are used primarily during the winter months for peak shaving when the demand for gas is greatest and exceeds deliverable supplies of natural gas through the pipelines.

The Company currently holds pipeline transportation contracts with Algonquin Gas Transmission Company ("AGT"), CNG Transmission Corporation ("CNGT"), Iroquois Gas Transmission System ("IGTS"), National Fuel Gas Supply Corporation ("NFGS"), Tennessee Gas Pipeline Company ("TGP"), Texas Eastern Gas Transmission Corporation ("TETCO"), and Transcontinental Gas Pipeline Corporation ("TRANSCO"). The various agreements expire at different times through 2012 and provide for the delivery of a total maximum daily quantity of approximately 170,596 mcf and maximum annual quantity of approximately 48,708,730 mcf.

Under FERC Order 636, the continuity of a local gas distribution company's transportation service arrangements is assured. A pipeline may not terminate service to a long-term firm transportation customer if that customer elects to exercise a "right of first refusal" following the initial contract term expiration. This requires the customer to match the price and length terms of another offer made to the pipeline to continue to purchase such service. The price for such continued firm transportation service would be capped at the maximum price determined as a just and reasonable rate under FERC jurisdiction.

The gas supply which feeds into the Company's firm transportation rights on the interstate pipelines has been contracted for directly with producers of natural gas ("Direct Producer Contracts"). The Direct Producer Contracts are diverse in terms of expiration date, supply location, price, flexibility, etc. as part of the Company's gas supply diversification strategy.

The Company continues to be very active in the area of purchasing gas directly from producers both in the spot market and under longer-term arrangements. Currently, the Company purchases all of its gas under such arrangements. Spot market volumes are those purchased under short-term arrangements from producers and gas withdrawn from storage which had been purchased directly from producers for injection to that storage. Spot market purchases are established through negotiations with the supplier.

The Company has contracted for storage service in various locations and with diverse expiration dates through 2012. Under these arrangements, gas available during the warmer months of the year is stored underground in locations that, although out-of-state, are accessible for use during the colder winter months of the year and for balancing throughout the year.

In addition to its pipeline gas supplies, the Company owns an LNG plant in Rocky Hill, Connecticut. This plant has the design capacity to liquefy approximately 6,000 MCF per day and store 1,206,000 MCF. The LNG plant is not a source of additional gas supply, but it permits the Company to liquefy and store gas supplies purchased during the summer and to deliver this stored gas during the following winter. The plant has the design capacity to vaporize 60,000 MCF per day.

LP-Air is a source of peak shaving supply to the Company. The Company has approximately 720,000 gallons of on-site propane storage, which can produce the equivalent of approximately 8,208 MCF of natural gas per day.

Regulatory Matters

The DPUC is required bv state statute to conduct a financial and operation review of each Connecticut local gas distribution company ("LDC") at intervals of not more than four years from each LDC's last general rate hearing. CNG's last rate decision from the DPUC regarding base rates for natural gas service was issued in October 1995. As such, CNG would have been subject to a four-year financial review with the DPUC beginning no later than October 1999. Rather than await such a statutory financial review, the Company made the decision to initiate a general rate hearing. On September 24, 1999, the CNG filed formal notification of its intention to file an application to increase its rates and charges with the DPUC. CNG filed its general rate case on November 10, 1999, requesting an increase to its base revenues of $15,700,000 or 8.37 %. Key elements of the case include a higher return on equity, increased depreciation rates, lowering of the interruptible sales sharing mechanism, and introduction of a performance-based ratemaking methodology ("RPA"), to take effect following the Merger with Energy East. This RPA includes performance measures, a higher return level, a sharing mechanism, and elimination of the Purchased Gas Adjustment clause. The DPUC review process is ongoing. Rates that reflect the DPUC's decision should become effective by May 2000.

In a series of regulatory proceedings held since 1995, the DPUC has steadily advanced natural gas deregulation in Connecticut. Consumer choice was first made available to commercial, industrial and multi-family residential housing customers in April 1996.

In a second phase of this regulatory review of natural gas deregulation, the DPUC is currently addressing the potential deregulation of the residential natural gas sales market in Connecticut and the future role of the LDCs in natural gas commodity sales. The DPUC has asked Connecticut LDCs to file information for the purpose of examining costs and developing appropriate natural gas sales and delivery rates for customers, to ensure that customers pay only for those services that they use. CNG filed its cost of service study with the DPUC in August 1999. Once the DPUC concludes generic proceedings it is expected to reopen each LDC's rate case that is currently in effect to apply its findings. The Company cannot predict the outcome of these proceedings.

CNG is currently examining its rate structure in this new context, to determine its future applicability in an unbundled environment where sales and delivery services may be purchased separately by all customers.

Diversified Businesses (Unregulated)

At September 30, 1999, the diversified businesses of the Company included TEN and its wholly-owned subsidiaries, The Hartford Steam Company ("HSC"), TEN Transmission, ENI Gas Services, Inc. ("ENI Gas") and TEN Gas Services, Inc. ("TEN Gas").

TEN was incorporated in 1982 and is engaged in the operations described in the following paragraphs. TEN and HSC provide DHC services to many buildings and complexes in the south-end and downtown neighborhoods of Hartford, Connecticut. TEN also holds a fifty percent interest in the DCA with two unrelated third parties. TEN's other operating division offers energy equipment rentals. ENI Gas and TEN Gas together own 100% of KBC Energy Services ("KBC"), a gas marketing business which is in the process of winding down its operations. TEN Transmission owns the Company's share of its investment in the Iroquois pipeline.

TEN Transmission, which was formed in 1986, owns the Company's 4.87% share of Iroquois. Iroquois operates a natural gas pipeline, which transports Canadian natural gas into the states of New York, Massachusetts and Connecticut. Although TEN Transmission is not regulated, Iroquois is regulated by the FERC.

HSC, incorporated in Connecticut in 1961, owns and operates a central production plant and distribution system for the processing and distribution of steam for heating and chilled water for cooling to a number of offices, stores and other large buildings in the south-end and downtown neighborhoods of Hartford, Connecticut. In June 1998, HSC acquired the assets of a cogeneration facility which is located adjacent to and serves Hartford Hospital, providing both steam and electricity. The facility was repowered as a 7.5-megawatt facility and came on line in December 1998. HSC manages the facility and supplies the hospital with steam and electricity over a twenty-year contract period. HSC also sells electricity to the local electric utility .

In April 1999, HSC announced the signing of a 25-year contract with the City of Hartford, Connecticut, under which HSC will provide heating and cooling to The Learning Corridor project in Hartford's sout-end. The Learning Corridor is an $86,000,000 educational campus that forms the centerpiece of the Trinity College/Southside Institutions Neighborhood Alliance ("SINA") neighborhood revitalization initiative. Service will begin in the autumn of 2000.

HSC chills its own water supply for district cooling and produces its own steam from its existing boilers. HSC also purchases steam from DCA, which sells steam to HSC under a twenty-year contract. The DCA owns and operates a 4.2-megawatt cogeneration facility on the roof of a downtown Hartford building complex. Electricity generated from this unit is sold to The Connecticut Light and Power Company ("CL&P") under a twenty-year contract expiring in 2007. In March 1999, TEN and CL&P entered into an agreement to terminate the Electricity Purchase Agreement ("EPA"). CL&P filed this termination agreement with the DPUC on March 31, 1999. Under the termination agreement, closing must occur prior to December 31, 2000. During fiscal 1999, TEN provided cogeneration management and consulting services to DCA.

The Capitol Area System ("CAS") is a district heating and cooling system serving the state office buildings in a section of the City of Hartford, Connecticut. TEN owns the distribution system and purchases hot and chilled water from an unrelated third party. TEN also provides marketing services to this third party.

TEN's energy equipment rentals division owns natural gas water heaters and natural gas conversion burners, which it leases to customers in the residential market.

ENI Gas was formed to own the Company's interest in KBC, a New England natural gas marketer. At September 30, 1997 TEN had a 50% ownership interest in this partnership. During the second quarter of fiscal 1998, TEN Gas was formed to own a portion of KBC, and together ENI Gas and TEN Gas assumed full control of KBC. The KBC operations were deemed not core to TEN's strategic focus on asset-based businesses. Accordingly, in fiscal 1998, ENI Gas and TEN Gas began the sale of KBC's assets and the wind down of its operations. This wind down will be complete in fiscal 2000.

The Energy Network Alliance

In October 1998, TEN entered into a marketing Alliance with Pratt & Whitney Canada, Inc., Carrier Corporation and Oxford Technologies, Inc. (the "Alliance") to provide energy for heating, cooling and electricity to large commercial, industrial and institutional facilities by combining cogeneration and district energy. As the lead role in this Alliance, TEN will own and operate the individual customers' on-site district energy plants, which will be equipped with state-of-the-art energy systems provided by the other members of the Alliance. A number of opportunities are currently being pursued by the Alliance members.

Environmental Considerations

The Company has not experienced and does not anticipate any significant problem in complying with laws and regulations pertinent to its business concerned with protecting the environment. Additional information regarding environmental considerations is included in the Management's Discussion and Analysis of Financial Condition and Results of Operations, filed in Part II, Item 7 of this report, and the Notes to the Financial Statements, filed in Part II, Item 8 of this report.

Franchises

CNG holds franchises, granted by the Legislature of the State of Connecticut, and other consents, which it considers to be valid and adequate to enable it to carry on its operations, substantially as now carried on, in each of the communities which it serves.

ITEM 2. PROPERTIES

Regulated Operations

At September 30, 1999, CNG owns gas distribution mains, a natural gas liquefaction plant, propane gas storage tanks, metering stations, gas service connections, meters, regulators and other equipment necessary for the operation of a gas distribution system. Substantially all of the Company's properties are subject to the lien of the Indenture of Mortgage and Deed of Trust securing its first mortgage bonds. The properties, in management's opinion, are maintained in good operating condition. The gas mains are located principally under public streets, roads and highways.

CNGR owns the Operating and Administrative Center in Hartford which is leased by CNG. The center is subject to the lien of the Mortgage Deed under which the CNGR's first mortgage notes are issued.

Unregulated Operations

TEN owns a distribution system located in the Capitol area of Hartford, Connecticut for the distribution of hot water for heating and chilled water for cooling. This property was financed with industrial revenue bonds secured by a letter of credit with a bank.

HSC owns a central production plant and distribution system, which includes a chilled water storage tank, in downtown Hartford, Connecticut for the processing and distribution of steam for heating and chilled water for cooling. HSC also owns a 7.5-megawatt cogeneration facility which is located on the campus of Hartford Hospital and supplies steam for heating and electricity for power to Hartford Hospital. This facility was financed with a long-term secured term note.

The equipment rentals division of TEN owns water heaters and conversion burners which it leases to its customers in the residential market.

Adriaen's Landing

The Company has been approached by local businesses and government agencies regarding the development of a stadium and convention center along with hotel, retail and recreational facilities. The proposed development, known as Adriaen's Landing, would be built in the area of the Company's headquarters and operating center. The Company, in order to accommodate the development as it has been proposed, would be required to relocate its administration and operating facilities and potentially a portion of HSC's steam and chilled water production facilities. Discussions are now under way with the developers in order to accomplish this at no cost to the Company or its customers. The area of development, which includes Company property, may contain hazardous materials that the project participants will be required to address (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations").

ITEM 3. LEGAL PROCEEDINGS

In November 1995, certain Connecticut plumbers and HVAC contractors, including Connecticut Cooling Total Air, Inc. and two trade associations, filed three class action suits against CNG and the State's two other LDCs claiming that the LDCs, including CNG, had performed gas service work in customers' homes without proper contractors' licenses from the State of Connecticut. The suits claimed that CNG violated the Connecticut Unfair Trade Practices Act, committed tortious interference with contract and/or business expectancies, violated the Connecticut Antitrust Act, and conspired with the other two gas companies to violate the license statute.

During fiscal 1999, CNG reached a settlement which resolves all three actions with no material impact to its results of operations or financial condition.

The Company is not a party to any other litigation other than ordinary routine litigation incident to the operations of the Company or its subsidiaries. In the opinion of management, the resolution of such litigation will not have a material adverse effect on the Company's financial condition or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the last quarter of the fiscal year ending September 30, 1999.

EXECUTIVE OFFICERS OF THE REGISTRANT

All executive officers' terms of office are one year.

Arthur C. Marquardt		Age - 52
Chairman, President and Chief Executive Officer
Business experience:
1999 - Present	Chairman, President and Chief Executive Officer
1998 - 1999	President and Chief Executive Officer
1997 - 1998	President and Chief Operating Officer
1996 - 1997	President and Chief Operating Officer, Connecticut Natural Gas Corporation
1992 - 1996	Senior Vice President - Gas Business Unit, Long Island Lighting Company

James P. Bolduc		Age - 50
Executive Vice President and Chief Financial Officer
Business experience:
1997 - Present	Executive Vice President and Chief Financial Officer
1996 - 1997	Executive Vice President and Chief Financial Officer, Connecticut Natural Gas Corporation
1993 - 1996	Senior Vice President - Financial Services and Chief Financial Officer, Connecticut Natural Gas Corporation

James P. Laurito		Age - 43
President, The Energy Network, Inc.
Business experience:
1998 - Present	President, The Energy Network, Inc.
1997 - 1998	Vice President Business Development, The Energy Network, Inc.
1996 - 1997	President and Chief Executive Officer, Consumers Applied Technologies, Inc.
1995 - 1996	President, Cochrane Environmental Systems, Inc.

Anthony C. Mirabella		Age - 59
Senior Vice President - District Heating and Cooling, The Energy Network, Inc.
Business experience:
1998 - Present	Senior Vice President - District Heating and Cooling, The Energy Network, Inc.
1997 - 1998	Senior Vice President - Operations and Chief Engineer, Connecticut Natural Gas Corporation
1993 - 1997	Vice President - Operations and Chief Engineer, Connecticut Natural Gas Corporation

Reginald L. Babcock		Age - 48
Vice President, General Counsel and Secretary
Business experience:
1997 - Present	Vice President, General Counsel and Secretary
1996 - 1997	Vice President - Administrative Services and General Counsel and Secretary, Connecticut Natural Gas Corporation
1993 - 1996	Vice President - Corporate Services and General Counsel and Secretary, Connecticut Natural Gas Corporation

Andrew H. Johnson		Age - 51
Treasurer and Chief Accounting Officer
Business experience:
1997 - Present	Treasurer and Chief Accounting Officer
1993 - Present	Treasurer and Chief Accounting Officer, Connecticut Natural Gas Corporation

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS

The Company's common stock is listed on the New York Stock Exchange. The high and low sales prices for each quarterly period during the years ended September 30, 1999 and 1998 were as presented in the table below. These prices are based on the New York Stock Exchange NYSE Net stock quotation service.

QUARTERLY COMMON STOCK PRICES
	1999		1998
Fiscal Year	High	Low		High	Low
First Quarter	26 5/16	22 5/8		26 1/2	22 3/4
Second Quarter	26 3/8	22 1/4		26 3/4	23 3/8
Third Quarter	36 3/4	22 1/8		25 15/16	21 15/16
Fourth Quarter	37 3/16	34 1/4		24 1/2	22 3/8

There were 6,627 record holders of the Company's common stock at November 1, 1999.

Cash dividends are declared on the Company's common stock on a quarterly basis out of funds legally available therefor. The total amount of dividends declared was $1.04 per share in 1999 and $1.00 per share in 1998. Funds utilized by the Company for the payment of dividends are received as dividends from its subsidiaries, CNG and TEN. Under the most restrictive terms of the open-end indenture securing CNG's first mortgage bonds, as amended, retained earnings of $26,700,000 were available for CNG to pay dividends at September 30, 1999. There are also certain restrictions relating to CNG's classes of preferred stock as to which dividends and sinking fund obligations must be paid prior to the payment of common stock dividends.

Under a provision of a Forward Equity Purchase Agreement between CTG and TEN, dated October 1, 1997, and amended October 14, 1998, the Company is restricted from declaring or paying any dividends or distributions to holders of its common stock if any amounts due and payable under this agreement are in arrears (See Note 5 to the Financial Statements in Part II, Item 8). There are no other restrictions on the Company's present or future ability to pay such dividends. The Company expects that future cash for dividends will be available.

ITEM 6. SELECTED FINANCIAL DATA

FIVE-YEAR SUMMARY OF CONSOLIDATED OPERATIONS
(Dollars in Thousands Except for Per Share Earnings and Dividends)

	1999	1998	1997	1996	1995
Operating revenues	$286,749	$282,748	$305,295	$315,103	$274,935
Net income applicable to common stock	$ 13,563	$ 15,135	$ 17,013	$ 18,932	$ 16,957
Earnings per share (1)	$ 1.57	$ 1.71	$ 1.60	$ 1.87	$ 1.71
Total assets	$466,261	$459,181	$444,373	$443,574	$437,372
Long-term obligations	$214,769	$215,852	$126,787	$136,432	$150,390
Cash dividends declared per common share	$ 1.04	$ 1.00	$ 1.52	$ 1.50	$ 1.48
Dividend payout ratio	66.2%	58.5%	95.0%	80.2%	86.6%
P/E ratio	23	14	14	13	13
Market price as a % of book value - year-end	239.7%	170.2%	145.9%	152.9%	146.8%

(Certain amounts for 1998 and prior years have been reclassified to conform with 1999 classifications.)

(1) Net income and Earnings per share for 1999 and 1998 reflect the impact of the October, 1997 stock repurchase and the related assumption of additional debt (See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8. Financial Statements and Supplementary Data, Notes to the Financial Statements, herein).

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, SEPTEMBER 30, 1999

(Dollars in Thousands Except for Per Share Data)

CTG Resources, Inc. (the "Company" or "CTG") is a holding company and parent of the Connecticut Natural Gas Corporation ("CNG") and The Energy Network, Inc. ("TEN"). CNG is an energy provider engaged in the regulated distribution, sale and transportation of natural gas. TEN holds and operates, through divisions or wholly-owned subsidiaries, CTG's unregulated, diversified businesses which are primarily engaged in district heating and cooling ("DHC") and also include the Company's equity investments in two partnerships, the Iroquois Gas Transmission System Limited Partnership ("Iroquois") and the Downtown Cogeneration Associates Limited Partnership ("DCA").

RESULTS OF OPERATIONS

Consolidated net income applicable to common stock and basic earnings per share for the fiscal years ended September 30, were $13,563 ($1.57) for 1999, $15,135 ($1.71) for 1998 and $17,013 ($1.60) for 1997. A charge of $(.34) per share, net of income taxes, for merger-related costs is included in fiscal 1999 earnings per share. As a result of a first quarter stock repurchase, fiscal 1998 earnings per share were impacted by both the lower weighted average shares outstanding and the cost of the debt which financed the transaction. Together these factors provided net benefits to earnings per share of approximately $.11 for fiscal 1998, as compared to fiscal 1997 earnings.

Gas Operating Margin

Gas operating margin is equal to gas revenues less the cost of gas and Connecticut Gross Earnings Tax, which is applied to revenues. The following table presents consolidated gas revenues, gas operating margin, heating degree days (a measure of temperature) and gas deliveries for fiscal 1999, 1998 and 1997, respectively:

	1999	1998	1997
Consolidated Gas Revenues	$262,060	$262,446	$283,324
Gas Operating Margin	$110,359	$109,241	$112,446
Heating Degree Days (30-Year Normal - 6,020)	5,557	5,490	6,002
Commodity and Transportation Volumes (mmcf)
Firm Gas Sales	19,594	20,577	22,354
Interruptible Gas Sales	8,984	9,079	9,573
Off-System Gas Sales	14,128	11,459	10,164
Transportation Services	5,558	4,376	4,131
Total	48,264	45,491	46,222

The Company's customers' greatest use of energy during the year is in the winter. Changes in weather patterns from year to year impact how much of the Company's overall operating margin is contributed by each of the different customer classes, based on the mix of the sales. The Company's firm customers require less gas in warmer winters. Therefore, more of the Company's gas supplies are available for sale to the other customer groups.

In the chart above, the higher number of degree days shown for fiscal 1999 over fiscal 1998 is an indicator of colder weather. The expected result would be higher gas revenues, firm sales and operating margin. However, the Company's service area has experienced milder winters in recent years, and the year-to-year 1999 to 1998 difference, as measured by degree days, is small. This milder winter heating season weather is the principal reason why gas operating margin is not significantly higher in fiscal 1999 as compared to 1998. Although overall gas throughput is higher in fiscal 1999, the milder winter weather resulted in fewer sales of gas to the higher-margin firm class of customers for winter heating. However, the continued increase in higher-use heating customers, described below, and higher interruptible margins, resulting from a decline in gas costs, offset some of the effect of the warmer winter and contributed to the increase in overall operating margin in fiscal 1999. A percentage of interruptible sales margin earned above a target level prescribed by the DPUC is refunded to firm ratepayers. A management fee earned on behalf of a gas marketing company, recorded in the third quarter of fiscal 1999, also added to operating margin.

During the fiscal 1998 heating season, the Company's service area also experienced warmer winter weather, as compared to the prior year. This warmer weather resulted in lower use per customer and reduced sales and operating margin, especially from the firm class of customers.

The Company's regulated gas business continues to add customers from year to year and to realize additional firm gas sales from customers who add gas heating to their existing cooking and hot water service. Firm sales historically follow variations in winter weather. Thus, the full opportunity to benefit operating margin from additional customers and load is not realized in a fiscal year that is characterized by a warm winter. Some commercial and industrial customers have migrated to transportation rates. This will not impact operating margin, because transportation tariffs are designed to earn the same margin as the sale and delivery of natural gas.

In fiscal 1999, the Company again recorded higher off-system sales, as compared to the prior year. This consistent increase in off-system sales reflects the Company's marketing efforts, the signing of additional volumes and off-system sales contracts prior to the start of the heating season, and the availability of natural gas in the winter heating season.

The Company's off-system sales program allows the Company to make short-term gas sales and provide transportation services by contract with customers nationwide. These sales contribute the smallest per-unit operating margin. The significance of the off-system sales program is that the Company acts as an independent marketer of natural gas and transportation, enabling the Company to generate operating margin from a source not restricted by the capacity of the Company's own distribution system or curtailment limitations driven by system demand. A significant portion of margin earned on off-system sales is refunded to firm ratepayers, as directed by the DPUC.

Transportation services are sold under per-unit operating margins comparable to those earned on similar gas sales. Therefore, the Company is financially indifferent as to whether it transports gas or sells gas and transportation together.

Weather Stabilization Insurance Program

In September 1998, CNG purchased an insurance product for the fiscal 1999 winter heating season (November through March). The program was designed to offset some of the effects of extreme winter weather variations on earnings. This program helps to offset a portion of lost margins and thus provides the Company with additional earnings in the event of significantly warmer winter weather in return for an insurance premium. In the event of significantly colder winter weather, the insurance carrier bills the Company for an additional premium amount. In the winter heating season of fiscal 1999, the Company realized a net benefit from this program of approximately $577, net of income taxes, equivalent to $.07 per share. In September 1999, CNG purchased a similar insurance product for the fiscal 2000 heating season.

Operating and Maintenance Expenses

Fiscal 1999 Operations and Maintenance ("O&M") expenses reflect additional costs related to expanded DHC operations. In the first quarter of fiscal 1999, the Company began to record operating expenses for a cogeneration plant which was purchased by TEN in June 1998, subsequently repowered, and brought on line in December 1998 to serve a large local hospital complex (See "Earnings from Diversified Operations," below). Otherwise, between fiscal 1999 and 1998, variations in several other expense categories offset each other.

In fiscal 1999, lower O&M expenses reflect the benefit of the weather stabilization insurance program described above. Significant decreases in O&M expenses were also recorded in the categories of employee benefits and pension related expenses, computer-related services, and outside professional and consulting services. O&M expenses are also lower because of an increase in customer service fees generated from CNG's service contract program. The principal increases that partially offset these benefits to O&M expenses were for compensation and bad debts.

Employee benefits costs declined because of lower medical claims and a premium refund. Pension costs reflect lower expenses as a result of favorable plan performance and changes in actuarial assumptions in the plans. Computer related costs reflect changes to equipment lease contracts. Changes in levels of expenses for outside services reflect costs incurred for legal and consulting services. A higher benefit to O&M expenses from customer service fees was generated by a growing natural gas equipment service contract program. Variations in levels of bad debt expenses typically relate to customers' natural gas bills and actual collection levels. Compensation expenses reflect increases in wages and salaries.

Consolidated O&M expenses were lower in fiscal 1998 as compared to fiscal 1997. A significant factor is the absence in fiscal 1998 of expenses related to TEN's heating, ventilation and air conditioning ("HVAC") operations. Those assets were sold and the HVAC operations ceased in fiscal 1998 (See "Earnings from Diversified Operations," below.). In the regulated operations, lower costs were incurred in fiscal 1998 for labor, employee benefits, regulatory expenses, professional and consulting services, workers' compensation insurance and corporate insurance reserves. Higher expenses were recorded for pension-related costs, bad debts and computer-related services.

In fiscal 1998, Corporate insurance costs declined because of lower actual and projected claims realized as a result of the Company's aggressive management of claims. Pension costs reflected a reduction in payments because of fewer claims, offset by higher costs related to changes in actuarial assumptions in the plans. Employee benefits expenses reflected an increase in medical claims, but reduced costs resulting from changes in benefit programs offset some of this increase.

Year to year increases in depreciation result from annual additions to depreciable plant and reflect the Company's continued growth.

Income Taxes

The year-to-year variation in income taxes is primarily a function of the effective tax rate and taxable income. Overall, the effective tax rate is higher in fiscal 1999 as compared to fiscal 1998. The most significant reasons for this increase are non-deductible merger-related costs, and changes to the the Company's income tax reserves and higher income taxes recorded for plant-related depreciation.

Lower taxable income and the benefits of reductions to the Company's income tax reserves are the principal reasons for lower income taxes in fiscal 1998. Other contributing factors include a lower State of Connecticut corporate income tax rate and the Connecticut Fixed Capital Asset Tax Credit.

Other Income/(Deductions)

Changes in the Company's equity in partnership earnings are discussed in "Earnings from Diversified Businesses."

Merger-related costs incurred to date of $3,204, appear as a separate line item in this section of the statements of income. Income tax benefits of $269, related to some of these costs, are included in the income taxes caption in Other Income/(Deductions). The Company expects to incur additional merger-related costs estimated at $2,500. These costs will be expensed in fiscal 2000 as they are incurred.

A positive benefit to other income/(deductions) in fiscal 1999 reflects the absence of costs recorded in fiscal 1998 related to the closing of certain diversified operations and higher fiscal 1999 interest income from the investment of cash and the investment of trust funds. These benefits are partially offset by increased costs related to converting CNG's regulated propane service program to natural gas.

The other income/(deductions) amount reported for fiscal 1998 includes $1,012 of after-tax costs incurred by TEN related to the closing of certain diversified operations, as described below in the section "Earnings from Diversified Businesses." Other income in fiscal 1998 also reflects the net effect of lower income from investments of available cash more than offset by the benefits of lower promotional and advertising expenses, lower life insurance premiums and the absence of fiscal 1997 costs associated with the termination of the Company's regulated propane service program.

Interest and Debt Expense

Higher interest and debt expense has been recorded in both fiscal 1999 and 1998 primarily because of the additional long-term debt issued during the first quarter of both fiscal years. In fiscal 1999, long-term debt was issued to replace outstanding short-term borrowings. In fiscal 1998, long-term debt was issued to finance the stock repurchase program (See "Financing Activities," below).

Other interest relates primarily to interest on short-term borrowings and interest associated with pipeline refunds and deferred gas costs. Short-term interest fluctuates as a result of changes in interest rates, short-term cash requirements and conversions to long-term debt.

Lower fiscal 1999 short-term interest reflects lower levels of borrowings. Early fiscal 1999 issues of long-term debt refinanced outstanding borrowings. Conversely, in addition to seasonal working capital requirements, short-term borrowings in fiscal 1998 were used to temporarily finance a portion of the stock repurchase and the acquisition of a cogeneration facility (See "Investing Activities", below).

Earnings from Diversified Businesses

The Company's diversified businesses are all unregulated and include TEN and TEN's wholly-owned subsidiaries: The Hartford Steam Company ("HSC"), ENI Gas Services, TEN Gas Services, and TEN Transmission Company ("TEN Transmission"). TEN and HSC provide DHC services to many buildings and complexes in the south-end and downtown neighborhoods of Hartford, Connecticut. TEN also holds a fifty percent interest in the Downtown Cogeneration Associates Limited Partnership ("DCA"), which owns and operates a 4.2-megawatt cogeneration facility in downtown Hartford, Connecticut. TEN Transmission owns the Company's share of its investment in the Iroquois pipeline. Although TEN Transmission is not regulated, Iroquois is regulated by the Federal Energy Regulatory Commission ("FERC"). Refer to Note 1 to the Financial Statements for additional information regarding these investments. ENI Gas Services and TEN Gas Services together own 100% of KBC Energy Services ("KBC") and had no significant activities in fiscal 1999.

The Company's diversified, unregulated businesses contributed earnings per share of $.23 in fiscal 1999, $.08 in fiscal 1998, and $.25 in fiscal 1997. Unregulated earnings are higher in fiscal 1999, as compared to 1998, primarily because of the absence of an $.11 per share loss recorded in fiscal 1998 for expenses related to the winddown of KBC, described below. Fiscal 1999 results include additional interest expense related to additional long-term debt issued in the first quarter, a full year of interest related to fiscal 1998 issues of long-term debt, and costs related to new business development activities. These additional expenses were partially offset by a reduction in commitment fees, as a result of the consolidation of loans and reduced credit lines, and a reimbursement of legal fees.

In June 1998 the diversified operations purchased a cogeneration facility which supplies Hartford Hospital, a major local hospital, with steam and electricity and sells electricity to the local electric utility. (See "Investing Activities," below.) TEN's fiscal 1999 earnings reflect new sales of electricity and steam from this facility, which came on line in December 1998.

Fiscal 1999 earnings also reflect the benefits of higher steam sales for heating and lower DHC energy and production costs. TEN continues to review its pricing structure so that it meets current market demands as energy deregulation and changes in energy costs move forward.

TEN's earnings from its equity interest in two partnerships are lower in fiscal 1999. The majority of these earnings are from Iroquois, and in August 1998 Iroquois' approved tariffs allowed by the FERC were reduced, resulting in lower income.

Earnings from the diversified businesses in fiscal 1998 reflect the measures that have been taken in the last few years to position this area of the Company for future growth and development. Several significant factors impacting TEN's earnings have occurred in fiscal 1998. The assets of TEN's wholly-owned HVAC subsidiary, ENServe, were sold and the subsequent winding down of this operation was completed. As a result, TEN's fiscal 1998 earnings no longer reflected the losses of ENServe that had been recorded in fiscal 1997, equivalent to $(.07) per share. During the second quarter of fiscal 1998, TEN assumed the full ownership of KBC and began the wind down of its operations. The Company's share of KBC's operating losses for fiscal 1998 was approximately $(.11) per share.

Fiscal 1998 earnings from ongoing operations for TEN included the benefit of lower energy and production costs for district heating and cooling, the result of lower energy prices, and higher chilled water sales for cooling because of the warmer summer weather. These benefits were partially offset by the effects of lower steam and hot water sales during the warmer winter. The cost of the added debt issued by TEN to finance the October 1997 stock repurchase reduced TEN's fiscal 1998 earnings by ($.19) per share (See "Investing Activities," below).

LIQUIDITY AND CAPITAL RESOURCES

Natural gas sales in New England are seasonal, and the Company's cash flows vary accordingly because regulated natural gas operations are the principal segment of the Company's business. The Company manages its changes in cash requirements, primarily to fund gas purchases, construction expenditures and customer accounts receivable, by using cash flows generated from operations supplemented by short-term financing from lines of credit.

The diversified operations' cash resources and requirements are also seasonal. Cash requirements have generally been satisfied with cash flows from operations together with short-term financing from lines of credit.

Proceeds from long-term debt issued in fiscal 1999 were used to refinance short-term debt, some of which had been used to finance the June 1998 acquisition of the Hartford Hospital cogeneration facilities. Long-term debt issued in fiscal 1998 was used to finance a stock repurchase and to retire existing short-term debt.

Cash Flows from Operating Activities

The cost of gas and volumes of gas sold are the principal factors which influence cash flows from operations from year to year. The price of natural gas impacts the amount of purchased gas costs subject to refund or recovery through the Purchased Gas Adjustment provisions ("PGA") of the Company's tariffs.

In fiscal 1999, cash from operations and available credit lines provided needed working capital and funded dividends and construction expenditures. In fiscal 1998, the Company relied on cash from operations and its available lines of credit to satisfy cash requirements for working capital, dividends, asset acquisitions and construction expenditures.

Investing Activities

Construction expenditures in fiscal 1999, 1998 and 1997 were $24,992, $22,435 and $24,593, respectively. Capital spending for the fiscal year ending September 30, 2000 is estimated to be $26,300 for the regulated operations. The diversified businesses are projecting to expend $10,900 in fiscal 2000, primarily to fund the expansion of the DHC system to support service to The Learning Corridor, as described below, and to provide for additional chilled water storage. CTG's construction program is subject to continuous review and modification, and actual expenditures may vary from these estimates. The Company plans to fund capital expenditures and other commitments through a combination of sources.

In June 1998, TEN acquired the assets of a 16-megawatt capacity cogeneration facility which supplies Hartford Hospital with steam and electricity. The purchase price and cost to repower this facility was approximately $17,000 and was financed through existing lines of credit. This was later refinanced with the October 1998 issue of $15,000 of long-term debt (See "Financing Activities," below). This investment is directly linked with the diversified operations' growth strategy of focusing on the ownership and operation of energy facility assets.

In April 1999, TEN executed a twenty-five year agreement with the City of Hartford to supply hot and chilled water to several facilities referred to collectively as The Learning Corridor project in Hartford's south-end. The Learning Corridor is an $86,000,000 educational campus that forms the centerpiece of the Trinity College/Southside Institutions Neighborhood Alliance ("SINA") neighborhood revitalization initiative. Energy to serve these customers will be produced at TEN's cogeneration facility located at Hartford Hospital. Construction of necessary pipeline and other facilities began in the third quarter of fiscal 1999. Service to The Learning Corridor is expected to begin in early 2000. The cost of this expansion of TEN's DHC system is estimated to be approximately $6,000, to be expended between fiscal 1999 and 2000. Approximately $700 was spent in fiscal 1999.

TEN continues to investigate other energy-related systems and other investment opportunities which are aligned with its overall capital asset investment strategy. Additional borrowings and/or funds may be required to realize such transactions. The Company has been working with its banks and other sources in order to be prepared if such an opportunity arises.

The Energy Network Alliance

In October 1998, TEN entered into a marketing Alliance with Pratt & Whitney Canada, Inc., Carrier Corporation and Oxford Technologies, Inc. (the "Alliance") to provide energy for heating, cooling and electricity to large commercial, industrial and institutional facilities by combining cogeneration and district energy. As the lead role in this Alliance, TEN will own and operate the district energy plants which will be installed on-site at each facility and equipped with state-of-the-art energy systems provided by the other members of the Alliance. A number of opportunities are currently being pursued by Alliance members. TEN's participation in this Alliance is in keeping with TEN's strategic plan to focus its investments in fixed assets in capital intensive businesses.

Adriaen's Landing

A relocation would have a significant impact on the Company's business and operations during the transition. The Company believes that the Adriaen's Landing project would be beneficial to the Greater Hartford area and provide an opportunity for new customers to the Company. The Company has indicated its willingness to relocate provided that the relocation is accomplished in a way that will not materially disadvantage the Company or its customers. However, the State's final plans for development of this site have not been completed, and, largely for this reason, the Company cannot assess the impact of future developments, including any arrangement pertaining to the funding of relocation and any related land preparation or remediation costs.

The Adriaen's Landing site, including the Company's property, contains contaminants, some of which originated during the Company's former gas manufacturing activities. The Company believes that if the development activities trigger the remediation of contamination on the Company's property, the cost of the remediation should be regarded as part of the project development costs. Prior decisions of the DPUC indicate that the costs of remediating property that is found to have been contaminated by a gas utility's former gas manufacturing activities are generally recoverable from the utility's customers.

Financing Activities

The Company uses short-term debt to finance working capital requirements. Capital expenditures are also temporarily funded with short-term debt. The Company raises short-term funds through the use of available bank lines of credit and revolving credit agreements (See Note 7 to the Financial Statements). Long-term debt and equity issues are used to reduce outstanding short-term debt and to permanently finance completed construction. In October 1998, the Company refinanced $30,800 of short-term borrowings with long-term debt.

The Company's 9.16%, Series AA First Mortgage Bonds are subject to redemption by sinking fund scheduled at $2,500 per year. In October 1998, the Company exercised its option to redeem $2,500 in principal of its 9.16%, Series AA First Mortgage Bonds in addition to the scheduled redemption of $2,500, for a total of $5,000. The Company also exercised its option to redeem an additional $2,000 of principal together with the scheduled payment amount due on October 1, 1999, for a total of $4,500. This increased the Company's current portion of long-term debt by $2,000 at September 30, 1999.

In October 1998, the Company issued a total of $20,000 of Medium Term Notes ("MTNs") at 6.04%, due 2008. These MTNs are unsecured and have no call provisions or sinking fund requirements. The proceeds were used primarily to refinance $15,800 of short-term debt that was outstanding at fiscal year-end 1998. The long-term debt amounts shown on the balance sheet and statement of capitalization at September 30, 1998 include $15,800 of these MTNs.

In October 1998, TEN issued $15,000 of Senior Secured Notes, due in 2010, at 6.9%. The full amount of the principal is due at maturity. A portion of the proceeds was used to repay short-term debt that was used to finance the purchase and repowering of the Hartford Hospital cogeneration facility (See "Investing Activities", above). The September 30, 1998 financial statements reflect the classification of the debt that was retired as a result of this refinancing as long-term debt.

In August 1998, the Company refinanced its outstanding $10,600 1986 and 1988 series of tax exempt, seven-day put, Industrial Revenue Variable Rate Demand Bonds ("IRBs") issued by the Connecticut Development Authority. The 1998 series of IRBs matures in 2025 and has no sinking fund requirements. The original IRBs financed TEN's Capitol Area district heating and cooling facilities in Hartford, Connecticut. At the same time, the Company replaced the letter of credit which supports these IRBs. The IRBs have been assigned the rating of A+/A-1 by Standard & Poor's.

In October 1997, TEN issued Senior Secured Notes for $45,000, due in 2009, at 6.99%. The principal will be retired through semi-annual payments of $2,500 beginning in 2001. The proceeds were used to repurchase approximately 2.0 million shares of CTG common stock.

In October 1997, the Company issued a total of $19,000 of MTNs due 2007. These MTNs are unsecured and have no call provisions or sinking fund requirements. The proceeds were used to refinance existing short-term debt. The face values and interest rates of these MTNs are:

Face Value	Interest Rate
$ 1,000	6.62%
$ 1,000	6.65%
$17,000	6.69%

The MTNs are rated at A3 by Moody's and A- by Standard and Poor's.

In March 1998, the Company renewed its $20,000 revolving credit agreement to 2001 with two subsequent one-year renewal options.

In February 1998, the Company replaced its expiring $9,000 bank line of credit with a seasonally adjusted $10,000 to $15,000 line of credit through February of 1999. In February 1999, the Company renewed this line of credit to February 2000.

In October 1997, TEN entered into a 364-day secured revolving credit agreement for $10,000 with a bank. In fiscal 1999 this agreement was renewed through September 1999, at which time it was extended into the first quarter of fiscal 2000 while arrangements for its renewal are in progress.

In October 1997, TEN entered into a three-year revolving credit agreement for $10,000 with a bank. The maximum borrowing amount is reduced by $500 on each fiscal quarter, beginning January 1, 1998.

Many of the Company's debt agreements require the maintenance of certain financial covenants. At September 30, 1999 the Company was in compliance with or had received a waiver with respect to these covenants and provisions.

Common Stock and Dividend Matters

On December 1, 1998, the Board of Directors of CTG Resources, Inc. declared a dividend distribution of one right (a "Right") for each share of Common Stock, without par value, of the Company (all such shares of common stock of the Company, collectively, the "Common Stock") outstanding at the close of business on December 18, 1998 (the "Record Date"), pursuant to the terms of a Rights Agreement, dated as of December 1, 1998 (the "Rights Agreement"), between the Company and ChaseMellon Shareholder Services, L.L.C., as Rights Agent. The Rights Agreement also provides, subject to specified exceptions and limitations, that shares of Common Stock issued or delivered by the Company (whether originally issued or delivered from the Company's treasury) after the Record Date will be entitled to and accompanied by Rights. The Rights are in all respects subject to and governed by the provisions of the Rights Agreement.

In February 1999, CTG's shareholders approved the CTG Resources, Inc. 1999 Stock Option Plan (the "Option Plan"). The Board of Directors adopted the plan in December 1998. The maximum number of shares that may be issued under the Option Plan is 500,000. In fiscal 1999, 64,600 options were granted under the Option Plan. These options vest over three years, beginning after the second year following their grant. The options are exercisable over ten years. The exercise price of the options is $23.125.

The Company follows the provisions of Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock Based Compensation" ("SFAS No. 123"), which requires the measurement of the fair value of stock options to be included in the statement of income or that proforma information related to the fair value be disclosed. The Company continues to account for stock based compensation under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and elects the disclosure-only alternative under SFAS No. 123. In fiscal 1999, the fair value of the stock options that would have been included in the statement of income under SFAS No. 123 was $65, equivalent to less than one cent per share after income taxes. The detailed proforma fair value and earnings per share information is disclosed in the Notes to the Financial Statements.

On October 30, 1997, through a tender offer made by TEN, the Company repurchased approximately 2.0 million shares of CTG common stock for approximately $53,000. TEN financed the purchase with a combination of cash, revolving bank debt and the issuance of Senior Secured Notes. The shares repurchased by TEN were transferred by the depositary directly to CTG. In connection with the repurchase, effective with the first quarter of fiscal 1998, CTG reduced its quarterly dividend on common stock from $0.38 ($1.52 annually) to $0.25 ($1.00 annually) per share.

In fiscal 1999, the Company declared a quarterly dividend of $0.26 ($1.04 annually) per share.

Under the most restrictive terms of the indenture securing the Company's First Mortgage Bonds, retained earnings of $26,700 are available for CNG to pay dividends at September 30, 1999. CTG's ability to pay dividends is not restricted by these terms. As a provision of CTG's Forward Equity Purchase Agreement with TEN, described below, CTG is restricted from declaring or paying any dividends or distributions to its holders of common stock if any amounts due and payable under this agreement are in arrears. Dividends paid on common and preferred stock in fiscal 1999 were $9,023. The preferred stock on the balance sheet is issued by CNG. CNG is prohibited from, among other things, paying dividends on common stock and purchasing, redeeming or retiring common stock, if dividends on preferred stock are in arrears.

Forward Equity Purchase Agreement

Other Tax Matters

The Company is subject to audit by State of Connecticut and federal authorities as it relates to income, sales, use and property tax returns filed. In addition, the Company has several ongoing issues related to the taxability of off-system gas sales by state taxing authorities. The Company believes that if amounts are required to be paid related to the off-system sales issues, a portion would be recoverable from ratepayers. These benefits had been previously flowed through to ratepayers. The ultimate resolution of these issues will be impacted by future negotiations with the State Department of Revenue Services and the DPUC. In the opinion of management, based upon current regulatory treatment, the ultimate resolution of these issues will not have a material impact on the Company's results of operations.

Competitive Environment

In recent years, the natural gas industry has undergone structural changes in response to Federal regulatory policy intended to increase competition. In 1992, the FERC issued Order 636, which required all interstate gas pipelines to provide "unbundled," or separate, gas transportation and storage services and to discontinue their bundled merchant sales operations, which included the gas acquisition function. The impact of the FERC Order 636 and the resulting deregulation of the gas industry have continued to heighten competition and have changed the nature of the Company's business.

At the local level, as a result of FERC Order 636 and Connecticut deregulation, the Company continues to face increasing competitive pressures as providers of gas seek to make sales to the Company's commercial and industrial customers. Similarly, the Company has offered firm transportation rate tariffs to nonresidential customers since April of 1996. The Company's transportation tariffs are designed to recover a margin on each transaction that is comparable to the margin that the Company would have received if it were making a system sale of natural gas.

The Company also competes with suppliers of oil, electricity and propane for cooking, heating, air conditioning and other purposes. Competition is greatest for the Company's large commercial and industrial customers who have the capability of using alternative fuels. The volatile effect of this price-sensitive load is somewhat overcome through the use of flexible rate schedules which allow gas pricing to meet alternative-fuel competition.

The diversified businesses own and operate district heating and cooling systems, collectively referred to as DHC, which distribute and sell steam, hot and chilled water to office complexes and other large buildings in the city of Hartford. The risk of competition to the DHC business from alternate energy types is diminished after a customer has made its commitment to DHC, because of the cost of the equipment necessary to utilize an alternative energy source. Similarly, the diversified businesses own and operate cogeneration facilities, which distribute thermal energy and electricity to hospitals, universities and other large commercial and industrial users.

Market Risk

The Company's exposure to market risk with respect to sales to firm customers comes primarily from changing natural gas prices. All of the Company's gas sales are at tariffs designed to fully recover the Company's cost of gas. The Company passes on to its firm customers changes in gas costs from those reflected in its tariffs under PGA provisions allowed by the DPUC. Interruptible and off-system sales are priced competitively at not less than the Company's cost of gas associated with those sales plus applicable taxes and a minimum margin. Some interruptible and off-system sales are made under fixed price sales contracts. For such sales, the Company secures its margin and protects against potential losses that could be caused by changes in gas prices by buying and storing natural gas for these contracts at a fixed price at the beginning of the contract period. Transportation services are also delivered at cost-based rates.

All but one issue of the Company's long-term debt are at fixed rates of interest. The $10,600 of Industrial Revenue Variable Rate Demand Bonds issued by TEN in October 1998 are at a variable rate of interest, which is set weekly.

Effects of Regulation

The Company's natural gas distribution business is subject to cost-of-service regulation by the DPUC. Based on current regulation and recent DPUC decisions, the Company believes that its use of regulatory accounting is appropriate and in accordance with the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (See Note 1 to the Financial Statements).

Regulatory Proceedings

CNG's last rate decision from the DPUC regarding base rates for natural gas service was issued in October 1995. By State statute, CNG was required to undergo a financial review with the DPUC beginning in October 1999. Rather than undergo such a statutory financial review, the Company made the decision to initiate a general rate hearing. CNG filed its general rate case on November 10, 1999, requesting an increase to its base revenues of $15,700 or 8.37 %. Key elements of the case include a higher return on equity, increased depreciation rates, lowering of the interruptible sales sharing mechanism, and introduction of a Rate Plan Alternative ("RPA"), a form of performance-based ratemaking methodology, to take effect following the Merger with Energy East. The RPA, which is proposed for a four-year term, includes performance measures, a higher return level, a sharing mechanism, and elimination of the Purchased Gas Adjustment clause. The RPA also includes a price cap for residential sales customers and flexible pricing options for nonresidential customers. The DPUC review process is ongoing. Rates that reflect the DPUC's decision should become effective by May 2000.

In a second phase of a regulatory review of natural gas deregulation which began in 1996, the DPUC is addressing the potential deregulation of the residential natural gas sales market in Connecticut and the future role of Connecticut's local natural gas distribution companies ("LDCs") in natural gas commodity sales. The DPUC has asked Connecticut LDCs to file information for the purpose of examining costs and developing appropriate natural gas sales and delivery rates for customers, to ensure that customers pay only for those services that they use. CNG filed its cost of service study with the DPUC in August 1999. Once the DPUC concludes generic proceedings it is expected to order each LDC to adjust its rates accordingly. The Company cannot predict the outcome of these proceedings.

Energy Contract Buyouts

TEN is a 50% partner in the DCA, a single purpose entity operating a 4.2-megawatt dual-fuel gas turbine generator which supplies electricity to a local electric utility under an Energy Purchase Agreement ("EPA") and steam to TEN's wholly-owned DHC subsidiary, HSC, under a Steam Supply Agreement ("SSA"). Currently, the electric utility and HSC are able to obtain energy at a lower cost than that which they pay under these agreements. For this reason, the electric utility and HSC have offered to buy out of their contracts with DCA. In March 1999, TEN and its partners in the DCA agreed to terminate both the EPA and SSA and negotiated terms for the buy out of each of these agreements, subject to DPUC approval for the electric utility. HSC's buy out of the SSA is estimated at $5,800.

The termination of the EPA and the SSA with DCA will occur upon the receipt of all necessary approvals for the electric utility. This is expected sometime in the year 2000. Until then, the DCA plant will continue to produce and sell steam and electricity under the SSA and EPA. HSC's termination of the SSA should benefit HSC and its customers by lower future production costs, but will reduce TEN's earnings from its partnership interest in DCA.

Environmental Matters

In the ordinary course of business, the Company may incur costs to clean up environmental contaminants related to natural gas activity. In those instances the Company expects that the remediation costs will be recoverable in rates. In August 1998, the Company received a notice of violation ("NOV") from the Connecticut Department of Environmental Protection ("DEP") regarding a number of areas on noncompliance. The Company submitted the required compliance report in September 1998. In April 1999, the DEP provided the Company with a draft Consent Order and informed the Company, by letter, that the Company's actions in response to the NOV were sufficient to correct the violations. The Company will also be required to pay a small penalty. The Company is working with the DEP to negotiate the Consent Order. The Company's written response to the DEP was submitted in October 1999. In the opinion of management, any existing environmental issues will not be significant to the future financial condition or results of operations of the Company.

Legal Proceedings

During fiscal 1999, CNG reached a settlement which resolves all three actions with no material impact to its results of operations or financial condition.

Year 2000 Compliance
CTG's State of Readiness

CTG has been preparing for Year 2000 ("Y2K") issues for a number of years. In 1989, CTG started the implementation of a Long-Range Information Systems Plan that addressed the replacement or redevelopment of all key CTG applications. All systems replaced or redeveloped since 1989 were required to be Y2K ready. In January 1998, a task force was organized to address all Y2K issues throughout CTG operations. The task force, headed by a Y2K compliance officer, is comprised of individuals from every business unit within CTG and is charged with assembling an inventory of date-impacted systems, identifying critical vendors and customers for readiness, prioritizing systems that are not ready, identifying critical dates for readiness, developing and executing test plans for all critical high priority application programs and embedded technology, developing contingency plans for vendors and systems that are not ready, and certifying that all systems and critical vendors are ready. All of the above-noted activities of the task force, with the exception of developing contingency plans and the system testing and certification phases, were completed during the last quarter of calendar year 1998. Initial contingency plans were completed during the first quarter of calendar 1999. These contingency plans will be finalized and updated during the balance of 1999 as needed.

The testing and certification of systems critical to CTG's operations were completed as of October 1, 1999.

In April 1998, a letter and survey were sent to CTG's vendors requesting a status of their Y2K efforts. In September 1998, a second letter and survey were sent to vendors who did not respond. For all critical vendors that do not respond or are not Y2K ready by the critical dates identified, CTG has made arrangements for alternate suppliers and service providers or developed contingency plans. This process will continue to take place during the balance of 1999. Parts and materials, which are critical

Although not all vendors have returned surveys, no third parties with which CTG has significant business relationships have disclosed problems which would indicate the potential for business interruptions.

During the quarter ending March 31, 1999, CTG received the results of reviews of its Y2K readiness by an outside legal firm and an outside consultant. During the quarter ending June 30, 1999, CTG received the results of a Y2K readiness review conducted by an outside consultant on behalf of the DPUC. CTG has integrated the recommendations received from these consultants into its Y2K readiness plan. The DPUC will continue to monitor CTG's Y2K readiness through the first quarter of the year 2000.

Costs to Address CTG's Year 2000 Issues
TG does not foresee incurring significant incremental costs, nor has it incurred significant outside consulting costs, relating to the Y2K issue. In accordance with the aforementioned Long-Range Information Systems Plan, CTG has been replacing or redeveloping its major computer applications over the past decade.

Risks of CTG's Year 2000 Issues

Although CTG is nearing the end of its project plan, CTG's current schedule is subject to change, depending on developments that may arise through unforeseen business circumstances. CTG also depends upon third parties, including customers, suppliers, government agencies and financial institutions, to reliably deliver products and services. Although CTG has not received responses from all third parties, CTG has not identified any known Y2K-related event, trend, demand, commitment, or uncertainty which would likely have a material effect on CTG's business, results of operations, liquidity, capital resources or financial condition. CTG has canvassed its critical vendors and no such vendor has indicated it will not be ready for the Y2K. CTG has assigned critical dates for vendors to show readiness throughout 1999. If a vendor does not show readiness by a specific date, CTG will either find a replacement vendor or develop a work-around.

Natural gas supply disruptions are not expected due to Y2K issues. CTG's gas supply is substantially dependent upon natural gas pipelines and other third party natural gas suppliers that it has no control over. None of the pipelines or suppliers has expressed expectations of gas supply delivery problems as a result of Y2K issues; therefore, CTG expects to be able to reliably supply customers. CTG has and will continue to work with pipelines and suppliers to examine their Y2K readiness.

CTG believes its planning has been adequate to secure Y2K readiness of critical systems and operations. CTG is not able to predict all the factors that could cause actual results to differ materially from its current expectations regarding its Y2K readiness. However, if CTG and/or third parties with which CTG has a significant business relationship fail to achieve Y2K readiness with respect to critical systems or operations, there could be a material adverse effect on CTG's results of operations and financial position.

CTG's Contingency Plans

CTG's contingency plans include selecting alternate vendors that are Y2K ready, using back-up systems which do not rely on computers, and obtaining and stocking critical parts and materials. Critical dates for readiness have been established for systems and vendors utilized throughout CTG. These critical dates have been established in order to allow sufficient time for CTG to either remediate any date-sensitive features in existing computer software and applications critical to CTG's business or to acquire services and products from alternate providers which are Y2K ready. Contingency planning is an ongoing process and will continue throughout 1999.

CTG has been an active participant at various Y2K town meetings around its service territory and is in the process of planning further Y2K communications to its customers and the general public during the remainder of 1999.

NEW ACCOUNTING STANDARD

In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). This statement establishes accounting and reporting standards for derivative instruments and for hedging activities. In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," to amend the implementation date of SFAS No. 133. Adoption of SFAS No. 133 is now required for the Company beginning with the first quarter of fiscal 2001. The Company is aware of certain provisions which may impact the natural gas industry but has not yet reviewed these provisions in detail against its existing accounting practices and disclosures. At this time the Company cannot predict what impact, if any, the adoption of SFAS No. 133 will have on its financial condition or results of operations.

INFLATION AND CHANGING PRICES

Inflation impacts the prices the Company must pay for operating and maintenance expenses and construction costs. The Company's rate schedules for natural gas and DHC sales include provisions that permit changes in gas costs and service costs, respectively, to be passed on to customers. The Company attempts to minimize the effects of inflation on other costs through cost control, productivity improvements and regulatory actions where appropriate.

FORWARD LOOKING INFORMATION

This report and other Company reports, including filings with the Securities and Exchange Commission, press releases and oral statements, contain forward looking statements. Such statements include but are not limited to disclosures about Year 2000 compliance, the Merger with Energy East, Adriaen's Landing, the Weather Stabilization Program, changes in operating and maintenance expenses, future construction expenditures, diversified operations growth strategy, anticipated earnings from a newly acquired cogeneration facility, a Forward Equity Purchase Agreement, state and Federal tax audits, the Company's competitive environment, regulatory proceedings regarding further state deregulation of the natural gas industry, environmental matters, legal proceedings, the Energy Network Alliance, and New Accounting Standards.

Forward looking statements are made based upon management's expectations and beliefs concerning future developments and their potential effect upon the Company. The Company cautions that, while it believes such statements to be reasonable and makes them in good faith, actual results almost always vary, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Investors should be aware of important factors that could have a material impact on future results. These factors include, but are not limited to, weather, the regulatory environment, the outcome of state and federal regulatory proceedings, legislative and judicial developments which affect the Company or significant groups of its customers, economic conditions in the Company's service territory, fluctuations in energy-related commodity prices, customer conservation efforts, financial market conditions, interest rate fluctuations, customers' preferences, unforeseen competition, and other uncertainties, all of which are difficult to predict and beyond the control of the Company.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item regarding quantitative and qualitative disclosures about market risk pursuant to Item 305 of Regulation S-K is contained in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of this report, in the section titled "Market Risk" under "Liquidity and Capital Resources." This information is hereby incorporated by reference.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and The Board of Directors of CTG Resources, Inc.:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of CTG Resources, Inc. (a Connecticut Corporation) and subsidiaries as of September 30, 1999 and 1998, and the related consolidated statements of income, common stock equity and cash flows for each of the three years in the period ended September 30, 1999. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of CTG Resources, Inc. and subsidiaries as of September 30, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1999, in conformity with generally accepted accounting principles.

Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the schedule index is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.

S/ Arthur Andersen LLP
(ARTHUR ANDERSEN LLP)

Hartford, Connecticut
October 26, 1999

Consolidated Balance Sheets
September 30, 1999 and 1998
(Dollars in Thousands)

Assets	1999	1998

Plant and Equipment:
Plant in service	$ 532,277	$ 510,542
Construction work in progress	1,654	3,647
	533,931	514,189
Less-Allowance for depreciation	192,751	176,173
	341,180	338,016
Investments, at equity	12,449	11,821

Current Assets:
Cash and cash equivalents	15,097	1,264
Accounts and notes receivable (less allowance for
doubtful accounts of $4,285 in 1999 and $3,283 in 1998)	30,846	31,513
Accrued utility revenue	3,263	3,789
Inventories	21,294	17,852
Prepaid expenses	7,449	11,707
Total Current Assets	77,949	66,125

Other Assets:
Unrecovered future taxes	5,322	10,734
Other assets	29,361	32,485
Total Other Assets	34,683	43,219
	$ 466,261	$ 459,181

Capitalization and Liabilities

Capitalization (see accompanying statements):
Common stock equity	$ 128,048	$ 123,397
Preferred stock, not subject to mandatory redemption	862	879
Long-term debt	214,769	215,852
	343,679	340,128
Current Liabilities:
Current portion of long-term debt	5,283	5,733
Notes payable	-	2,000
Accounts payable and accrued expenses	33,017	30,813
Refundable purchased gas costs	2,782	1,640
Accrued taxes	401	707
Accrued interest	5,032	4,317
Total Current Liabilities	46,515	45,210

Deferred Credits:
Deferred income taxes	55,444	50,175
Unfunded deferred income taxes	5,322	10,734
Investment tax credits	2,541	2,761
Refundable taxes	5,311	4,252
Other	7,449	5,921
Total Deferred Credits	76,067	73,843
Commitments and Contingencies
	$ 466,261	$ 459,181

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Income
For the Years Ended September 30, 1999, 1998 and 1997
(Dollars in Thousands Except for Per Share Data)

	1999	1998	1997

Operating Revenues	$ 286,749	$ 282,748	$ 305,295
Less: Cost of energy	151,098	150,685	166,785
State gross revenues tax	9,262	9,660	11,107
Operating Margin	126,389	122,403	127,403

Operating Expenses:
Operations	46,547	45,623	48,241
Maintenance	7,575	8,361	8,682
Depreciation and amortization	20,233	19,305	18,184
Income taxes	14,152	12,210	16,959
Local property taxes	5,277	5,216	5,323
Other taxes	2,220	2,233	2,400
	96,004	92,948	99,789
Operating Income	30,385	29,455	27,614

Other Income/(Deductions):
Allowance for equity funds used
during construction	78	61	125
Equity in partnership earnings	2,088	3,271	2,910
Other income/(deductions)	913	(1,120)	(68)
Merger-related costs	(3,204)	-	-
Income taxes	(670)	(856)	(665)
	(795)	1,356	2,302
Income Before Interest Charges	29,590	30,811	29,916

Interest and Debt Expense, net:
Interest on long-term debt	14,807	13,720	11,345
Other interest	815	1,463	1,200
Allowance for borrowed funds used
during construction	(52)	(41)	(84)
Amortization of debt expense	396	473	380
	15,966	15,615	12,841
Net Income	13,624	15,196	17,075
Less-Dividends on Preferred Stock	61	61	62

Net Income Applicable to Common Stock	$ 13,563	$ 15,135	$ 17,013

Average Common Shares Outstanding:
Basic	8,613,455	8,871,349	10,632,001
Diluted	8,656,872	8,922,965	10,683,759

Income Per Average Share of Common Stock:
Basic	$ 1.57	$ 1.71	$ 1.60
Diluted	$ 1.57	$ 1.70	$ 1.59

Dividend Per Share of Common Stock	$ 1.04	$ 1.00	$ 1.52

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Cash Flows
For the Years Ended September 30, 1999, 1998 and 1997
(Dollars in Thousands)

	1999	1998	1997
Cash Flows from Operating Activities:
Net Income	$ 13,624	$ 15,196	$ 17,075

Adjustments to reconcile income to net cash:
Depreciation and amortization	20,845	20,628	18,098
Provision for uncollectible accounts	5,270	5,044	3,855
Deferred income taxes, net	6,108	6,414	4,115
Equity in partnership earnings	(2,088)	(3,271)	(2,910)

Changes in assets and liabilities:
Accounts receivable	(4,172)	(5,410)	(3,873)
Accrued utility revenue	526	835	(444)
Inventories	(3,442)	(268)	(1,616)
Purchased gas costs	1,142	(3,074)	(1,298)
Prepaid expenses	4,258	(2,804)	2,017
Accounts payable and accrued expenses	2,613	(4,823)	(1,682)
Other assets/liabilities	3,825	(1,376)	(3,783)
Total adjustments	34,885	11,895	12,479
Net cash provided by operating activities	48,509	27,091	29,554

Cash Flows from Investing Activities:
Capital expenditures	(24,992)	(22,435)	(24,593)
Purchase of Cogeneration Assets	-	(17,067)	-
Cash distributions received from investments	1,461	2,442	1,761
Other investing activities, net	1,594	901	54
Net cash used in investing activities	(21,937)	(36,159)	(22,778)

Cash Flows from Financing Activities:
Dividends paid	(9,023)	(8,657)	(16,177)
Issuance (repurchase) of common stock	-	(53,277)	622
Other stock activity, net	(183)	(3)	(652)
Issuance of long-term debt	35,000	74,600	-
Principal retired on long-term debt	(5,733)	(12,089)	(22,126)
Short-term debt	(32,800)	5,300	27,500
Net cash provided (used) by financing activities	(12,739)	5,874	(10,833)
Increase (Decrease) in Cash and Cash Equivalents	13,833	(3,194)	(4,057)
Cash and Cash Equivalents at Beginning of Year	1,264	4,458	8,515
Cash and Cash Equivalents at End of Year	$ 15,097	$ 1,264	$ 4,458

Supplemental Disclosures of Cash Flow Information:
Cash Paid During the Year for:
Interest	$ 16,037	$ 14,222	$ 13,058
Income taxes	$ 3,656	$ 8,042	$ 8,261

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Capitalization
September 30, 1999 and 1998
(Dollars in Thousands)

	1999	1998
Common Stock Equity:
Common stock, no par, authorized 20,000,000 shares, issued and
outstanding 8,648,029 shares in 1999 and 1998	$ 67,448	$ 67,448
Retained earnings	61,048	56,447
	128,496	123,895
Less: Unearned compensation - restricted stock awards	(448)	(498)
	128,048	123,397
Preferred Stock, Not Subject to Mandatory Redemption:
$3.125 par value, 8%, noncallable, authorized 904,274 shares in 1999
and 909,898 shares in 1998, issued and outstanding 128,802 shares
in 1999 and 134,426 shares in 1998, entitled to preference on
liquidation at $6.25 per share	403	420

$100 par value, callable, authorized 9,999,557 shares in 1999 and 1998
6% Series B, issued and outstanding 4,593 shares in 1999 and 1998	459	459
	862	879
Long-Term Debt:
First Mortgage Bonds -
9.16%, due 2004	13,000	18,000
Industrial Revenue Demand Bonds -
1998 series, weighted average interest rate of 3.05% in 1999, due 2025	10,600	10,600
First Mortgage Note -
10.5%, due 2010	882	925
Senior Secured Notes -
6.99%, due 2009	45,000	45,000
6.90%, due 2010	15,000	15,000
Secured Notes -
6.89%, due 2010	11,570	12,260
Unsecured Medium Term Notes -
7.61%, due 2002	10,000	10,000
7.82%, due 2004	10,000	10,000
6.62%, due 2007	1,000	1,000
6.65%, due 2007	1,000	1,000
6.69%, due 2007	17,000	17,000
6.04%, due 2008	20,000	15,800
8.05%, due 2012	5,000	5,000
6.85%, due 2013	20,000	20,000
8.12%, due 2014	5,000	5,000
9.10%, due 2016	10,000	10,000
8.96%, due 2017	20,000	20,000
8.49%, due 2024	5,000	5,000
Less - Current Maturities	(5,283)	(5,733)
	214,769	215,852
	$343,679	$340,128

The accompanying notes are an integral part of these consolidated financial statements.

Consolidated Statements of Common Stock Equity
For the Years Ended September 30, 1999, 1998 and 1997
(Dollars in Thousands Except for Share Data)

`	Common Stock		Unearned	Retained
	Shares	Amount	Compensation	Earnings

Balance at September 30, 1996	10,620,439	$ 120,168	$ (312)	$ 49,026
Net income after preferred dividends	-	-	-	17,013
Purchase of restricted stock awards	16,078	501	(1,131)	-
Issues to dividend reinvestment and employee
benefit plans	29,145	622	-	-
Establishment of holding company	-	(508)	-	-
Amortization and adjustment of restricted shares	(13,493)	(374)	409	-
Dividends	-	-	-	(16,115)
Balance at September 30, 1997	10,652,169	120,409	(1,034)	49,924

Repurchase Common Stock	(1,999,998)	(52,891)	-	-
Net income after preferred dividends	-	-	-	15,135
Issues to dividend reinvestment and employee
benefit plans	-	63	-	-
Amortization and adjustment of restricted shares	(4,142)	(133)	536	(16)
Dividends	-	-	-	(8,596)
Balance at September 30, 1998	8,648,029	67,448	(498)	56,447

Net income after preferred dividends	-	-	-	13,563
Purchase of restricted stock awards	-	-	(165)	-
Amortization and adjustment of restricted shares	-	-	215	-
Dividends	-	-	-	(8,962)
Balance at September 30, 1999	8,648,029	$ 67,448	$ (448)	$ 61,048

The accompanying notes are an integral part of these consolidated financial statements.

NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands except for per share amounts)

September 30, 1999

1. Summary of Significant Accounting Policies:

Organization-

CTG Resources, Inc. ("the Company" or "CTG") is a holding company and parent of Connecticut Natural Gas Corporation ("CNG") and The Energy Network, Inc. ("TEN"). TEN holds and operates, through divisions or wholly-owned subsidiaries, CTG's unregulated, diversified businesses which also include the Company's equity investments in two partnerships, the Iroquois Gas Transmission System Limited Partnership ("Iroquois") and the Downtown Cogeneration Associates Limited Partnership ("DCA").

Merger with Energy East-

Through September 30, 1999, the Company has incurred and expensed merger-related costs of $3,204. The Company expects to incur additional merger-related costs estimated at $2,500. These costs will be expensed in fiscal 2000 as they are incurred.

Nature of the business-

CTG's principal business is the distribution, transportation and sale of natural gas through CNG. This business is subject to extensive regulation. CTG is also engaged in unregulated diversified businesses through TEN and its subsidiaries. These business activities are primarily focused on district heating and cooling ("DHC") and also include other energy-related products and services and new business development. The activities of Iroquois are regulated by the Federal Energy Regulatory Commission ("FERC").

Principles of consolidation-

CTG owns all of the capital stock of its subsidiaries, CNG and TEN. The consolidated financial statements represent the accounts of the Company after the elimination of intercompany transactions. Certain prior year amounts have been reclassified to conform with current year presentations.

Use of estimates-

The preparation of financial statements in conformity with generally accepted accounting principles 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.

Revenues-

Revenues are recorded based on deliveries to customers through the end of the accounting period. Regulated gas operations revenues are based on rates authorized by the DPUC.

The Company is required to provide natural gas service to residential customers within its defined service territory and is precluded by Connecticut state law from discontinuing service to hardship residential customers during a winter moratorium period (November - April).

In compliance with Connecticut law, the Company has an accounts receivable forgiveness program for qualified hardship natural gas customers. The total payments made by these customers and the energy assistance funds received on their behalf are matched by the Company. The DPUC allows the Company to defer this matched amount and to recover it from ratepayers in a future period. At September 30, 1999 and 1998, deferred balances of approximately $6,400 and $5,400, respectively, are included in other assets pending future amortization and recovery from ratepayers.

Purchased gas costs-

The Company passes on to its firm customers changes in gas costs from those reflected in its tariff charges. In accordance with this procedure, any current under or over-recoveries of gas costs are charged or credited to the cost of gas and included in current assets or liabilities. Such amounts are collected or refunded in subsequent periods under purchased gas adjustment provisions ("PGA").

Allowance for funds used during construction-

In the ordinary course of business, an allowance for funds used during construction ("AFUDC") is calculated on the construction of physical assets which exceed a minimum cost threshold and are constructed over an extended period of time.

AFUDC for the regulated operations is computed based on the weighted average cost of capital used to determine the rates charged to customers, as allowed by the DPUC. It is computed at current borrowing rates for the diversified businesses.

Plant-

Plant is stated at original cost, which includes an apportionment of general and administrative costs, and, for certain long-term construction projects, AFUDC.

Substantially all of the plant of the regulated operations is subject to the lien of the Indenture of Mortgage and Deed of Trust securing its First Mortgage Bonds. The Capitol Area DHC properties owned by TEN are also subject to the liens associated with TEN's Industrial Revenue Variable Rate Demand Bonds and related letter of credit (See Notes 6 and 7).

Purchase of Cogeneration Facility-

In June 1998, TEN acquired the assets of a 16-megawatt capacity cogeneration facility which supplies Hartford Hospital with steam and electricity. The price of approximately $17,000 was financed through existing lines of credit. The assets acquired in the transaction include $1,619 of current assets, $1,744 of plant and equipment and a note receivable of $13,637, of which $6,765 is current at September 30, 1999, and classified in accounts and notes receivable in the consolidated balance sheet. The note receivable relates to an existing termination agreement with the local electric utility which is now assigned to The Hartford Steam Company ("HSC"), a wholly-owned subsidiary of TEN. Pursuant to this agreement, the utility will make payments to HSC through December 2000. The facility came on line during fiscal 1999. HSC now supplies the hospital with steam and electricity over a twenty-year contract period.

Depreciation-

CTG and its subsidiaries, except CNG's wholly-owned subsidiary, CNG Realty Corp. ("CNGR"), provide depreciation on a straight-line basis. The composite rate applied by the regulated operations was 3.4% in 1999, 1998 and 1997, as approved by the DPUC. The operating and administrative center, owned by CNGR, is being depreciated under a DPUC approved sinking fund method through 2010.

The average depreciation rates for diversified businesses' depreciable plant were 3.4% in 1999 and 3.6% in 1998 and 1997.

Cash and cash equivalents-

Cash in excess of daily requirements is invested in short-term interest bearing securities with original maturities of three months or less.

Investments-

The Company has investments of $12,449 at September 30, 1999. These include $11,353 for a 4.87% investment in Iroquois and $1,096 for a 50% investment in the Downtown Cogeneration Associates Limited Partnership ("DCA"). These investments are accounted for on the equity method of accounting.

Iroquois owns and operates a natural gas pipeline which transports Canadian natural gas into New York State, Massachusetts and Connecticut. DCA owns and operates a 4.2-megawatt cogeneration facility in Hartford, Connecticut.

During the second quarter of fiscal 1998, TEN assumed control of KBC Energy Services ("KBC"), a New England natural gas marketer, and began the sale of its assets and the wind down of its operations. The fiscal 1998 charge to other income/(deductions) related to the wind down of KBC was $1,012, net of income taxes. Management does not anticipate any significant future activity related to KBC.

Inventories-

Gas inventories are stated at their weighted average cost. Other inventories are accounted for using the first-in, first-out or average cost method.

Accounting for the effects of regulation-

CNG's natural gas distribution business is subject to regulation by the DPUC. CNG prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS No. 71"). SFAS No. 71 requires a cost-based, rate-regulated enterprise such as CNG to reflect the impact of regulatory decisions in its financial statements. In certain circumstances, SFAS No. 71 requires that certain costs and/or obligations (such as incurred costs not currently recovered through rates, but expected to be so recovered in the future) be reflected in a deferred account in the balance sheet and not be reflected in the statement of income until matching revenues and/or expenses are recognized. CNG records regulatory assets and liabilities based on prior rate orders issued by the DPUC, which provide a mechanism for recovery in regulated rates, or on historical rate treatment, which provides evidence as to the probability of future rate recovery.

In the application of SFAS No. 71, the Company follows accounting policies that reflect the impact of the rate treatment of certain events or transactions. Specifically, the DPUC permits recovery of depreciation on the operating and administrative center, owned by CNGR, under a sinking fund method through 2010. The overall impact of annual depreciation expense under this method, versus straight line depreciation recovery, is not material to the overall financial statements.

It is the Company's policy to continually assess the recoverability of costs recognized as regulatory assets and the Company's ability to continue to account for its regulated activities in accordance with SFAS No. 71, based on each regulatory action and the criteria set forth in SFAS No. 71. Based on current regulation and recent DPUC decisions, the Company believes that its use of regulatory accounting is appropriate and in accordance with the provisions of SFAS No. 71.

The Company's consolidated balance sheets at September 30, 1999 and 1998 contain the following amounts as a result of the application of SFAS No. 71:

	Assets/(Liabilities)
	1999	1998
Hardship Arrearage Forgiveness	$ 6,377	$ 5,388
Unrecovered Future Taxes	5,322	10,734
Other Postretirement Benefits	2,775	2,974
Deferred Income Taxes	2,312	1,797
Other Deferred Charges	2,106	1,280
Pipeline Refunds, Surcharges and Interest	(514)	(535)
Refundable Purchased Gas Costs	(2,782)	(1,496)
Revenue Sharing Mechanisms	(4,262)	(3,329)
Refundable Taxes	(5,311)	(4,252)
	$ 6,023	$ 12,561

New accounting standard-

In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). This statement establishes accounting and reporting standards for derivative instruments and for hedging activities. In June 1999, the FASB issued SFAS No. 137 "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," to amend the implementation date of SFAS No. 133. Adoption of SFAS No. 133 is now required for the Company beginning with the first quarter of fiscal 2001. The Company is aware of certain provisions which may impact the natural gas industry but has not yet reviewed these provisions in detail against its existing accounting practices and disclosures. At this time the Company cannot predict what impact, if any, the adoption of SFAS No. 133 will have on its financial condition or results of operations.

2. Regulatory Matters:

In a second phase of a regulatory review of natural gas deregulation which began in 1996, the DPUC is addressing the potential deregulation of the residential natural gas sales market in Connecticut and the future role of Connecticut's local natural gas distribution companies ("LDCs") in natural gas commodity sales. The DPUC has asked Connecticut LDCs to file information for the purpose of examining costs and developing appropriate natural gas sales and delivery rates for customers, to ensure that customers pay only for those services that they use. CNG filed its cost of service study with the DPUC in August 1999. Once the DPUC concludes generic proceedings, it is expected to order each LDC to adjust its rates accordingly. The Company cannot predict the outcome of these proceedings.

3. Retiree Benefits:

Effective October 1, 1998, CTG adopted SFAS No.132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" ("SFAS No. 132"), which revises prior disclosure requirements. The information for fiscal 1998 and 1997 has been updated to comply with SFAS No. 132 disclosure requirements.

The Company has noncontributory retirement plans ("Plans") covering substantially all employees. Pension benefits are based on years of credited service and employees' average annual earnings, as defined in the Plans. The Company's funding policy is to contribute, annually, an amount at least equal to that which will satisfy the minimum funding requirements of the Employee Retirement Income Security Act. The Company also provides its officers with a supplemental retirement plan. The Company contributes to a trust to fund the liability for these supplemental retirement plan benefits. The trust balance included in other assets at September 30, 1999 and 1998, was $5,982 and $5,805, respectively.

The Company provides certain health care and life insurance benefits to retirees through a benefit plan. These benefits are available for employees leaving the Company who are otherwise eligible to retire and have met specific service requirements. The Company may also provide certain health care, life insurance or income benefits to former or inactive employees after employment but before retirement. The Company accounts for these costs on the accrual basis under SFAS No. 112, "Employers' Accounting for Postemployment Benefits."

The Company began the amortization of its postretirement accumulated benefit obligation over a twenty-year period in 1994. In 1995, the DPUC approved a five-year phase-in of SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other than Pensions" ("SFAS No. 106") expenses with an allowed annual recovery of $2,755 allowed in rates and deferral of additional SFAS No. 106 expenses for future recovery. At September 30, 1999 and 1998, $2,775 and $2,975, respectively, were deferred pending future amortization and recovery.

The net cost for these plans included in the statements of income for the years ending September 30, includes the following components:

	Pension Benefits				Other Benefits
	1999	1998	1997	1999		1998	1997
Service cost	$ 2,652	$ 2,490	$ 2,139	$ 528		$ 456	$ 425
Interest cost	7,133	7,195	6,730	2,036		2,045	2,131
Expected return on plan assets	(9,656)	(8,899)	(8,042)	(904)		(707)	(463)
Amortization of prior service cost	87	40	108	-		-	-
Amortization of transition obligation	(212)	(212)	(212)	901		954	981
Recognition of net actuarial (gain)/loss	60	84	(166)	-		-	-
Net periodic pension cost	$ 64	$ 698	$ 557	$ 2,561		$ 2,748	$ 3,074

The following tables show the change in benefit obligation and plan assets, reconciliation of the Plans' funded status and amounts included in the balance sheets at September 30, 1999 and 1998:

	Pension Benefits		Other Benefits
	1999	1998	1999	1998
Change in Benefit Obligation
Benefit obligation at beginning of year	$ 107,077	$ 98,508	$ 29,255	$ 28,460
Service cost	2,652	2,490	528	456
Interest cost	7,133	7,195	2,036	2,045
Plan amendments	592	494	-	(1,220)
Actuarial (gain) or loss	(2,758)	3,319	2,721	923
Benefits paid	(5,122)	(4,929)	(1,777)	(1,409)
Benefit obligation at end of year	$ 109,574	$ 107,077	$ 32,763	$ 29,255

Change in Plan Assets
Fair value of plan assets at beginning of year	$ 123,611	$ 113,331	$ 11,037	$ 8,504
Actual return on plan assets	6,214	14,897	1,331	1,506
Employer contribution	345	312	4,812	2,436
Benefits paid	(5,122)	(4,929)	(1,777)	(1,409)
Fair value of plan assets at end of year	$ 125,048	$ 123,611	$ 15,403	$ 11,037

Reconciliation of Funded status
Funded status	$ 15,474	$ 16,534	$ (17,360)	$ (18,218)
Unrecognized net actuarial (gain) or loss	(17,965)	(18,589)	4,130	1,870
Unrecognized prior service cost	1,302	797	-	-
Unrecognized transition obligation	221	9	12,657	13,519
Prepaid (accrued) benefit cost	$ (968)	$ (1,249)	$ (573)	$ (2,829)

Amounts Recognized in the Balance Sheet
Prepaid benefit cost	$ 1,947	$ 1,288
Accrued benefit liability	(5,424)	(4,360)
Intangible asset	1,735	1,279
Accumulated additional benefit cost expensed	774	544
Net amount recognized	$ (968)	$ (1,249)	$ (573)	$ (2,829)

The Company has established two Employee Benefit Trusts ("VEBA") to pay current retiree health care and life insurance benefits and to fund the Company's retirement benefit liability. In fiscal 1999, 1998 and 1997 the Company funded $2,520, $2,493 and $2,459, respectively, for health care and life insurance costs. The VEBA balances are primarily invested in life insurance policies and commingled fixed income and equity mutual funds.

The weighted average assumptions used in developing the projected benefit obligations were:

	Pension Benefits			Other Benefits
	1999	1998	1997	1999	1998	1997
Discount rate	7.25%	7.00%	7.50%	7.25%	7.00%	7.50%
Expected return on plan assets	9.00%	9.00%	9.00%	8.00%	8.00%	8.00%
Increase in future compensation	4.00%	4.00%	4.00%	4.00%	4.00%	4.00%
Cost of living adjustment	2.75%	3.00%	3.00%	N/A	N/A	N/A

For purposes of developing the expense, annual rates of increase of 7.5% and 6.5% are assumed for non-Medicare and Medicare eligible retirees, respectively, in the per capita cost of covered health care benefits. For both groups, the annual rate of increase is assumed to reduce gradually to 4.5% by the year 2005. For purposes of disclosure, the corresponding annual rates of increase of 12.0% and 11.0% are assumed for non-Medicare and Medicare eligible retirees, respectively, reducing to 6.5% and 5.5% for the second year, and then reducing gradually to 4.5% and 5.5% by the year 2005.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage Point Increase	1-Percentage Point Decrease

Effect on total of service and interest cost components	$ 95	$ (97)
Effect on postretirement benefit obligation	$ 1,407	$ (1,382)

4. Taxes:

Income Taxes-

The following is an analysis of the provision for federal and state income taxes:

	September 30,
	1999	1998	1997
Charged to operations:
Federal:
Current	$ 6,445	$ 4,742	$ 10,330
Deferred	5,144	5,277	3,069
	11,589	10,019	13,399
State:
Current	1,205	427	2,816
Deferred	1,579	1,985	965
	2,784	2,412	3,781
Deferred investment tax credits	(221)	(221)	(221)
Total charged to operations	14,152	12,210	16,959

Charged to other income/(deductions):
Federal:
Current	684	590	531
Deferred	-	62	(34)
	684	652	497
State:
Current	(14)	183	179
Deferred	-	21	(11)
	(14)	204	168
Total charged to other income/(deductions)	670	856	665

Total	$ 14,822	$ 13,066	$ 17,624

Depreciation for federal income tax purposes is computed using accelerated cost recovery methods and different lives as permitted under the Internal Revenue Code ("Code"). The DPUC has allowed the Company to normalize taxes on accelerated depreciation, as required under the Code, for depreciable property additions made by the regulated operations subsequent to 1980. For certain other temporary differences, tax reductions are accounted for as a reduction of federal income tax expense in accordance with the flow-through method of accounting as required by the DPUC. Under the established ratemaking practices followed by the DPUC, deferred income taxes not previously provided for will be collected in customer rates when such taxes become payable.

Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Deferred income taxes are primarily a result of normalized plant items and temporary differences related to gas costs. For the regulated operations, deferred investment tax credits are amortized to income over the average life of the related property. The diversified businesses provide deferred taxes on all temporary differences, including depreciation.

The tax effects of the temporary differences which resulted in the deferred income taxes on the balance sheets at September 30, 1999 and 1998 were:

    1999

    1998

Property, Plant and Equipment

$ 56,136

$ 53,297

Other, net

      (692)

    (3,122)

Deferred Income Taxes

$ 55,444

$ 50,175

The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes" ("SFAS No. 109"). Under the caption "Refundable Taxes" the balance sheet reflects refundable taxes to ratepayers for reductions in the statutory federal income tax rate on normalized plant related temporary differences. The regulated operations also recognize the cumulative deferred income taxes on temporary differences which were previously flowed through to ratepayers. At September 30, 1999 and 1998, the Company had $5,322 and $10,734, respectively, on the balance sheets as an unfunded deferred income tax liability, with a corresponding unrecovered receivable, for temporary differences previously flowed through to ratepayers. These amounts have been adjusted for the tax effect of future revenue requirements and will be amortized over the life of the related depreciable assets concurrent with their recovery in rates.

A reconciliation of the consolidated federal income tax expense, at the statutory tax rate of 35%, to the reported consolidated federal income tax expense is as follows:

    1999

    1998

    1997

Consolidated statutory federal income tax expense

$   8,987

$   8,976

$ 10,762

Change in consolidated federal income tax expense

    resulting from:

Excess book over tax depreciation

      2,857

      2,654

      2,253

Non-deductible merger costs

         889

         -

          -

Investment tax credits

       (221)

       (221)

       (221)

Bad debts

            -

           44

         175

Tax reserves

       (295)

       (866)

         714

Computer software

         175

         175

         175

Cost of removal

       (311)

       (381)

       (324)

Other

          (29)

           69

         141

Consolidated reported federal income tax expense

$ 12,052

$ 10,450

$ 13,675

Outstanding tax issues-

5. Capital Stock:

Shareholder Rights Plan-

On December 1, 1998, the CTG Board of Directors declared a dividend distribution of one right (a "Right") for each outstanding share of CTG common stock. The distribution was payable on December 18, 1998 to the shareholders of record as of the close of business on that date. Each Right entitles the registered holder thereof to purchase from CTG one one-hundredth of a share of CTG Series A Junior Participating Preferred Stock, without par value ("CTG Preferred Stock"), at a price of $65.00 per one one-hundredth of a share of CTG Preferred Stock, subject to adjustment. The description of the terms of the Rights are set forth in a Rights Agreement, dated as of December 1, 1998 (the "Rights Agreement"), between CTG and ChaseMellon Shareholder Services, L.L.C., as Rights Agent.

Under the Rights Agreement, the Rights trade together with shares of CTG common stock, and shares of CTG common stock issued upon transfer or new issuance will contain a notation incorporating the Rights Agreement by reference. In absence of further action by the CTG Board of Directors, the Rights will generally become exercisable if any person or group acquires 10% or more of the CTG common stock. Rights held by persons who exceed the applicable threshold will be void. In certain circumstances, the Rights will entitle the holder to buy shares in an acquiring entity at a discounted price

The Rights Agreement also includes an exchange option. In general, after the Rights become exercisable, the CTG Board of Directors may, at its option, effect an exchange of all or part of the Rights (other than Rights that have become void) for shares of CTG common stock. Under this option, CTG would issue one share of CTG common stock for each right, subject to adjustment in certain circumstances.

The CTG Board of Directors may, at its option, redeem all Rights, generally at any time prior to the Rights becoming exercisable. The Rights will expire on December 18, 2008, unless earlier redeemed, exchanged or amended by the CTG Board of Directors.

In June 1999, CTG amended the terms of the Rights Agreement to provide, among other things, that the execution, delivery and performance of its merger agreement with Energy East Corporation (See Note 1 to the Financial Statements) and the transactions contemplated by the merger agreement will not cause any Rights to become exercisable.

Copies of the Rights Agreement and the above-referenced amendment thereto have been filed with the Securities and Exchange Commission and are available free of charge from CTG.

This summary description of the Rights and the Rights Agreement, as amended, does not purport to be complete and is qualified in its entirety by reference to the Rights Agreement, as amended.

Stock Options -

Beginning in fiscal 1999, the Company offered a stock option plan for officers, directors and key employees (the "Option Plan"). Under the Option Plan, options are granted at an exercise price not less than the fair market value of the Company's no par common stock at the date of grant. The maximum number of shares that may be issued under the Option Plan is 500,000. In fiscal 1999, 64,600 options were granted under the Option Plan. The options ordinarily vest over three years, beginning after the second year following their grant. However, the grants will vest and be exercisable upon a change of control. The grants are exercisable over ten years. The exercise price of the options is $23.125. No options were vested or exercisable at September 30, 1999.

The status of the Company's Option Plan as of September 30, 1999 is summarized below:

	Number of Shares	Weighted Average Exercise Price



Outstanding at September 30, 1998	-	$ -
Granted	64,600	23.125
Outstanding at September 30, 1999 (held by 14 optionees)	64,600	$ 23.125

The Company accounts for compensation related to the Option Plan using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." Under this method, no compensation cost for stock options is recognized for stock option awards granted at or above fair market value. Had compensation expense for the Option Plan been determined based upon fair values at the grant date in accordance with SFAS No. 123, "Accounting for Stock Based Compensation," the Company's net income applicable to common stock would have been $13,524 in fiscal 1999. Basic earnings per share for fiscal 1999 would have been $1.57 and fully diluted earnings per share for fiscal 1999 would have been $1.56. As the Option Plan began in fiscal 1999, net income applicable to common stock and earnings per share for fiscal 1998 and 1997 would not have been affected.

For purposes of determining the impact to net income applicable to common stock and earnings per share, the fair value of the options on their grant date was measured using the Binomial option pricing calculation. Key assumptions used to prepare this calculation were as follows:

	1999
Risk-free interest rate	5.18%
Expected life of option grants (years)	10
Expected volatility of underlying stock	20%

Dividend reinvestment plan and employee savings plans-

The Company maintains a Dividend Reinvestment Plan ("DRIP") which provides the Company's holders of common stock and preferred stock the opportunity to receive shares of the Company's common stock in lieu of some or all of their cash dividends. In addition, the Company has Employee Savings Plans ("ESP"), which are designed to encourage and assist employees to save and invest for long-term financial security. The Company's common stock is one of the investment options offered to employees under the ESP. At September 30, 1999, there were 74,263 shares of the Company's common stock reserved for issuance under the DRIP and ESP. In the fiscal years ended September 30, 1999, 1998 and 1997, the Company's contributions to the ESP on behalf of employees were $954, $1,032 and $960, respectively.

Restricted stock plan-

In 1990, the Company adopted a restricted stock performance plan terminating in the year 2000 and authorized to issue up to 200,000 shares. On February 23, 1999, the Company extended the term of this plan to 2010. On October 1, 1990, October 1, 1993, October 1, 1996 and April 27, 1999, key employees were granted 22,146, 24,040, 41,800 and 6,450, respectively, of restricted shares of the Company's common stock under this plan. Restrictions lapse and the shares vest over a one to five year period beginning October 1, 1990, 1993, 1996 and 1999, respectively, as certain performance goals are achieved. In October 1995, 5,770 of the restricted shares from the 1990 grant became fully vested and were awarded to qualifying employees. In October 1999, 7,950 restricted shares from the 1996 grant became fully vested and were awarded to qualifying employees.

The market value of the shares awarded under this plan has been recorded as unearned compensation and is a separate component of common equity. The unearned compensation is being charged to expense over the vesting period based on achievement of the performance criteria.

Recapitalization plan-

On October 30, 1997, through a tender offer made by TEN, the Company repurchased approximately 2.0 million shares of CTG common stock for approximately $53,000. TEN financed the purchase with a combination of revolving bank debt and the issuance of Senior Secured Notes. The shares repurchased by TEN were transferred by the depositary directly to CTG. In connection with the repurchase, effective with the first quarter of fiscal 1998, CTG reduced its quarterly dividend on common stock from $0.38 ($1.52 annually) to $0.25 ($1.00 annually) per share.

Forward equity purchase agreement-

In a Forward Equity Purchase Agreement amended October 14, 1998 and originally dated October 1, 1997, CTG has committed to fund from $4,500 to $9,000 per year into TEN from 1998 through 2009 for an aggregate additional cash infusion into TEN of $122,600. In exchange, TEN caused all shares of CTG common stock purchased through the October 1997 tender offer to be transferred directly to CTG by the depositary. As a provision of this agreement, CTG is restricted from declaring or paying any dividends or distributions to its holders of common stock if any amounts due and payable under this agreement are in arrears.

Earnings per share-

SFAS No. 128, "Earnings per Share," requires the computation of basic and diluted earnings per share. Basic earnings are computed by dividing net income available for common stock by the weighted average number of common shares outstanding during the year. Diluted earnings per share are determined by giving effect to the exercise of stock options, using the treasury stock method, and to granted but unawarded restricted stock plan shares.

	1999	1998	1997
Net Income Applicable to Common Stock	$ 13,563	$ 15,135	$ 17,013
Weighted Average Common Shares Outstanding	8,613,455	8,871,349	10,632,001
Dilutive Effect of Restricted Stock Plan Shares	34,574	51,616	51,758
Dilutive Effect of Options	8,843	-	-
Adjusted Weighted Average Common Shares Outstanding	8,656,872	8,922,965	10,683,759
Basic Earnings per Share	$ 1.57	$ 1.71	$ 1.60
Diluted Earnings per Share	$ 1.57	$ 1.70	$ 1.59

Preferred stock-

The preferred stock on the balance sheet was issued by CNG. CNG is prohibited from, among other things, paying dividends on common stock and purchasing, redeeming or retiring common stock, if dividends on preferred stock are in arrears.

The following table sets forth the changes in the number of shares outstanding for each class of the Company's preferred stock not subject to mandatory redemption, for the years ended September 30, 1999, 1998 and 1997:

   1999

   1998

   1997

$3.125 par value

   (5,624)

            -

   (3,934)

$100 par value

            -

        (45)

        (29)

6. Long-term Debt:

The Company has various issues of first mortgage bonds and first mortgage notes outstanding with maturities from 2004 to 2010, secured notes with maturities from 1999 to 2010, industrial revenue variable rate demand bonds which mature in 2025 and unsecured medium term notes with maturities from 2002 to 2024. Under the most restrictive terms of the indenture securing the bonds, retained earnings of $26,700 are available for CNG to pay dividends at September 30, 1999. CTG's ability to pay dividends is not restricted by these terms. Dividends paid on common and preferred stock in fiscal 1999 were $9,023. Sinking fund requirements for outstanding bonds were paid in cash.

Many of the Company's debt agreements require the maintenance of certain financial and operating covenants. At September 30, 1999 the Company was in compliance with or had received a waiver with respect to these covenants and provisions.

In October 1998, the Company issued $15,000 of Senior Secured Notes, due in 2010, at 6.9%. The full amount of the principal is due at maturity. The September 30, 1998, financial statements reflect the classification of the debt that was retired as a result of this refinancing as long-term debt.

In October 1998, the Company issued a total of $20,000 of Medium Term Notes ("MTNs") at 6.04%, due 2008. These MTNs are unsecured and have no call provisions or sinking fund requirements. The long-term debt amounts shown on the balance sheet and statement of capitalization at September 30, 1998 include $15,800 of these MTNs.

In October 1997, the Company issued Senior Secured Notes for $45,000, due in 2009, at 6.99%. The principal will be retired through semi-annual payments of $2,500 beginning in 2001. The proceeds were used to repurchase approximately 2.0 million shares of CTG common stock.

The face values and interest rates of these MTNs are:

Face Value

Interest Rate

$    1,000

6.62%

$    1,000

6.65%

$  17,000

6.69%

Long-term debt amounts which are due during each of the five years ending September 30, 2000 through 2004, are as follows:

Sinking Fund Requirements and Maturities

Year

Total

2000

$   5,283

2001

      5,843

2002

    18,404

2003

      8,465

2004

    17,033

$ 55,028

7. Short-term Borrowings and Lines of Credit:

The Company maintains a line of credit under a revolving credit agreement with a bank. Under this agreement the Company can borrow up to $20,000 at a Eurodollar or Base Rate of interest plus a variable margin. In March of 1998, the Company extended this agreement to 2001 with two subsequent one-year renewal options. There is a variable .15% to .5% commitment fee. At September 30, 1999 there were no borrowings outstanding under this agreement.

The Company maintains a one-year seasonally variable $10,000 to $15,000 line of credit with a bank through February of 2000. The Company pays a 1/5 of 1% commitment fee on this line of credit. The interest rate varies according to market conditions. At September 30, 1999 there were no borrowings outstanding under this line of credit.

TEN maintains a 364-day secured revolving credit agreement for $10,000 with a bank. This agreement matured in September 1999 and was extended into the first quarter of fiscal 2000 while arrangements for its renewal are in progress. Interest is based on a Bank Rate or a LIBOR rate plus a variable margin. It is determined at the time of each borrowing. There is a one-time $5 commitment fee and a .375% facility fee upon renewal. At September 30, 1999 there were no borrowings outstanding under this line of credit.

TEN maintains a three-year revolving credit agreement for $10,000 with a bank through September 2000. The maximum borrowing amount is reduced by $500 on each fiscal quarter, beginning January 1, 1998. Interest is based on a Bank Rate or a LIBOR rate plus a variable margin and is determined at the time of each borrowing. There is a one-time $5 commitment fee and an on-going .45% to .6% facility fee. At September 30, 1999 there were no borrowings outstanding under this line of credit.

The weighted average interest rate on short-term borrowings outstanding was 5.98% at September 30, 1998.

8. Fair Value of Financial Instruments:

The fair value amounts disclosed below have been reported to meet the disclosure requirements of SFAS No. 107, "Disclosures About Fair Values of Financial Instruments" and are not necessarily indicative of the amounts that the Company could realize in a current market exchange.

The carrying amount of cash and cash equivalents; accounts receivable; notes payable; accounts payable and accrued expenses; and refundable purchased gas costs approximates fair value.

At September 30, 1999 and 1998, the fair value of the Company's long-term debt, including current maturities, is estimated to be $220,307 and $209,121, respectively. The fair value at year-end 1999 and 1998, of $209,452 and $180,185 of fixed-rate long-term debt, based on the market value of similar instruments, is estimated at $209,707 in 1999 and $198,521 in 1998. The carrying amount of the variable-rate long-term debt of $10,600 in 1999 and 1998 approximates fair value.

The Company has committed to support 4.87% of a letter of credit for Iroquois, equivalent to approximately $1,431 at September 30, 1999, which approximates fair value. The letter of credit is used to satisfy Iroquois' cash retention requirements with respect to agreements between Iroquois and its lenders.

9. Commitments and Contingencies:

Construction expenditures-

Construction expenditures for the fiscal year ending September 30, 2000 are estimated at $26,300 for the regulated operations and $10,900 for the diversified businesses.

In April 1999, TEN executed a twenty-five year agreement with the City of Hartford to supply hot and chilled water to several facilities referred to collectively as The Learning Corridor. Energy to serve these customers will be produced at TEN's cogeneration facility located at Hartford Hospital. Construction of necessary pipeline and other facilities began in the third quarter of fiscal 1999. Service to The Learning Corridor is expected to begin early in the year 2000. The cost of this expansion of TEN's DHC system is estimated to be approximately $6,000, to be expended between fiscal 1999 and 2000. Approximately $700 was spent in fiscal 1999.

Adriaen's Landing-

The Company has been approached by local businesses and government agencies regarding the development of a stadium and convention center along with hotel, retail and recreational facilities. The proposed development, known as Adriaen's Landing, would be built in the area of the Company's headquarters and operating center. The Company, in order to accommodate the development as it has been proposed, would be required to relocate its administrative and operating facilities and potentially a portion of TEN's steam and chilled water production facilities. Discussions are now underway with the developers in order to accomplish this at no cost to the Company or its customers. The area of development, which includes Company property, may contain hazardous materials that the project participants will be required to address.

Gas supply-

The Company is party to short-term and long-term contracts for the purchase of natural gas and transportation and storage services.

Steam supply-

Along with generating steam from their own internal boilers, the DHC operations are party to long-term contracts for the purchase of steam.

Energy Contract Buyouts-

TEN is a 50% partner in Downtown Cogeneration Associates Limited Partnership ("DCA"), a single purpose entity operating a 4.2-megawatt dual-fuel gas turbine generator which supplies electricity to a local electric utility under an Energy Purchase Agreement ("EPA") and steam to TEN's wholly-owned DHC subsidiary, HSC, under a Steam Supply Agreement ("SSA"). Currently, the electric utility and HSC are able to obtain energy at a lower cost than that which they pay under these agreements. For this reason, the electric utility and HSC have offered to buy out of their contracts with DCA. In March 1999, TEN and its partners in the DCA agreed to terminate both the EPA and SSA and negotiated terms for the buy out of each of these agreements, subject to DPUC approval for the electric utility. HSC's buy out of the SSA is estimated at $5,800.

The termination of the EPA and the SSA with DCA will occur upon the receipt of all necessary approvals for the electric utility. This is expected sometime in the year 2000. Until then the DCA plant will continue to produce and sell steam and electricity under the SSA and EPA. HSC's termination of the SSA should benefit HSC and its customers by lower future production costs but will reduce TEN's earnings from its partnership interest in DCA.

Letters of credit-

The Company has outstanding a letter of credit amounting to $1,500 for workers' compensation claims. As a condition of its ownership in the DCA, TEN is contingently liable under two letters of credit amounting to $8,800. As a condition to its variable rate long-term debt, TEN holds a long-term letter of credit amounting to $10,757 at September 30, 1999 and 1998.

Environmental matters-

In the ordinary course of business, the Company may incur costs to clean up environmental contaminants related to natural gas activity. In those instances the Company expects that the remediation costs will be recoverable in rates. In August 1998, the Company received a notice of violation ("NOV") from the Connecticut Department of Environmental Protection ("DEP") regarding a number of areas on noncompliance. The Company submitted the required compliance report in September 1998. In April 1999, the DEP provided the Company with a draft Consent Order and informed the Company, by letter, that the Company's actions in response to the NOV were sufficient to correct the violations. The Company will also be required to pay a minimal penalty fee. The Company is working with the DEP to negotiate the Consent Order. The Company's written response to the DEP was submitted in October 1999. In the opinion of management, any existing environmental issues will not be significant to the future financial condition or results of operations of the Company.

Leases-

The Company has entered into operating lease agreements for the use of computer and office equipment, facilities and motor vehicles. For fiscal 1999, 1998 and 1997, these lease payments were $1,243, $2,058 and $1,378 respectively.

Lease payments are projected to be approximately $1,100 per year for each of the five years ending September 30, 2000 through 2004. If the Company relocates its facilities to make room for the proposed Adriaen's Landing project, described above, the Company may need to lease space to replace its current administrative offices and operations facilities. At this time, the Company cannot predict either the amount of space that would need to be leased or the lease payments that would be required.

Legal proceedings-

During fiscal 1999, CNG reached a settlement which resolves all three actions with no material impact to its results of operations or financial condition.

10. Segment Information:

The Company operates and manages its business in two segments: regulated gas-related activities and unregulated diversified businesses. Gas-related activities include the purchase, distribution and sale of natural gas to on-system residential, commercial, industrial customers and off-system sales. Diversified businesses provide district heating and cooling services to large buildings and building complexes. These segments are managed separately because each offers a different energy product and one is regulated and the other is not.

The segments follow the same accounting policies as described in Note 1, "Summary of Significant Accounting Policies." Intersegment sales are priced in accordance with terms of existing tariffs and contracts, as if they were made to third parties. Management evaluates segment performance based on operating income.

The unregulated, diversified businesses hold all of the Company's investments in equity-method investees. The full share of the Company's profit or loss from theses investments is included in the diversified businesses' net income. Income taxes are allocated to the segments based on a tax sharing agreement.

Information about the Company's operations, by business segment, is presented below:

	1999	1998	1997
Revenues:
Gas related activities	$ 265,913	$ 266,418	$ 287,401
Diversified businesses	25,558	21,049	22,636
Intersegment revenues	(4,722)	(4,719)	(4,742)
Consolidated Revenues	$ 286,749	$ 282,748	$ 305,295

Pre-Tax Operating Income:
Gas related activities	$ 40,581	$ 39,342	$ 42,839
Diversified businesses	3,956	2,323	1,734
Total	44,537	41,665	44,573
Income Taxes	14,152	12,210	16,959
Consolidated Operating Income	$ 30,385	$ 29,455	$ 27,614

Identifiable Assets:
Gas related activities	$ 386,458	$ 382,669	$ 382,289
Diversified businesses	79,803	76,512	62,084
Consolidated Identifiable Assets	$ 466,261	$ 459,181	$ 444,373

Depreciation and Amortization:
Gas related activities	$ 17,972	$ 17,087	$ 16,019
Diversified businesses	2,261	2,218	2,165
Total	$ 20,233	$ 19,305	$ 18,184

Property Additions:
Gas related activities	$ 21,403	$ 21,189	$ 23,726
Diversified businesses	3,589	1,246	867
Total	$ 24,992	$ 22,435	$ 24,593

Interest Expense:
Gas related activities	$ 12,239	$ 11,863	$ 12,128
Diversified businesses	3,727	3,752	713
Total	$ 15,966	$ 15,615	$ 12,841

Interest Income:
Gas related activities	$ 624	$ 113	$ 299
Diversified businesses	177	218	31
Total	$ 801	$ 331	$ 330

The following table reconciles reportable segment revenues, net income, assets and depreciation and amortization to the Company's consolidated total.

	1999	1998	1997
Revenues:
External revenues for reportable segments	$ 291,471	$ 287,467	$ 310,037
Intersegment revenues	(4,722)	(4,719)	(4,742)
Consolidated Revenues	$ 286,749	$ 282,748	$ 305,295

Net Income:
Total net income for reportable segments	$ 16,559	$ 15,196	$ 17,075
Corporate merger-related costs	(2,935)	-	-
Consolidated Net Income	$ 13,624	$ 15,196	$ 17,075

Assets:
Total assets for reportable segments	$ 466,261	$ 459,181	$ 444,373
Holding company assets	-	-	-
Consolidated Assets	$ 466,261	$ 459,181	$ 444,373


Other Significant Non-Cash Items -
Depreciation and Amortization:
Segment totals	$ 20,249	$ 19,321	$ 18,200
Intersegment eliminations	(16)	(16)	(16)
Consolidated Total	$ 20,233	$ 19,305	$ 18,184

11. Quarterly Results (Unaudited):

The following table sets forth information with respect to the consolidated quarterly results of operations for the fiscal years 1999 and 1998. The amounts are unaudited but, in the opinion of management, present fairly the results of operations.

The quarterly results of operations reflect the seasonal nature of the Company's operations. The results of any one quarter during the year are not indicative of the results of future quarters or the results of the Company's fiscal year.

Consolidated Results of Operations

Quarter Ended	December 31,	March 31,	June 30,	September 30,
	1998	1999	1999	1999
Operating Revenues	$ 81,679	$ 113,001	$ 52,225	$ 39,844
Operating Income (Loss)	$ 9,392	$ 15,990	$ 4,649	$ (258)
Net Income (Loss)	$ 5,692	$ 12,241	$ (780)	$ (3,529)
Net Income (Loss) Per Common Share*	$ 0.66	$ 1.41	$ (0.09)	$ (0.41)

Quarter Ended	December 31,	March 31,	June 30,	September 30,
	1997	1998	1998	1998
Operating Revenues	$ 92,396	$ 105,416	$ 48,370	$ 36,566
Operating Income (Loss)	$ 11,472	$ 14,169	$ 3,775	$ 39
Net Income (Loss)	$ 8,123	$ 9,727	$ 179	$ (2,833)
Net Income (Loss) Per Common Share*	$ 0.85	$ 1.12	$ 0.02	$ (0.33)

* The sum of quarterly earnings per share does not equal annual earnings per share as reported on the statements of income because of quarterly changes in weighted average shares outstanding.

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no disagreements required to be disclosed under this item.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Board of Directors is divided into three classes, and each class is elected for a 3-year term. The terms of the directors in each class are scheduled to expire at the third annual meeting following their election. The information required by this item regarding executive officers of the registrant is included in Item 4 of Part I of this Form 10-K. Each director of CTG is also a director of Connecticut Natural Gas Corporation, a wholly-owned subsidiary of CTG.

Bessye W. Bennett, 61	Mrs. Bennett is the Principal in the Law Offices of Bessye W. Bennett, Bloomfield, CT. Mrs. Bennett has been engaged in the private practice of law as a sole practitioner from 1983 to the present, except for the period 1990 to 1995 when she was a partner in the law firm of Douglas-Bailey and Bennett, Bloomfield, CT. She is a cum laude graduate of Radcliffe College with a B.A. in Government and also holds an M.A. in Education from Trinity College and a J.D. from the University of Connecticut Law School. She is a director of the Trust Company of Connecticut. She has been Director since 1987 and is a Class II Director, last elected in 1999. She is a member of the Audit Committee and Committee on Directors.
Herman J. Fonteyne, 60	Mr. Fonteyne joined Ensign-Bickford Industries, Inc, Simsbury, CT in 1982 as President and Chief Executive Officer, retiring in 1998. He has a B.S. degree in Chemical Sciences from Louvain University in Belgium. A Director since 1993, is a Class I Director, last elected in 1998. Mr. Fonteyne is the Chair of the Audit Committee and member of the Compensation Committee.
Victor H. Frauenhofer, 66	Mr. Frauenhofer joined the Company in 1961 and held various positions, including Chairman, President and Chief Executive Officer with the Company. In January 1998 Mr. Frauenhofer relinquished the position of Chief Executive Officer and he retired from the Company in July 1998. Mr. Frauenhofer is a graduate of Bentley College and Harvard AMP. He serves on the Board of Directors of Spencer Turbine Company. He has been a Director since 1978 and is a Class III Director, last elected in 1997. He is a Member of the Executive Committee and Committee on Directors.
Beverly L. Hamilton, 53	Mrs. Hamilton is President, ARCO Investment Management Company, Los Angeles, CA, a subsidiary of Atlantic Richfield, where she has also been a Vice President since 1991. Mrs. Hamilton holds a B.A, with honors from the University of Michigan and has studied at New York University's Graduate School of Business. She is a director of United Asset Management Corp., the American Funds Emerging Markets Growth Fund, Mass Mutual's Institutional and Series Funds and The Common Fund. Mrs. Hamilton has been a Director since 1982 and is a Class II Director, last elected in 1999. She is Chair of the Pension and Investment Committee and a member of the Committee on Directors.
Harvey S. Levenson, 59	Mr. Levenson is a managing member of Hamleg Enterprises, L.L.C., Hartford, CT, a private investment company. From 1982 until 1996 he held various positions at Kaman Corporation, Bloomfield, CT, retiring as President and Chief Operating Officer in 1996. Mr. Levenson holds B.A. and J.D. degrees from Drake University and an L.L.M. from Georgetown University. He has been a Director since 1990 and is a Class II Director, last elected in 1999. Mr. Levenson is Chair of the Executive Committee and a member of the Compensation Committee.
Arthur C. Marquardt, 52	Mr. Marquardt joined the Company as President and Chief Operating Officer of CTG Resources and its subsidiaries in 1996, became Chief Executive Officer on December 1,1998 and Chairman in August, 1998. He is a director of each of the company's subsidiaries. From 1992 until he joined the Company in 1996, he was Senior Vice President-Gas Business Unit of the Long Island Lighting Company. Mr. Marquardt holds a B.S. in Mechanical Engineering from Tufts University. He has been a Director since 1996 and is a Class III Director, last elected in 1997.
Denis F. Mullane, 69	Mr. Mullane has been a Principal in Mullane Enterprises, West Hartford, CT since 1994. Mullane Enterprises provides advice to its clients about retirement, estate planning and charitable giving. In 1994 Mr. Mullane retired as Chairman of Connecticut Mutual Life after a 38-year career. He is a graduate of the U.S. Military Academy at West Point. He has been a Director since 1993 and is a Class I Director last elected in 1998. He is the Chair of the Committee on Directors and a member of Executive Committee.
Richard J. Shima, 60	Mr. Shima is a Corporate Advisor from West Hartford, CT. Mr. Shima joined Travelers Companies in 1961 and served as Vice Chairman and Chief Investment Officer until 1991. He is a graduate of Harvard University. He serves as a director of Enhance Financial Services Group, Inc., the Trust Company of Connecticut and the Evergreen Mutual Funds. Mr. Shima has been a Director since 1987 and is a Class I Director, last elected in 1998. He is the Chair of the Compensation Committee and a member of the Executive Committee.
Laurence A. Tanner, 53	Mr. Tanner has been President and Chief Executive Officer of New Britain General Hospital, New Britain, CT since 1987. He is also President and Chief Executive Officer of the Central Connecticut Health Alliance, a holding corporation for New Britain General Hospital and several affiliated corporations. Mr. Tanner has been a Director since 1993 and is a Class III Director, last elected in 1997. He is a member of the Compensation Committee and the Pension and Investment Committee.
Michael W. Tomasso, 46	Mr. Tomasso has been a Principal in Tomasso Brothers, Inc., New Britain, CT since 1993. He holds a B.A. from Tufts University and a M.B.A. from Babson College. He has been a Director since 1996 and is a Class I Director, last elected in 1998. He is a member of the Pension and Investment Committee and the Audit Committee.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company's executive officers and directors as well as persons who own more than 10 percent of a registered class of the Company's equity securities, to file reports of ownership and changes of ownership with the Securities and Exchange Commission and the New York Stock Exchange. Based solely on the Company's review of the copies of such forms received or written representations from certain reporting persons that no reporting was required, the Company believes during fiscal year 1999 all filing requirements were met.

ITEM 11. EXECUTIVE COMPENSATION

(a) Compensation of Directors

The directors' annual retainer fee is $10,000 in cash and 200 shares of common stock of the Company plus $800 for each Board or committee meeting attended. A chairperson of a committee receives $850 for each committee meeting chaired in lieu of $800. A plan of deferred compensation for services as a director is made available to directors. No director who also is an employee of the Company receives any fees or common stock of the Company for service on the Board.

(b) Compensation Committee Interlocks and Insider Participation

The members of the Compensation Committee for fiscal year 1999 were Messrs. Shima (Chair), Levenson, Fonteyne and Tanner. All four are non-employee directors and none has any direct or indirect material interest in or relationship with the Company outside of his position as director.

(c) Summary Executive Compensation

The following table provides certain information concerning total compensation received for services rendered to the Company in all capacities during the period October 1, 1996 to September 30, 1999 by the Chief Executive Officer and the four most highly compensated executive officers who were serving as of the end of fiscal year 1999.

SUMMARY COMPENSATION TABLE

	Annual Compensation				Long Term Compensation
Name and Principal Position	Fiscal Year	Salary ($)(a)	Bonus ($)	Other Annual Comp. ($)(b)	Securities Underlying Options (#) (c) +	LTIP Payouts ($)(d)	All Other Comp. ($)(e)

Arthur C. Marquardt	1999	305,000	65,250	-	16,600	-	114,408
Chairman, President and Chief	1998	278,745	-	-	-	-	172,172
Executive Officer	1997	228,551	76,731	-	-	-	14,953

James P. Laurito*	1999	190,177	42,900	-	8,000		25,745
President , The Energy Network	1998	141,803	20,000	-	-	-	13,663
	1997	-	-	-	-	-	-

James P. Bolduc	1999	188,600	42,000	-	5,000	-	44,605
Executive Vice President	1998	185,833	37,850	-	-	-	76,297
and Chief Financial Officer	1997	180,333	64,323	-	-	-	63,207

Anthony C. Mirabella	1999	148,267	29,400	14,029	3,500	-	31,315
Senior Vice President-DH&C	1998	146,250	11,355	13,988	-	-	42,330
The Energy Network	1997	142,250	20,220	13,142	-	-	34,996

Reginald L. Babcock	1999	143,000	21,600	-	5,000	-	27,563
Vice President, General	1998	138,000	-	-	-	-	46,158
Counsel and Secretary	1997	137,267	19,506	-	-	-	45,088

* Mr. Laurito joined the Company on September 15, 1997.

a) For fiscal year 1999, the amount reported in this column includes $59,465 deferred at the election of Mr. Marquardt and $266 deferred at the election of Mr. Laurito.

b) Represents amount reimbursed to the named officer by the Company for the payment of taxes resulting from such officer's participation in the Executive Life Insurance Program.

c) Number of common shares underlying stock option award at date of grant.

d) For fiscal year 1999 no awards vested pursuant to the Executive Restricted Stock Plan. The number and value of aggregate unvested restricted stock holdings including dividends reinvested as of September 30, 1999 for each of the listed officers was as follows: Mr. Marquardt 12,741 shares, $450,713 value; Mr. Laurito 812 shares, $28,725 value; Mr. Bolduc 8,116 shares, $287,104 value; Mr. Mirabella 4,390 shares, $155,296 value; Mr. Babcock 4,427 shares, $156,605 value. Values are calculated based on the share price of $35.375 on September 30, 1999, however, a portion of these restricted stock shares were forfeited pursuant to the performance features of the Executive Restricted Stock Plan on October 1, 1999. The total aggregate holdings (including restricted stock shares) of each of the listed officers as of November 1, 1999 is shown in the table in Item 12 listing beneficial ownership of Company stock.

e) For fiscal year 1999 amounts reported in this column consist of the following: for Mr. Marquardt $14,709 - unvested dividends earned on restricted stock as of September 30, 1999, $6,895 - 401(k) Plan, $60,584 - Executive Life Insurance plan, $6,363 - Deferred Compensation Plan B, moving expenses - $25,857; for Mr. Laurito $ 424-unvested dividends earned on restricted stock as of September 30, 1999, $5'258 - 401K Plan, $20,063- Executive Life Insurance Plan; for Mr. Bolduc $9,777- unvested dividends earned on restricted stock as of September 30, 1999, $7,273 - 401(k) Plan, $26,358 - Executive Life Insurance Plan, $1,197 - Deferred Compensation Plan B; for Mr. Mirabella $5,230 - unvested dividends earned on restricted stock as of September 30, 1999, $6,672 - 401(k) Plan, $19,413 - Executive Life Insurance Plan; for Mr. Babcock $5,165 - unvested dividends earned on restricted stock as of September 30, 1999, $6,435 - 401(k) Plan, $15,963 - Executive Life Insurance Plan.

Under the Executive Life Insurance Program, split dollar life insurance is provided to officers by the Company which pays the entire amount of the premiums due on the policies but is reimbursed for the aggregate amount of all such premiums out of the proceeds of the policies upon the death of the covered executives. The amounts set forth above represent the full amount of the annual premiums paid on behalf of the named executive officers.

(d) Option Grants in the Last Fiscal Year

The following table sets forth, as to the named officers, information concerning stock options granted during the year ended September 30, 1999.

Individual Grants						Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term (4)
(a) Name	(b) Number of Securities Underlying Options Granted (1)	(c) % of Total Options Granted to Employees in Fiscal Year (2)	(d) Exercise or Base Price	(e) Expiration Date (3)	(f) 5% ($)		(g) 10% ($)
Arthur C. Marquardt	16,600	25.70%	$23.125	2/22/09	241,841		610,361
James P. Laurito	8,000	12.38%	$23.125	2/22/09	116,550		294,150
James P. Bolduc	5,000	7.75%	$23.125	2/22/09	72,844		183,844
Anthony C. Mirabella	3,500	5.42%	$23.125	2/22/09	50,991		128,691
Reginald L. Babcock	5,000	7.75%	$23.125	2/22/09	72,844		183,844

(1) The options in this table were granted under the 1999 Stock Option Plan and have 10 year terms. All grants were made on February 23, 1999. The exercise price is equal to the fair market value on the date of grant. The options vest as follows: 50% two years from date of grant, 75% at three years from date of grant and 100% at 4 years from date of grant. The grants will vest and be exercisable upon a Change of Control.

(2) CTG granted options to purchase 64,600 shares of common stock to employees in fiscal 1999.

(3) The options in this table may terminate before their expiration date upon the termination of optionee's status as an employee or upon optionee's disability or death.

(4) Under rules promulgated by the Securities and Exchange Commission, the amounts in these two columns represent the hypothetical gain or "option spread" that would exist for the options in this table based on assumed stock price appreciation from the date of grant until the end of such options' ten-year term at assumed annual rates of 5% and 10%. Annual compounding results in total appreciation of 63% (at 5% per year) and 159% (at 10% per year). If the price of CTG's common stock were to increase at such rates from the price at 1999 year end ($35.375 per share) over the next 10 years, the resulting stock price at 5% and 10% appreciation would be $57.66125 and $91.62125, respectively. The 5% and 10% assumed annual rates of appreciation are specified in the Commission's rules and do not represent the Company's estimate or projection of future stock price growth. CTG does not necessarily agree that this method can properly determine the value of an option.

The 1999 Stock Option Plan provides that, in the event of a Change in Control, the value of all outstanding options shall be cashed out at an amount equal to the excess of (x) the Change in Control Price (as defined in the Stock Option Plan) over (y) the exercise price of the Common Stock covered by the option. The Plan defines Change in Control Price as (i) the highest fair market value at any time within the 60-day period immediately preceding the date of determination of the Change in Control Price by the Board of Director (the "Sixty- Day Period"), or the highest price paid or offered as determined by the Board, in any bona fide transaction or bona fide offer related to the Change of Control, at any time within the Sixty-Day Period.

(e) Retirement Plans

The Company maintains two noncontributory defined benefit retirement plans that provide benefits for certain employees (except for employees covered by certain collective bargaining agreements) who have completed one year of continuous service and have met certain age requirements. One such plan is qualified under the applicable provisions of the Internal Revenue Code (the "Pension Plan"), and the other is a nonqualified supplemental Officers Retirement Plan (the "Officers Retirement Plan").

Under the Pension Plan, retirement benefits are computed by multiplying the average of the employee's five highest years of annual pensionable earnings out of the last 15 by a specified formula determined with reference to years of credited service. Benefits accrue at 1.25% of earnings not in excess of social security covered compensation, plus 1.65% of earnings in excess of social security covered compensation, times credited service up to 35 years; plus 1.25% of earnings times credited service in excess of 35 years. If, as of May 1, 1998, the employee had reached age 55 and completed 5 years of service or had completed 25 years of service, benefits will be determined under the prior "grandfathered" formula. Under that formula, benefits accrue at 2 percent per year of service up to 30 years of service and thereafter an additional 1 percent per year up to 35 years for a maximum accrual of 65 percent. Benefits under the "grandfathered" formula are offset by a portion of the employee's social security benefits. The plan provides for several optional forms of benefit payments, including a straight life annuity, various joint and survivor options, and a continuous and certain benefit option. Employees are fully vested under the Pension Plan after five years of continuous service with the Company or following a change of control.

The Officers Retirement Plan operates in conjunction with and as a supplement to the Pension Plan. The benefits payable under the Officers Retirement Plan are calculated as continuous and certain benefits for unmarried individuals, and as joint and survivor benefits for married individuals. Benefits paid under the Officers Retirement Plan are based on the highest rate of annual base salary paid to the officer at any time throughout his or her career. For purposes of the Officers Retirement Plan, the salary upon which benefits are based excludes compensation received pursuant to the Annual Incentive Plan, which amounts are reflected in the bonus category of the Summary Compensation Table above. An officer is eligible to receive 60 percent of base salary at age 60 and for officers with more than 25 years of service there is an additional 1 percent accrual for each year up to 30 for a maximum accrual of 65 percent. Such benefits are offset by 50 percent of social security benefits payable to each participant, and by the benefits computed under all other defined benefit pension plans to which the officer is entitled from the Company or from previous employment. Also, no officer's benefit (when combined with benefits under the Pension Plan) will be less than the benefit that would be received under the Pension Plan formula as determined without regard to the application of any Internal Revenue Service limitations on compensation or benefits payable from a qualified plan in determining the benefit level. In the case of any officer who has been employed by the Company for less than fifteen years at the time of retirement, any benefits under the Officers Retirement Plan are adjusted in proportion that such officer's years of service are to fifteen. Officers who terminate employment on or after May 25, 1999, and also on or after attaining age 55 and completion of 10 years of service, are also entitled to benefits reduced for early retirement. In the event of a change of control, officers participating in the Officers Retirement Plan are vested under the Plan even if their employment terminates prior to age 60, or age 55 with 10 years of service.

The credited years of service as of September 30, 1999, for the five individuals named in the Summary Compensation Table are as follows: Mr. Marquardt, 3 years; Mr. Laurito, 2 years, Mr. Bolduc, 31 years; Mr. Mirabella, 28 years; and Mr. Babcock, 20 years. The estimated annual benefits payable upon retirement under the plans are as follows: Mr. Marquardt, $151,264; Mr. Laurito $109,026, Mr. Bolduc, $171,778; Mr. Mirabella, $107,722; Mr. Babcock, $98,024.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following shows common stock beneficially owned by (1) each director and (2) each of the executive officers listed in the Summary Compensation Table above and (3) all directors and executive officers as a group as of November 1, 1999.

Title of Class	Name of Beneficial Owner	Amount and Nature of ;Beneficial Ownership*	Percent of Class
Common Stock	Bessye W. Bennett	1,172	0.01%
Common Stock	Herman J. Fonteyne	3,529	0.04%
Common Stock	Victor F. Frauenhofer	35,484	0.41%
Common Stock	Beverly L. Hamilton	1,647	0.02%
Common Stock	Harvey S. Levenson	6,976	0.08%
Common Stock	Denis F. Mullane	2,412	0.03%
Common Stock	Richard J. Shima	10,031	0.12%
Common Stock	Lawrence A. Tanner	2,730	0.03%
Common Stock	Michael W. Tomasso	2,287	0.03%
Common Stock	Arthur C. Marquardt	12,472	0.14%
Common Stock	James P. Laurito	1,045	0.01%
Common Stock	James P. Bolduc	14,074	0.16%
Common Stock	Anthony C. Mirabella	13,930	0.16%
Common Stock	Reginald L. Babcock	9,256	0.11%

            Title of Class

Amount Beneficially Owned by
all Executive Officers and
                    Directors

            Common Stock

117,043

*Unless otherwise indicated, each person listed in the table has the sole voting and investment power with respect to all shares shown as beneficially owned by him or her.

The percentage of shares owned by all officers and directors as a group is 1.4 percent of the Company's common stock.

The Company is aware of no shareholders who owned beneficially more than 5 percent of a class of its voting securities on November 1, 1999.

Change of Control

The Company has entered into an Agreement and Plan of Merger with Energy East Corporation and Oak Merger Co. dated as of June 29, 1999, whereby the Company will merge with and into Oak Merger Co., a wholly owed subsidiary of Energy East Corporation. The merger has been approved by the shareholders of the Company. The merger is contingent, among other things, on the approval of the Connecticut Department of Public Utility Control and the Securities and Exchange Commission. These approvals are expected to be obtained by mid-year 2000.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Employment Agreements

The Company has entered into Change of Control Employment Agreements ("Agreements") with its Chief Executive Officer, Mr. Marquardt, and eight other officers of the Company, including Messrs. Babcock, Bolduc, Laurito and Mirabella. The Agreements become effective upon a Change of Control (as defined therein) and provide that for a period of two or three years following a Change of Control, in the event of termination of a covered executive's employment without cause or for good reason by the executive, the covered executive is entitled to a lump sum severance payment of either two or three times his or her annual salary and annual bonus, together with pension credit and continued welfare benefits. The Agreements also provide for an additional payment to make the executives whole for any excise taxes imposed by Section 4999 of the Internal Revenue Code on payments made to them that are contingent on a Change of Control. CTG's merger with Energy East Corporation will constitute a Change of Control under these Agreements.

Certain Business Relationships of Directors

Not applicable.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) 1.	Financial Statements:
	The consolidated balance sheets, statements of income, statements of cash flows, statements of capitalization and statements of common stock equity, together with the notes to the financial statements and report thereon of Arthur Andersen LLP dated October 26, 1999, are included in Part II, Item 8 herein.
2.	Financial Statement Schedules:
	The following financial statement schedules included herein under Item 14(d) are filed as part of this report.
	II Valuation and Qualifying Accounts and Reserves for the fiscal years ended September 30, 1999, 1998 and 1997
	Schedules I, III, IV, and V are not submitted because they are not applicable or the information required to be included therein is contained in the financial statements and footnotes.
3.	Exhibits
Exhibit Number
2	Plan of acquisition, reorganization, arrangement, liquidation or succession
2(1)	Agreement and Plan of Merger, dated as of June 29, 1999, by and among CTG Resources, Inc., Energy East Corporation and Oak Merger Co., filed as Exhibit 2.1 to the CTG Resources, Inc.'s Current Report on Form 8-K, filed with the Commission on June 30, 1999 (Commission File No.1-12859)
3	Articles of Incorporation and By-Laws
3(1)	Amended and Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
3(2)	Amended and Restated By-Laws of the Company, filed as Exhibit No. 3.2 to the Company's Company's Quarterly Report on Form 10-Q, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
4	Instruments Defining Rights of Security Holders, Including Indentures
4(1)	Indenture of Mortgage and Deed of Trust between The Hartford Gas Company and The First National Bank of Hartford, Trustee dated February 1, 1947, filed as Exhibit No. 2.2 to the Connecticut Natural Gas Corporation's Registration Statement on Form S-7 filed with the Commission on December 8, 1970 (Commission File No. 2-38993)
4(2)	In addition to the Indenture of Mortgage and Deed of Trust referred to in 4(1) above, there have been sixteen supplemental indentures thereto, all of which have been filed with the Commission as follows:
	(a) Supplemental indentures 1-9 filed as Exhibit No. 2.2 to the Connecticut Natural Gas Corporation's Registration Statement on Form S-7 filed with the Commission on December 8, 1970 (Commission File No. 2-38993)
4(2)	(b) Tenth Supplemental Indenture filed as Exhibit No. 2.3 to the Connecticut Natural Gas Corporation's Registration Statement on Form S-7 filed with the Commission on March 3, 1972 (Commission File No. 2-43286)
	(c) Eleventh Supplemental Indenture filed as Exhibit No. V to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1974, filed with the Commission in March, 1975 (Commission File No. 1-7727)
	(d) Twelfth Supplemental Indenture filed as Exhibit No. 4(h) to the Connecticut Natural Gas Corporation's Registration Statement on Form S-7 filed with the Commission on December 23, 1981 (Commission File No. 2-75457)
	(e) Thirteenth Supplemental Indenture filed as Exhibit No. 4 to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1982, filed with the Commission in August, 1982 (Commission File No. 1-7727)
	(f) Fourteenth Supplemental Indenture filed as Exhibit No. 4(iii) to the Connecticut Natural Gas Corporation's Current Report on Form 8-K, dated August 28, 1986, filed with the Commission in September, 1986 (Commission File No. 1-7727)
	(g) Fifteenth Supplemental Indenture filed as Exhibit No. 4(iii) to the Connecticut Natural Gas Corporation's Current Report on Form 8-K, dated December 8, 1987, filed with the Commission in December, 1987 (Commission File No. 1-7727)
	(h) Sixteenth Supplemental Indenture filed as Exhibit No. 4(ii)(h) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, filed with the Commission in November, 1989 (Commission File No. 1-7727)
4(3)	Rights Agreement (including a Form of Certificate of Adoption of Amendment to the Amended and Restated Articles of Incorporation of the Company as Exhibit A thereto, a Form of Right Certificate as Exhibit B thereto and a Summary of Rights to Purchase Preferred Stock as Exhibit C thereto), filed as Exhibit 4.1 to the CTG Resources, Inc.'s Registration Statement on Form 8-A, filed with the Commission on December 1, 1998 (Commission File No.1-12859)
4(4)	Amendment to Rights Agreement, dated as of June 29, 1999, between CTG Resources, Inc. and ChaseMellon Shareholder Services, L.L.C., as Rights Agent, filed as Exhibit 4.1 to the CTG Resources, Inc.'s Current Report on Form 8-K, filed with the Commission on June 30, 1999 (Commission File No.1-12859)
4(5)	CTG Resources, Inc. 1999 Stock Option Plan, filed as Exhibit A to the CTG Resources, Inc.'s Definitive Proxy for the CTG Resources, Inc. Annual Meeting of Shareholders on February 23, 1999, filed with the Commission on December 29, 1998 (Commission File No.1-12859)
9	Voting Trust Agreement
	Not applicable

10	Material Contracts
	Natural Gas Supply, Storage and Transportation
10(1)	Canadian gas transportation contract (rate schedule CGT-NE) between the Connecticut Natural Gas Corporation and Tennessee, dated December 1, 1987, filed as Exhibit No. 10(xxiii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1987, filed with the Commission on March 29, 1988 (Commission File No. 1-7727)
10(2)	Gas purchase contract between the Connecticut Natural Gas Corporation and TransCanada Pipelines Limited, dated September 14, 1987, filed as Exhibit No. 10(xxiv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1987, filed with the Commission on March 29, 1988 (Commission File No. 1-7727)
10(3)	Gas sales agreement between the Connecticut Natural Gas Corporation and Boundary Gas, Inc., dated September 14, 1987, filed as Exhibit No. 10(xxv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1987, filed with the Commission on March 29, 1988 (Commission File No. 1-7727)
10(4)	Precedent Agreement to First Amendment, dated September 14, 1988, to the Gas Sales Agreement between the Connecticut Natural Gas Corporation and Boundary Gas, Inc., dated September 14, 1987, filed as Exhibit No. 10(xxxi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1989, filed with the Commission March 28, 1990 (Commission File No. 1-7727)
10(5)	First Amendment, dated January 1, 1990, to the Gas Sales Agreement between the Connecticut Natural Gas Corporation and Boundary Gas, Inc., dated September 14, 1987, filed as Exhibit 10(xxxii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1989, filed with the Commission on March 28, 1990 (Commission File No. 1-7727)
10(6)	Amendment to Phase 2 Gas Sales Agreement, dated August 20, 1997, between the Connecticut Natural Gas Corporation and Boundary Gas, Inc., filed as Exhibit No. 10(108) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(7)	Gas Transportation Contract for Firm Reserved Service, dated February 7, 1991, between the Connecticut Natural Gas Corporation and the Iroquois Gas Transmission System, L.P., filed as Exhibit No. 10(xxxvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(8)	Gas Sales Agreement No. 1, dated February 7, 1991, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(xxxviii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(9)	Amendment to ANE Gas Sales Agreement No. 1, dated August 19, 1997, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(106) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(10)	Gas Sales Agreement No. 2, dated February 7, 1991, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(xxxix) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(11)	Amendment to ANE Gas Sales Agreement No. 2, dated August 19, 1997, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(107) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(12)	Gas Sales Agreement (ProGas), dated February 7, 1991, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(xl) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(13)	Gas Sales Agreement (ATCOR), dated February 7, 1991, between the Connecticut Natural Gas Corporation and Alberta Northeast Limited, filed as Exhibit No. 10(xli) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(14)	Gas Sales Agreement (AEC), dated February 7, 1991, between the Connecticut Natural Gas Corporation and Alberta Northeast Gas Limited, filed as Exhibit No. 10(xlii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(15)	Gas Transportation Contract for Firm Reserved Service, dated October 20, 1992, between the Connecticut Natural Gas Corporation and the Iroquois Gas Transmission System, L.P., filed as Exhibit No. 10(xlvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1992, filed with the Commission on December 23, 1992, (Commission File No. 1-7727)
10(16)	Service Agreement #89102 (Rate Schedule AFT-1), dated June 1, 1993, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(xxxviii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(17)	Service Agreement #93205 (Rate Schedule AFT-1), dated June 1, 1993, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(xl) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(18)	Service Agreement #.6426, dated June 1, 1993, between the Connecticut Natural Gas Corporation and Transcontinental Gas Pipe Line Corporation, filed as Exhibit No. 10(xlv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(19)	Service Agreement (Rate Schedule FTNN), dated October 1, 1993, between the Connecticut Natural Gas Corporation and CNG Transmission Corporation, filed as Exhibit No. 10(liii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(20)	Service Agreement (Rate Schedule GSS), dated November 1, 1993, between the Connecticut Natural Gas Corporation and CNG Transmission Corporation, filed as Exhibit No. 10(liv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(21)	Gas Storage Contract, dated February 16, 1990, between the Connecticut Natural Gas Corporation and ENDEVCO Industrial Gas Sales Company, filed as Exhibit No. 10(lxix) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(22)	Service Agreement #86006 (Rate Schedule AFT-1), dated September 1, 1994, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(lxxi) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, filed with the Commission August 2, 1995 (Commission File No. 1-7727)
10(23)	Service Agreement #93005 (Rate Schedule AFT-1), dated September 1, 1994, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(lxxii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, filed with the Commission August 2, 1995 (Commission File No. 1-7727)
10(24)	Service Agreement #9B103 (Rate Schedule AFT-1), dated September 1, 1994, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(lxxiii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, filed with the Commission August 2, 1995 (Commission File No. 1-7727)
10(25)	Service Agreement #9W005 (Rate Schedule AFT-1), dated September 1, 1994, between the Connecticut Natural Gas Corporation and Algonquin Gas Transmission Company, filed as Exhibit No. 10(lxxiv) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1995, filed with the Commission August 2, 1995 (Commission File No. 1-7727)
10(26)	Gas Storage Agreement No. 1626 (Rate Schedule FS), dated September 1, 1993, by and between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxix) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(27)	Gas Transportation Agreement No. 2498 (Rate Schedule FT-A), dated September 1, 1993, by and between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxx) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(28)	Gas Transportation Agreement No. 3900 (Rate Schedule FT-A), dated October 1, 1993, by and between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxxi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(29)	Gas Transportation Agreement No. 3901 (Rate Schedule FT-A), dated October 1, 1993, by and between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxxii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(30)	Gas Transportation Agreement No. 2075 (Rate Schedule FT-A), dated September 1, 1993, by and between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxxiii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(31)	Gas Transportation Agreement (FT-A Rate Schedule, Service Package No. 86) dated September 1, 1993, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxxxviii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(32)	Gas Transportation Agreement (FT-A Rate Schedule, Service Package No. 1625) dated September 1, 1993, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(lxxxix) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(33)	Gas Transportation Agreement (FT-A Rate Schedule, Service Package No. 2655) dated September 1, 1993, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(xc) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(34)	Gas Storage Contract (Rate Schedule FS, Service Package No. 1626) dated December 1, 1994, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(xciii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(35)	Amendment No.1-A to Gas Storage Contract (Rate Schedule FS, Service Package No. 1626) dated July 1, 1995 between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(xciv) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(36)	Service Agreement (#N01719, FST Service) dated March 28, 1996 between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation, filed as Exhibit No. 10(xcv) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(37)	Amendment No. 1 to Service Agreement (#N01719, FST Service) dated April 1, 1996, between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation, filed as Exhibit No. 10(xcvi) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(38)*	Amendment No. 2 to Service Agreement (#N01719, FST Service) dated June 10, 1999, between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation
10(39)	Service Agreement (#O01718, FSS Service) dated March 28, 1996 between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation, filed as Exhibit No. 10(xcvii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(40)	Amendment No. 1 to Service Agreement (#O01718, FSS Service) dated April 1, 1996, between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation, filed as Exhibit No. 10(xcviii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, filed with the Commission July 29, 1996 (Commission File No. 1-7727)
10(41)*	Amendment No. 2 to Service Agreement (#O01718, FSS Service) dated June 10, 1999, between the Connecticut Natural Gas Corporation and National Fuel Gas Supply Corporation
10(42)	Service Agreement (#400507, Rate Schedule FSS-1), dated November 15,1996, between the Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(civ) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(43)	Service Agreement (#800424, Rate Schedule CDS), dated November 15, 1996, between the Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(cvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(44)	Storage Service Agreement (#300094, Rate Schedule GSS), dated April 1, 1997, between the Connecticut Natural Gas Corporation and CNG Transmission Corporation, filed as Exhibit No. 10(109) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(45)	Seasonal Transportation Service Agreement (#200106, Rate Schedule FT), dated April 1, 1997, between the Connecticut Natural Gas Corporation and CNG Transmission Corporation, filed as Exhibit No. 10(110) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(46)	Storage Service Agreement (#1623, Rate Schedule SS-NE), dated September 1, 1993, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(111) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(47)	Transportation Service Agreement (#1627, Rate Schedule FT-A), dated September 1, 1993, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(112) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(48)	Transportation Service Agreement (#10781, Rate Schedule FT-A), dated June 1, 1995, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(113) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(49)	Amended Transportation Service Agreement (#10781, Rate Schedule FT-A), dated November 21, 1996, between the Connecticut Natural Gas Corporation and Tennessee Gas Pipeline Company, filed as Exhibit No. 10(114) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(50)	Service Agreement (#830035, Rate Schedule FT-1), dated November 15, 1996, between the Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(116) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(51)	Service Agreement (#400223, Rate Schedule SS-1), dated November 15, 1996, between the Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(117) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(52)	Service Agreement (#800294R, Rate Schedule FT-1), dated May 20, 1998, between Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(128) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)
10(53)	Service Agreement (#800295R, Rate Schedule FT-1), dated May 20, 1998, between Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(129) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)
10(54)	Service Agreement (#830047, Rate Schedule FT-1), dated May 20, 1998, between Connecticut Natural Gas Corporation and Texas Eastern Transmission Corporation, filed as Exhibit No. 10(130) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)

	District Heating and Cooling
10(55)	Steam Supply Agreement between The Hartford Steam Company and Independent Energy Operations, Inc., dated December 3, 1987, filed as Exhibit No. 10(xxv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended December 31, 1989, filed with the Commission on March 28, 1990 (Commission File No. 1-7727)
10(56)	Steam and Chilled Water Supply Agreement, dated May 28, 1986, between Capitol District Energy Center Cogeneration Associates and Energy Networks, Incorporated, filed as Exhibit No. 10(xxxvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1993, filed with the Commission December 28, 1993 (Commission File No. 1-7727)
10(57)	Asset Purchase Agreement, dated June 26, 1998, by and among The Hartford Steam Company, CCF-1, Inc. and Kenetech Facilities Management, Inc., filed as Exhibit No. 10(55) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1998, filed with the Commission on December 2, 1998 (Commission File No. 1-12859)
10(58)	Assignment and Consent, dated June 26, 1998, by and among The Hartford Steam Company, CCF-1, Inc. and The Connecticut Light and Power Company, filed as Exhibit No. 10(56) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1998, filed with the Commission on December 2, 1998 (Commission File No. 1-12859)
10(59)	Memorandum of Agreement, dated October 23, 1998, among The Energy Network, Inc., Pratt & Whitney Canada Inc., Oxford Technologies, Inc. and Carrier Corporation, filed as Exhibit No. 10(126) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
10(60)	Independent Consulting Agreement, dated December 23, 1998, between The Energy Network, Inc. and Oxford Technologies, Inc., filed as Exhibit No. 10(127) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
10(61)	District Heating and Cooling Service Agreement, dated April 6, 1999, between the Energy Network, Inc. and the City of Hartford, filed as Exhibit No. 10(147) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)

	Financing
10(62)	Capital Contribution Support Agreement, dated April 15, 1993, among Connecticut Natural Gas Corporation, ENI Transmission Company and Bank of Montreal, filed as Exhibit No. 10(l) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1993, filed with the Commission on August 3, 1993 (Commission File No. 1-7727)
10(63)	Secured Note Purchase Agreement, dated July 15, 1993, between the CNG Realty Corp. and the Aid Association for Lutherans, filed as Exhibit No. 10(xlix) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 1993, filed with the Commission on August 3, 1993 (Commission File No. 1-7727)
10(64)	Three-year Revolving Credit Agreement between TEN and Fleet National Bank, filed as Exhibit No. 99(B)(2) to the CTG Resources, Inc.'s Issuer Tender Offer Statement on Schedule 13E-4, filed with the Commission on October 2, 1997 (Commission File No. 5-51659)
10(65)	364-Day Revolving Credit Agreement between and TEN and Fleet National Bank, filed as Exhibit No. 99(B)(3) to the CTG Resources, Inc.'s Issuer Tender Offer Statement on Schedule 13E-4, filed with the Commission on October 2, 1997 (Commission File No. 5-51659)
10(66)	Amendment to the 364-day Revolving Credit Agreement, dated December 8, 1999, between The Energy Network, Inc. and Fleet National Bank, filed as Exhibit No. 10(128) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
10(67)	Reimbursement Agreement (Including Irrevocable Letter of Credit), dated August 1, 1998, between The Energy Network, Inc. and Fleet National Bank, filed as Exhibit No. 10(61) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1998, filed with the Commission on December 2, 1998 (Commission File No. 1-12859)
10(68)	Note Purchase Agreement among TEN, Metropolitan Life Insurance Company and Texas Life Insurance Company, filed as Exhibit No. 99(B)(4) to the CTG Resources, Inc.'s Issuer Tender Offer Statement on Schedule 13E-4, filed with the Commission on October 2, 1997 (Commission File No. 5-51659)
10(69)	Note Purchase Agreement, dated October 14, 1998, between The Energy Network, Inc. and Metropolitan Life Insurance Company, filed as Exhibit No. 10(63) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1998, filed with the Commission on December 2, 1998 (Commission File No. 1-12859)
10(70)	Revolving Credit Agreement, dated March 30, 1993, between the Connecticut Natural Gas Corporation and The First National Bank of Boston, filed as Exhibit No. 10(xlviii) to the Connecticut Natural Gas Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1993, filed with the Commission on May 3, 1993 (Commission File No. 1-7727)
10(71)	First Amendment to Credit Agreement, dated March 30, 1998, among Connecticut Natural Gas Corporation and BankBoston, N.A., filed as Exhibit No. 10(124) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)
10(72)	Medium Term Notes, Series A, Placement Agency Agreement among Connecticut Natural Gas Corporation, PaineWebber Incorporated and Smith Barney, Harris Upham & Co. Incorporated, dated November 1, 1991, filed as Exhibit No. 10(xxxix) to the Connecticut Natural Gas Corporation's Transition Report on Form 10-K for the period October 1, 1990 to September 30, 1991, filed with the Commission on December 23, 1991, (Commission File No. 1-7727)
10(73)	Issuing and Paying Agency Agreement between The Connecticut National Bank and Connecticut Natural Gas Corporation, for the Medium Term Notes, Series A, dated November 1, 1991, filed as Exhibit No. 10(xl) to the Connecticut Natural Gas Corporation's Transition Report on Form 10-K for the period October 1, 1990 to September 30, 1991, filed with the Commission on December 23, 1991, (Commission File No. 1-7727)
10(74)	Medium Term Notes, Series B, Placement Agency Agreement among Connecticut Natural Gas Corporation, Smith Barney Inc., and A.G. Edwards & Sons, Inc., dated June 14, 1994, filed as Exhibit No. 10(lxvi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(75)	Medium Term Notes, Series B, Amended and Restated Placement Agency Agreement among Connecticut Natural Gas Corporation, PaineWebber Incorporated, and A.G. Edwards & Sons, Inc., dated August 13, 1997, filed as Exhibit No. 10(119) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(76)	Issuing and Paying Agency Agreement between Shawmut Bank Connecticut, National Association, and Connecticut Natural Gas Corporation, for Medium Term Notes, Series B, dated June 14, 1994, filed as Exhibit No. 10(lxvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(77)	First Amendment to Issuing and Paying Agency Agreement, dated August 13, 1997, filed as Exhibit No. 10(118) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1997, filed with the Commission on December 19, 1997 (Commission File No. 1-12859)
10(78)	Forward Equity Purchase Agreement, dated October 1, 1997, between CTG and TEN, filed as Exhibit No. 99(c) to the CTG Resources, Inc.'s Issuer Tender Offer Statement on Schedule 13E-4, filed with the Commission on October 2, 1997 (Commission File No. 5-51659)
10(79)	First Amendment to the Forward Equity Purchase Agreement, dated October 14, 1998, between CTG Resources, Inc. and The Energy Network, Inc., filed as Exhibit No. 10(73) to the CTG Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended September 30, 1998, filed with the Commission on December 2, 1998 (Commission File No. 1-12859)

	Employment, Compensation and Benefits
10(80)	Connecticut Natural Gas Corporation Executive Restricted Stock Plan, filed as Exhibit A to the Connecticut Natural Gas Corporation's definitive proxy statement dated March 26, 1991, filed with the Commission on March 26, 1991 (Commission File No. 1-7727)
10(81)	First Amendment to Connecticut Natural Gas Corporation Executive Restricted Stock Plan, dated March 25, 1997, filed as Exhibit No. 10(cxiv) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(82)	First Amendment to Connecticut Natural Gas Corporation Executive Restricted Stock Plan, dated May 17, 1999, filed as Exhibit No. 10(136) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(83)	Second Amendment to Restricted Stock Agreement (Under the Connecticut Natural Gas Corporation Executive Restricted Stock plan), dated June 27, 1995, filed as Exhibit No. 10(lxxxii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(84)	Third Amendment to Restricted Stock Agreement (Under the Connecticut Natural Gas Corporation Executive Restricted Stock plan), dated June 27, 1995, filed as Exhibit No. 10(lxxxiii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(85)	First Amendment to Restricted Stock Agreement (Under the Connecticut Natural Gas Corporation Executive Restricted Stock Plan), dated April 27, 1999, filed as Exhibit No. 10(137) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(86)	Connecticut Natural Gas Corporation Officers' Retirement Plan (As Amended and Restated Effective As Of March 31, 1999), dated May 17, 1999, filed as Exhibit No. 10(138) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(87)	First Amendment to Connecticut Natural Gas Corporation Officers' Retirement Plan, dated June 21, 1999, filed as Exhibit No. 10(139) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(88)	The Connecticut Natural Gas Corporation Officers' Retirement Plan Trust Agreement, dated January 9, 1989, filed as Exhibit No. 10(liv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(89)	First Amendment to the Connecticut Natural Gas Corporation Officers' Retirement Plan and Deferred Compensation Plan Trust Agreement, dated August 5, 1993, filed as Exhibit No. 10(lv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(90)	Third Amendment to The Connecticut Natural Gas Corporation Officers' Retirement Plan and Deferred Compensation Plan Trust Agreement, dated September 12, 1995, filed as Exhibit No. 10(lxxxi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(91)	Fourth Amendment to The Connecticut Natural Gas Corporation Officers Retirement Plan and Deferred Compensation Plan Trust Agreement, dated March 25, 1997, filed as Exhibit No. 10(cxvi) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(92)	Fifth Amendment to the Connecticut Natural Gas Corporation Officers' Retirement Plan and Deferred Compensation Plan Trust Agreement, dated February 26, 1999, by and between Connecticut Natural Gas Corporation and Fleet National Bank, filed as Exhibit No. 10(131) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed with the Commission on April 30, 1999 (Commission File No. 1-12859)
10(93)	Sixth Amendment to the Connecticut Natural Gas Corporation Officers Retirement Plan Trust Agreement, dated April 27, 1999, filed as Exhibit No. 10(140) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(94)	Connecticut Natural Gas Corporation Deferred Compensation Plan, dated February 26, 1999, filed as Exhibit No. 10(132) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed with the Commission on April 30, 1999 (Commission File No. 1-12859)
10(95)	First Amendment to Connecticut Natural Gas Corporation Deferred Compensation Plan, dated March 1, 1999, filed as Exhibit No. 10(133) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed with the Commission on April 30, 1999 (Commission File No. 1-12859)
10(96)	Connecticut Natural Gas Corporation Deferred Compensation Plan Trust Agreement, between Connecticut Natural Gas Corporation and Putnam Fiduciary Trust Company, dated March 1, 1999, filed as Exhibit No. 10(134) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed with the Commission on April 30, 1999 (Commission File No. 1-12859)
10(97)	First Amendment to Connecticut Natural Gas Corporation Deferred Compensation Trust Agreement, between Connecticut Natural Gas Corporation and Putnam Fiduciary Trust Company, dated March 1, 1999, filed as Exhibit No. 10(135) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, filed with the Commission on April 30, 1999 (Commission File No. 1-12859)
10(98)	First Amendment to the Connecticut Natural Gas Corporation Deferred Compensation Plan Trust Agreement, between Connecticut Natural Gas Corporation and Putnam Fiduciary Trust Company, dated April 27, 1999, filed as Exhibit No. 10(142) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(99)	Agreement and Declaration of Trust, Connecticut Natural Gas Corporation Employee Benefit Trust, dated December 28, 1987, filed as Exhibit No. 10(lix) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(100)	First Amendment to Agreement and Declaration of Trust, Connecticut Natural Gas Corporation Employee Benefit Trust, Dated December 2, 1993, filed as Exhibit No. 10(lx) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(101)	Second Amendment to Agreement and Declaration of Trust, Connecticut Natural Gas Corporation Employee Benefit Trust, dated March 25, 1997, filed as Exhibit No. 10(cxvii) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(102)	Agreement and Declaration of Trust, Connecticut Natural Gas Corporation Union Employee Benefit Trust, dated December 2, 1993, filed as Exhibit No. 10(lxi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(103)	First Amendment to Agreement and Declaration of Trust, Connecticut Natural Gas Corporation Union Employee Benefit Trust, dated January 24, 1995, between the Connecticut Natural Gas Corporation and Fleet Bank, N.A., filed as Exhibit No. 10(xcii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)10
10(104)	CNG Annual Incentive Plan, 1994, filed as Exhibit No. 10(lxii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1994, filed with the Commission December 27, 1994 (Commission File No. 1-7727)
10(105)	Connecticut Natural Gas Corporation Employee Savings Plan, as amended and restated including first amendment, filed as exhibit 4(i) to the Connecticut Natural Gas Corporation Employee Savings Plan Registration Statement on Form S-8, filed with the Commission on July 20, 1994 (Commission File No. 33-54643)
10(106)	Second Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated June 27, 1995, filed as Exhibit No. 10(lxxvi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(107)	Third Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated October 31, 1995, filed as Exhibit No. 10(xcvi) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(108)	Fourth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated December 19, 1995, filed as Exhibit No. 10(xcvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(109)	Fifth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated February 27, 1996, filed as Exhibit No. 10(xcviii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(110)	Sixth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan (As Amended and Restated, Effective as of January 1, 1989), dated May 2, 1997, filed as Exhibit No. 10(cxviii) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(111)	Seventh Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated January 27, 1998, filed as Exhibit No. 10.120 to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed with the Commission on May 4, 1998 (Commission File No. 1-12859)
10(112)	Eighth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated May 1, 1998, filed as Exhibit No. 10.121 to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed with the Commission on May 4, 1998 (Commission File No. 1-12859)
10(113)	Ninth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated June 9, 1998, filed as Exhibit No. 10(125) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)
10(114)	Tenth Amendment to the Connecticut Natural Gas Corporation Employee Savings Plan, dated November 24, 1998, filed as Exhibit No. 10(129) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
10(115)	Eleventh Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated May 19, 1999, filed as Exhibit No. 10(143) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(116)	Twelfth Amendment to Connecticut Natural Gas Corporation Employee Savings Plan, dated June 7, 1999, filed as Exhibit No. 10(144) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(117)	Connecticut Natural Gas Corporation Employee Savings Plan Trust Agreement, including amendments thereto, filed as exhibit 4(ii) to the Connecticut Natural Gas Corporation Employee Savings Plan Registration Statement on Form S-8, filed with the Commission on July 20, 1994 (Commission File No. 33-54643)
10(118)	First Amendment to Connecticut Natural Gas Corporation Employee Savings Plan Trust Agreement, dated March 25, 1997, filed as Exhibit No. 10(cx) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(119)	Connecticut Natural Gas Corporation Union Employee Savings Plan, as amended and restated including first amendment, filed as exhibit 4(i) to the Connecticut Natural Gas Corporation Union Employee Savings Plan Registration Statement on Form S-8, filed with the Commission on July 20, 1994 (Commission File No. 33-54653)
10(120)	Second Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated January 24, 1995, filed as Exhibit No. 10(lxxvii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(121)	Third Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated June 27, 1995, filed as Exhibit No. 10(lxxviii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(122)	Fourth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated October 31, 1995, filed as Exhibit No. 10(xcix) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(123)	Fifth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated December 19, 1995, filed as Exhibit No. 10(c) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(124)	Sixth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated February 27, 1996, filed as Exhibit No. 10(ci) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(125)	Seventh Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan (As Amended and Restated, Effective as of January 1, 1989), dated May 2, 1997, filed as Exhibit No. 10(cxix) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(126)	Eighth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated January 27, 1998, filed as Exhibit No. 10.122 to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed with the Commission on May 4, 1998 (Commission File No. 1-12859)
10(127)	Ninth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated June 9, 1998, filed as Exhibit No. 10(126) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998, filed with the Commission on August 14, 1998 (Commission File No. 1-12859)
10(128)	Tenth Amendment to the Connecticut Natural Gas Corporation Union Employee Savings Plan, dated November 24, 1998, filed as Exhibit No. 10(130) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended December 31, 1998, filed with the Commission on February 16, 1999 (Commission File No. 1-12859)
10(129)	Eleventh Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated May 19, 1999, filed as Exhibit No. 10(145) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(130)	Twelfth Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan, dated June 7, 1999, filed as Exhibit No. 10(146) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)
10(131)	Connecticut Natural Gas Corporation Union Employee Savings Plan Trust Agreement, including amendments thereto, filed as exhibit 4(ii) to the Connecticut Natural Gas Corporation Union Employee Savings Plan Registration Statement on Form S-8, filed with the Commission on July 20, 1994 (Commission File No. 33-54653)
10(132)	First Amendment to Connecticut Natural Gas Corporation Union Employee Savings Plan Trust Agreement, dated March 25, 1997, filed as Exhibit No. 10(cxi) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(133)	Amended and Restated CNG Nonemployee Directors' Fee Plan, dated September 29, 1995, filed as Exhibit No. 10(lxxxiv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(134)	CNG Nonemployee Directors' Fee Plan, dated October 1, 1996, filed as Exhibit No. 10(xciii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(135)	First Amendment to CNG Nonemployee Directors' Fee Plan, dated May 2, 1997, filed as Exhibit No. 10(cxxx) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(136)	Second Amendment to CNG Nonemployee Directors' Fee Plan, dated March 24, 1998, filed as Exhibit No. 10.123 to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998, filed with the Commission on May 4, 1998 (Commission File No. 1-12859)
10(137)	CNG Nonemployee Directors' Fee Plan Trust Agreement, by and between the Connecticut Natural Gas Corporation and Fleet Bank, N.A., dated September 28, 1995, filed as Exhibit No. 10(lxxxv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1995, filed with the Commission December 18, 1995 (Commission File No. 1-7727)
10(138)	First Amendment to CNG Nonemployee Directors' Fee Plan Trust Agreement, dated October 1, 1996, between the Connecticut Natural Gas Corporation and Putnam Fiduciary Trust Company, filed as Exhibit No. 10(xciv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(139)	Second Amendment to CNG Nonemployee Directors' Fee Plan Trust Agreement, dated October 1, 1996, between the Connecticut Natural Gas Corporation and Putnam Fiduciary Trust Company, filed as Exhibit No. 10(xcv) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(140)	Third Amendment to CNG Nonemployee Directors' Fee Plan Trust Agreement, dated March 25, 1997, filed as Exhibit No. 10(cxv) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, filed with the Commission on August 14, 1997 (Commission File No. 1-12859)
10(141)	Settlement Agreement and Release of All Claims between Connecticut Natural Gas Corporation and Harry Kraiza, Jr., dated September 25, 1996, filed as Exhibit No. 10(cii) to the Connecticut Natural Gas Corporation's Annual Report on Form 10-K for the fiscal year ended September 30, 1996, filed with the Commission on December 19, 1996 (Commission File No. 1-7727)
10(142)	The Energy Network, Inc., Instrument of Adoption of Connecticut Natural Gas Corporation Officers' Retirement Plan, dated April 27, 1999, filed as Exhibit No. 10(141) to the CTG Resources, Inc.'s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999, filed with the Commission on August 6, 1999 (Commission File No. 1-12859)

11*	Computation of Consolidated Basic and Fully Diluted Earnings Per Share
12	Computation of Ratios
	Not applicable
13	Annual Report to Stockholders for the Fiscal Year Ended September 30, 1999
	Not applicable
16	Letter Regarding Change in Certifying Accountant
	Not applicable
18	Letter Regarding Change in Accounting Principles
	Not applicable
21*	Subsidiaries of the Registrant
22	Published Report Regarding Matters Submitted to Vote of Security Holders
	None
23*	Consent of Independent Public Accountants
24*	Power of Attorney
27*	Financial Data Schedule
28	Information from Reports Furnished to State Insurance Regulatory Authorities
	Not applicable
99	Additional Exhibits
99(1)*	Exhibit Index
99(2)*	Information required by Form 11-K with respect to the Connecticut Natural Gas Corporation Employee Savings Plan for the fiscal year ending December 31, 1998
99(3)*	Information required by Form 11-K with respect to the Connecticut Natural Gas Corporation Union Employee Savings Plan for the fiscal year ending December 31, 1998
All exhibits listed above which have an asterisk (*) next to the exhibit number are filed herewith. All other exhibits listed above which have previously been filed with the Securities and Exchange Commission pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, and which were designated as noted above and have not been amended, are hereby incorporated by reference.

(b)	Reports on Form 8-K
	There were no current reports filed on Form 8-K during the last quarter of fiscal 1999.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CTG RESOURCES, INC.
(Registrant)

S/ Arthur C. Marquardt
(Arthur C. Marquardt)
President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

S/ Arthur C. Marquardt (Arthur C. Marquardt)	Chairman, President and Chief Executive Officer	December 10, 1999
S/ James P. Bolduc (James P. Bolduc)	Executive Vice President and Chief Financial Officer	December 10, 1999
S/ Andrew H. Johnson (Andrew H. Johnson)	Treasurer and Chief Accounting Officer	December 10, 1999
S/ R. L. Babcock (R. L. Babcock) as Attorney-in-fact for:		December 10, 1999

Bessye W. Bennett, Esq.	Director
Herman J. Fonteyne	Director
Victor H. Frauenhofer	Director
Beverly L. Hamilton	Director
Harvey S. Levenson	Director
Denis F. Mullane	Director
Richard J. Shima	Director
Laurence A. Tanner	Director
Michael W. Tomasso	Director

CTG RESOURCES, INC.

Annual Report on Form 10-K
Schedule Index
Fiscal Year Ended September 30, 1999

Item	Description
II	Financial Statement Schedule II; Valuation and Qualifying Accounts and Reserves for the fiscal years ended September 30, 1999, 1998 and 1997

(d) Financial Statement Schedules

Page 1 of 1

CTG RESOURCES, INC. AND SUBSIDIARIES

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

FOR THE YEARS ENDED SEPTEMBER 30, 1999, 1998 AND 1997
(Dollars in Thousands)

Column A	Column B	Column C		Column D	Column E
		Additions
Description	Balance at Beginning of Period	Charged to Costs and Expenses	Charged to Other Accounts	Deductions from Reserves (1)	Balance at End of Period
YEAR ENDED SEPTEMBER 30, 1999
RESERVE DEDUCTED IN THE BALANCE SHEET FROM THE ASSET TO WHICH IT APPLIES:
Allowance for doubtful accounts -
Gas	$ 2,533	$ 5,175	$ -	$ 3,631	$ 4,077
Other	750	147	-	689	208
	$ 3,283	$ 5,322	$ -	$ 4,320	$ 4,285
YEAR ENDED SEPTEMBER 30, 1998
RESERVE DEDUCTED IN THE BALANCE SHEET FROM THE ASSET TO WHICH IT APPLIES:
Allowance for doubtful accounts -
Gas	$ 2,966	$ 4,463	$ -	$ 4,896	$ 2,533
Other (2)	473	93	650	466	750
	$ 3,439	$ 4,556	$ 650	$ 5,362	$ 3,283
YEAR ENDED SEPTEMBER 30, 1997
RESERVE DEDUCTED IN THE BALANCE SHEET FROM THE ASSET TO WHICH IT APPLIES:
Allowance for doubtful accounts -
Gas	$ 4,425	$ 3,689	$ -	$ 5,148	$ 2,966
Other	394	166	-	87	473
	$ 4,819	$ 3,855	$ -	$ 5,235	$ 3,439

Notes:
(1) Deductions From Reserves include the write-off of uncollectible accounts, net of recoveries of accounts previously written off.
(2) $650 Charged to Other Accounts represents the receivables of KBC Energy Services, Inc. (See Part I, "Diversified Businesses").

	1999	1998
Property, Plant and Equipment	$ 56,136	$ 53,297
Other, net	(692)	(3,122)
Deferred Income Taxes	$ 55,444	$ 50,175

Sinking Fund Requirements and Maturities
	Year	Total
	2000	$ 5,283
	2001	5,843
	2002	18,404
	2003	8,465
	2004	17,033
		$ 55,028

Title of Class	Amount Beneficially Owned by all Executive Officers and Directors
Common Stock	117,043