SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

 

For the fiscal year ended September 30, 2005                                                                                           Commission file number:  1-7196

 

CASCADE NATURAL GAS CORPORATION

(Exact name of Registrant as specified in its charter)

 

Washington

 

91-0599090

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

222 Fairview Avenue North

 

(206) 624-3900

Seattle, WA 98109

 

(Registrant’s telephone number

(Address of principal executive offices)

 

including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange on which Registered

Common Stock, Par Value $1 per Share

 

New York Stock Exchange

 

Securities registered pursuant to section 12(g) of the Act:  None

 

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  ý    No  o

 

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.  o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).      Yes  ý    No  o

 

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).       Yes  o    No  ý

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the close of business on September 30, 2005, was $245,876,677.

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date:

 

Title

 

Outstanding

Common Stock, Par Value $1 per Share

 

11,435,593 as of November 30, 2005

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s definitive proxy statement for its 2006 Annual Meeting of Shareholders are incorporated by reference into Part III.

 

 



 

CASCADE NATURAL GAS CORPORATION

Annual Report to the Securities and Exchange Commission on Form 10-K

For the Fiscal Year Ended September 30, 2005

 

Table of Contents

 

Part I

 

 

Item 1 - Business

 

 

Item 2 - Properties

 

 

Item 3 - Legal Proceedings

 

 

Item 4 - Submission of Matters to a Vote of Security Holders Executive Officers of the Registrant

 

 

 

 

 

Part II

 

 

Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

 

Item 6 - Selected Financial Data

 

 

Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

 

Item 7A- Quantitative and Qualitative Disclosures about Market Risk

 

 

Item 8 - Financial Statements and Supplementary Data

 

 

Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

 

Item 9A – Controls and Procedures

 

 

Item 9B – Other Information

 

 

 

 

 

Part III

 

 

Item 10 - Directors and Executive Officers of the Registrant

 

 

Item 11 - Executive Compensation

 

 

Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

 

Item 13 - Certain Relationships and Related Transactions

 

 

Item 14 – Principal Accountant Fees and Services

 

 

 

 

 

Part IV

 

 

Item 15 - Exhibits, Financial Statement Schedules

 

 

 

 

 

Signatures

 

 

 

 

 

Index to Exhibits

 

 

 

2



 

PART I

 

Item 1.  Business

 

General

 

Cascade Natural Gas Corporation (Cascade or the Company) was incorporated under the laws of the state of Washington on January 2, 1953.  Its principal business is the distribution of natural gas to customers in the states of Washington and Oregon.  Approximately 72% of its residential and commercial gas distribution margins are from customers in the state of Washington.

 

As of September 30, 2005, the Company had approximately 196,000 residential customers, 30,000 commercial customers, and 719 industrial and other larger customers.  Residential, commercial, and most small industrial customers are generally core customers who take traditional “bundled” natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation.  Sales to core customers in fiscal 2005 accounted for approximately 24% of gas deliveries and 71% of operating margin.  The Company’s sales to its core residential and commercial customers are influenced by fluctuations in temperature, particularly during the winter season.  A warm winter season will tend to reduce gas consumption.  Also affecting sales to core customers is the addition of more energy-efficient homes and facilities, consumer behavior driven by cost increases and a desire to conserve, and a recent trend to warmer winters in the Company’s service areas.  Together, these forces have resulted in reductions in average gas usage per customer.  The company is actively working with regulators within both states served to develop restructured rates to offset this trend.

 

Non-core customers are generally large industrial and institutional customers who have chosen “unbundled” service, meaning that they select from among several upstream supply, pipeline transportation, and gas management service options independent of the Company’s distribution service.  The Company’s margin from non-core customers is derived primarily from distribution service and to a lesser extent from gas management service revenue.  Gas management service revenue primarily includes operating margin from delivery of gas supplies and fees charged to non-core customers in consideration of securing gas supplies and pipeline capacity for the customers.

 

Natural Gas Supply

 

The majority of Cascade’s supply of natural gas is transported via Williams Gas Pipelines - West (Williams).  Williams owns and operates a transmission system extending from points of interconnection with El Paso Natural Gas Company and Transwestern Pipeline Company near Blanco, New Mexico through the states of New Mexico, Colorado, Utah, Wyoming, Idaho, Oregon and Washington to the Canadian border near Sumas, Washington.  Natural gas is transported north from the Colorado and New Mexico area, and south from British Columbia, Canada.  The Company is also a shipper on the transmission system of Gas Transmission Northwest Corporation (GTN), owned by TransCanada Pipeline (TCPL). GTN connects with the facilities of the TCPL at the international border near Kingsgate, British Columbia and extends through Washington and central Oregon into California. In addition, Cascade receives natural gas directly from Duke Energy Gas Transmission (DEGT) at the Canadian border near Sumas, Washington and also intra British Columbia at a receipt point known as Station 2 on DEGT.

 

Presently, baseload requirements for Cascade’s core market are provided by eight major gas supply contracts with various expiration dates ranging from 2006 through 2009 and averaging 460,000 therms per day of Canadian supply and 106,500 therms per day of domestic supply.  These contracts are supplemented by various service agreements to cover periods of peak demand including three storage agreements.  One such agreement, with Williams, extends to October 31, 2014 and provides for 167,890 therms per day and a maximum, renewable inventory of 6,043,510 therms.  The second storage agreement is with Avista Energy, and has a primary term ending April 30, 2006 and entitles Cascade to receive up to 150,000 therms per day and a maximum, renewable inventory of 4,800,000 therms.  A third contract, also with Williams for liquefied natural gas (LNG) storage, is effective through October 31, 2014.  Under this LNG agreement, Cascade is entitled to receive up to 600,000 therms per day to a maximum inventory of 5,622,000 therms.  In addition to withdrawal and inventory capacity, Cascade maintains a corresponding amount of firm transportation from the storage facility to the city gate for each of these agreements.

 

The Company enters into various seasonal and annual gas supply contracts designed to match the load requirements of its customers.  Interstate pipelines provide natural gas to the Company from production areas in the Rocky Mountain states and from western Canada. Management believes gas supply resources in those areas are adequate to serve the Company’s current needs and to support future growth.  The

 

3



 

wholesale price of gas in the region has increased in recent years, paralleling national trends.  Additionally, a favorable differential that has historically existed between Pacific Northwest gas prices and national prices has narrowed as new pipelines have increased access to Rocky Mountain and Canadian supplies by California and mid-west markets.

 

To mitigate price volatility, the Company employs a gas procurement strategy for supplies for sale to core customers that involves entering into physical gas supply contracts with suppliers at published first-of-the-month index prices for up to five-year terms.  To mitigate the price volatility, these index related supplies are hedged through the use of derivatives, primarily swaps, with financial institutions.  Approximately 90% of the core market’s requirement for fiscal 2006, 60% of fiscal 2007, and 30% of fiscal 2008 are secured with fixed prices as of the end of fiscal 2005.

 

State Regulation

 

The Company’s rates and practices are regulated by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).

 

Cascade’s gas supply contracts contain pricing provisions based on market prices, and as a matter of practice, the Company generally enters into derivatives, generally swaps, to fix the price of future supplies.  To the extent that overall demand is different from the amount of gas supply under contract and hedged, the net effective price paid by Cascade may change with respect to supplies purchased for core customers.  The Company is able to pass the effect of such changes, subject to regulatory review, to its customers by means of a periodic purchased gas cost adjustment (PGA) in each state.  Gas price changes occurring between times when PGA rate changes become effective are deferred for pass through in the next PGA.  These PGA’s include interest compensation on any deferred collections financed by Cascade.

 

With respect to such gas supplies delivered to Oregon customers, 67% of the incremental change in the actual cost of gas supplies, as compared to the forecasted cost reflected in the PGA, is deferred.  The remaining 33% (increase or decrease) is absorbed by the Company. This mechanism is intended to encourage the Company to seek opportunities to lower its cost of supplies and to be innovative in its management of the supply portfolio to avoid price spikes.  Cascade’s gas supply portfolio for Oregon core customers is comprised mostly of gas supplies with commodity prices that have been fixed through derivative arrangements; therefore, management believes the risk or opportunity for the Company is not significant under the 67% / 33% sharing arrangement.

 

Cascade has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the Oregon Public Utilities Commission.  The mechanism was designed as an incentive to pursue operational efficiencies and new revenue opportunities, and to share the success of such pursuits with ratepayers if the Company’s earnings exceed a calculated ceiling.  Under that arrangement, the Company is authorized to retain all of its earnings attributable to its Oregon operations up to a threshold level equal to 300 basis points above a 10.25% return on equity (ROE).  Subsequent years’ base ROE is adjusted by 20% of the movement in the average of the annual yields, reported monthly, for five-, seven-, and ten-year US Treasury debt securities for the test period.  If the adjusted Oregon earnings are below the threshold, there is no rate adjustment.  If the adjusted earnings are above the threshold, one-third of the earnings exceeding the threshold will be refunded to customers through future rate reductions.

 

The Company is also subject to state regulation with respect to integrated resource planning, and its most recent update of its Integrated Resource Plan (IRP) was filed in 2004 with both the WUTC and the OPUC.  The IRP shows the Company’s optimum set of supply and demand side resources that minimizes costs and risk over the 20-year planning horizon.  The IRP also sets forth possible core customer growth scenarios for a 20-year period.  In addition, the IRP sets forth the Company’s demand side management goals of achieving certain conservation levels in customer usage.

 

The IRP also includes the Company’s supply side management plans regarding transportation capacity and gas supply acquisition over a 20-year period.  The Company develops updates of the IRP every two years.  These updated documents take into account input solicited from the public and the WUTC and OPUC staffs.  While the filing of the IRP with both commissions gives the Company no advance assurance that its acquisitions of pipeline transportation capacity and gas supplies will be recognized in rates, management believes that the integrated resource planning process benefits the Company by giving it the opportunity to obtain input from regulators and the public concurrently with making these important strategic decisions.  Until the Company receives final regulatory approval of these decisions in the context of the ratemaking process, the Company cannot predict with certainty the extent to which the integrated resource planning process will affect its rates.

 

4



 

Like virtually all U.S. gas utilities, Cascade has experienced a declining trend in per-customer consumption over the last several years.  Given the drivers, this trend is unlikely to reverse itself.  To date, growth in the number of residential and commercial customers and earnings from other services contributed to offsetting this reduction.  The company is working with regulators in each state served to develop decoupling approaches which enable gas utilities to promote conservation while still earning an adequate return on its invested capital and operating costs.   Similar approaches have been implemented in Oregon and many other states.

 

Pipeline Safety

 

Cascade is subject to both state and federal pipeline safety rules.  In both Washington and Oregon, the federal rules are enforced by the state commissions.  Both the federal and state rules are updated and amended periodically.  The Pipeline Safety Act of 2002 requires operators of gas transmission pipelines to identify lines located in High Consequence Areas (HCA’s) and develop Integrity Management Programs (IMP’s) to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing safety of the pipelines.  The legislation requires Cascade to complete inspection of 50% of the highest risk pipelines located in its HCA’s within the first five years, and the remaining covered pipelines within 10 years of the date of enactment.  The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years from the date of the previous inspection for the life of the pipelines.  Cascade has met all interim deadlines in The Act and is on schedule to meet remaining deadlines.

 

Federal Energy Regulatory Commission (FERC) Matters

 

Cascade is not subject to regulation by the FERC; however, FERC actions can affect the amounts Cascade pays to interstate pipeline companies for interstate deliveries of natural gas supplies.  Several issues are pending before FERC, or are on appeal before the U.S. Court of Appeals.  The final outcome may affect prices Cascade pays; however, none would have a significant impact.  Since the Company’s current tariffs with the WUTC and OPUC provide for 100% pass through of costs subject to FERC regulation, the Company expects that the final resolution of pending issues will not significantly affect net income.

 

Curtailment Procedures

 

In some previous heating seasons, cold weather has required Cascade to curtail deliveries to its interruptible customers. Cascade has not curtailed any supply to firm customers, except under rarely occurring force majeure conditions. Cascade’s tariffs effective in Washington and Oregon allow for curtailment of interruptible services, which are provided at rates lower than for firm services.  In the event of curtailment by Cascade of firm service due to force majeure, Cascade’s tariffs provide that it will not be liable for damages to any customer for failure to deliver gas curtailed in accordance with the provisions of the tariffs.  The tariffs provide for appropriate adjustment of the monthly charges to firm customers curtailed by reason of an insufficient supply of gas.

 

Territory Served and Franchises

 

The population of communities served by Cascade totals approximately 1,045,000. At the end of September 2005, Cascade held the franchises necessary for the distribution of natural gas in all of the communities it serves in Washington and Oregon. Under the laws of those states, incorporated municipalities and counties may grant non-exclusive franchises for a fixed term of years conferring upon the grantee certain rights with respect to public streets and highways in the location, construction, operation, maintenance and removal of gas distribution facilities.

 

In the opinion of Cascade’s management, none of its franchises contain any restrictions or requirements that are of a materially burdensome nature, and such franchises are adequate for the conduct of Cascade’s present business. Franchises expire on various dates from fiscal 2006 to 2065. Management has not incurred significant difficulties in renewing franchises when they expire and does not expect any significant problems in the future.

 

Customers

 

Residential and commercial customers principally use natural gas for space heating and water heating.  Once connected, these customers rarely change from gas service.  This category is our fastest growing with customer count increases of 3-5% during each of the last several years.  The residential and commercial

 

5



 

market is very weather-sensitive.  See “Seasonality” below.  In addition to the seasonal nature of usage, average consumption per customer has declined since the beginning of this decade.  As mentioned earlier, the addition of more efficient homes and other buildings, replacing old appliances with more efficient units, and consumer behaviors drive this trend.  Reductions are most pronounced following significant gas cost increases.  Cascade’s growth has contributed to offsetting these declines.  As discussed under State Regulation, the Company is working with regulators in both states served to restructure rates to recognize this trend.

 

Agreements with Cascade’s principal industrial customers are for fixed terms of not less than one year and provide for automatic extension from year to year unless terminated by either party on at least 120-days’ notice.  The principal industrial activities in Cascade’s service area include the production of pulp, paper and converted paper products, plywood, industrial chemicals; refining of crude oil; the processing, flash freezing and canning of many types of vegetable, fruit and fish products; processing of milk products; meat processing; drying and curing of wood and agricultural products; and electric power generation.  Electric generation customers represent a significant portion of industrial revenues.  The demand for gas-fired generation tends to vary with the availability of hydroelectric power and the relative price of gas.

 

Seasonality

 

Weather is an important factor affecting gas revenues because of the large number of customers using gas for space heating.  For the fiscal year ended September 30, 2005, 68% of operating revenues and 106% of income from operations were derived from the first two quarters (October 2004 through March 2005). Because of the seasonality of space heating revenues, financial results for interim periods are not indicative of results to be expected for an entire year. To mitigate the seasonality of space heating revenues, the Company pursues a marketing strategy of encouraging the installation of appliances that utilize natural gas more consistently year-round since they are not as influenced by weather conditions.

 

Competitive Conditions

 

Cascade operates in a competitive market for natural gas service.  Cascade competes with residual fuel oil and other alternative energy sources for industrial boiler uses, and oil, propane, and electricity for residential and commercial space heating, and electricity for water heating.

 

Competition is primarily based on price.  Though wholesale natural gas prices have increased significantly during 2005, Cascade’s residential and commercial rate schedules continue to maintain a price advantage over oil in its entire service territory and have an advantage over electricity in much of its territory.  In addition, natural gas enjoys the advantage of being the preferred energy choice by builders for new home construction.

 

The large volume industrial market has always been very sensitive to price fluctuations between the comparable cost of natural gas and alternate fuels, principally residual fuel oil used in boiler applications.  However, the advent of open access transportation in the late 1980’s and early 1990’s and the subsequent restructuring of gas supply and contractual provisions with these customers have improved the Company’s competitive position. With the escalation of wholesale natural gas prices that began in the 2000 - 2001 heating season, and again in 2005, the Company has experienced some movement of its gas load to alternative fuels and some plant curtailments by industrial customers.

 

In addition to multiple alternative fuels, the Company is subject to bypass.  Bypass refers to actual or prospective customers who install their own facilities and connect directly to an upstream pipeline and thereby “bypass” the Company’s distribution service.  The Company has in the past experienced bypass, but has also experienced success in offering competitive rates to reduce economic incentives to bypass.

 

The Company competes with others in acquiring gas supplies for resale to governmental and industrial customers.  Further opportunities in this area will be dependent upon market conditions that can change over time, credit worthiness of customers and the increase or decrease in the number of competing providers that are available.

 

The Bonneville Power Administration (BPA) is a major supplier of hydroelectric power in the Pacific Northwest including Cascade’s service area.  BPA significantly influences the electric rates of all classes of customers including those applications in direct competition with natural gas marketed by Cascade.

 

6



 

Environmental

 

The Company is subject to federal and state environmental regulation of its operations and properties through the United States Environmental Protection Agency, the Washington Department of Ecology and the Oregon Department of Environmental Quality.  Such regulation may, at times, result in the imposition of liability or responsibility for the clean up or treatment of existing environmental problems or for the prevention of future environmental problems.  For detailed descriptions of specific environmental issues, see “Environmental Matters” under Item 7.

 

Capital Expenditures

 

Driven by Cascade’s high growth rate, capital expenditures are primarily used to expand the Company’s distribution system to serve new customers. Investments to expand capacity and to assure a safe and reliable system require a relatively smaller portion of our overall capital spending.  A one-time project, the installation of automated meter-reading capabilities system-wide, represented $16 million of our capital spending during fiscal years 2003 and 2004.  Total capital expenditures for the three fiscal years ended September 30, 2005 averaged approximately $31.5 million.  Capital spending for fiscal 2006 is expected to be significantly lower, likely within or slightly higher than the range Cascade spent during fiscal years 1999 to 2002.

 

Cascade has no current plans for major one-time capital projects.  Also supporting the reduced need to invest capital is the Company’s practice of assuring that its spending generates the highest possible returns within the shortest possible time, while assuming prudent risk, and complying with the requirements of regulators.  An example is our practice of working with developers and new customers to share the cost of marginal expansions and service connections when projected returns are insufficient for the Company to fund the entire investment.   Other practices include considering innovative solutions to specific needs, such as utilizing temporary supplemental capacity rather than investing in expensive pipe expansions to cover peak requirements.

 

Non-Utility Subsidiaries

 

Cascade has four non-utility subsidiaries, only two of which are actively engaged in business at present. The first active subsidiary, Cascade Land Leasing, is engaged in the servicing of loans that were made to Cascade’s gas customers to finance their purchases of energy-efficient appliances.  The subsidiary ceased making new loans in September 1997.  In addition, Cascade Land Leasing receives a small amount of annual royalty on gas production in Colorado. These mineral rights were a result of historical operations the Company had in Colorado until the mid-1970’s. The second active subsidiary, CGC Resources, is engaged in pipeline capacity management, with the objective of mitigating gas costs for Cascade.  The subsidiaries, which in the aggregate account for less than 1% of the consolidated assets of the Company, do not currently have a significant impact on Cascade’s financial statements.

 

Personnel

 

At September 30, 2005, Cascade had 375 employees.  Of the total employees, 177 are represented by the International Chemical Workers’ Union.  The present contract with the union extends to April 1, 2006 and remains in force thereafter from year to year unless terminated by either party by written notice sixty days prior to the expiration date.  Historically, the Company and the union have negotiated a new agreement to become effective as of the earliest expiration date rather than allowing the existing agreement to remain in force.

 

On November 23, 2005, 29 customer service representatives in the Company’s Bellingham and Sunnyside call centers elected to be represented by the International Chemical Workers’ Union.

 

Available Information

 

The Company makes available free of charge, on or through its website, http://www.cngc.com, its annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such reports with the Securities and Exchange Commission. In addition, copies of these documents may be requested, at no cost, from the Company’s corporate headquarters. Requests should be directed to Shareholder Relations, Cascade Natural Gas Corporation, 222 Fairview Avenue North, Seattle, WA 98109, or by phone at 206-624-3900.

 

7



 

To contact any independent board member, you may write to Larry L. Pinnt, Board of Directors Chair, P.O. Box 87, Redmond, WA 98073-0087, fax to 425-895-1349, or e-mail to lpinnt@cngc.com.

 

Item 2.  Properties

 

At September 30, 2005, Cascade’s utility plant investments included approximately 5,244 miles of distribution mains ranging in diameter from two inches to sixteen inches, 215 miles of transmission mains ranging in diameter from two inches to twenty inches, and 3,593 miles of service lines.

 

The distribution and transmission mains are located under public property such as streets and highways or on private property with the permission or consent of the individual owner.

 

Cascade owns 21 buildings used for operations, office space and warehousing in Washington and six such buildings in Oregon. It leases two commercial offices and warehouse buildings.  Cascade considers its properties well maintained and in good operating condition, and adequate for Cascade’s present and anticipated needs. All facilities are substantially utilized.

 

Item 3.  Legal Proceedings

 

Incorporated herein by reference is the information under “Environmental Matters” in Item 7.

 

Item 4.  Submission of Matters to a Vote of Security Holders

 

No matters were submitted during the fourth quarter of fiscal year 2005.

 

Executive Officers of the Registrant

 

The executive officers of the Company, as of December 8, 2005, are as follows:

 

 

 

 

 

 

 

Year

 

 

 

 

 

 

Became

Name

 

Office

 

Age

 

Officer

 

 

 

 

 

 

 

David W. Stevens

 

President and Chief

 

 

 

 

 

 

Executive Officer

 

46

 

2005

 

 

 

 

 

 

 

Rick A. Davis

 

Chief Financial Officer

 

53

 

2005

 

 

 

 

 

 

 

Jon T. Stoltz

 

Senior Vice President -

 

 

 

 

 

 

Gas Supply and Regulatory

 

 

 

 

 

 

Affairs

 

58

 

1981

 

 

 

 

 

 

 

Larry C. Rosok

 

Vice President - Human Resources

 

 

 

 

 

 

and Corporate Secretary

 

49

 

1995

 

 

 

 

 

 

 

Michael J. Gardner

 

Vice President – Operations

 

36

 

2005

 

 

 

 

 

 

 

Julie A. Marshall

 

Vice President – Customer Service

 

52

 

2005

 

 

 

 

 

 

 

James E. Haug

 

Controller

 

56

 

1981

 

None of the above officers is related by blood, marriage or adoption to any other of the above-named officers.  With the exception of David W. Stevens and Rick A. Davis, each of the other above-named officers has been employed by the Company in a management capacity for at least the past five years.  None of the above officers holds directorships in other public corporations.  All officers serve at the pleasure of the Board of Directors.

 

Mr. Stevens, 46, was elected to President and Chief Executive Officer and to the Board of Directors of Cascade Natural Gas Corporation effective April 1, 2005.  From July 2003 to December 2004, Mr. Stevens was President and COO for Panhandle Energy, a Southern Union Company subsidiary.  From September 1997 to January 2003, he was President of the Southern Union Gas Company.  Prior to that, Mr. Stevens served in other executive capacities within the Southern Union Company, including Senior Vice President – Sales and Operations, Regional Vice President, Group Vice President and Vice President – Operations.

 

8



 

Mr. Stevens joined the Southern Union Company in 1984.  He has served on the Board of Directors for the Southern Gas Association and the Intrastate Natural Gas Association of America, and was a member of the president’s counsel of the American Gas Association.

 

Mr. Davis, 53, was elected to Chief Financial Officer effective June 27, 2005.  From September 2003 to June 2005, Mr. Davis provided strategic planning and compliance consulting services through his own firm, Advisory Services and Jefferson-Wells, a global provider of accounting and finance-related services.  From January 2003 to August 2003, Mr. Davis was Chief Financial Officer at PAC Worldwide, a privately held manufacturer and distributor of packaging products.  From 1984 to 2002, Mr. Davis held executive-level positions at Weyerhaeuser Company and one of its subsidiaries serving at various times as Controller, Director Finance, Vice President-Finance and Vice President-Marketing.  He has served on various professional and non-profit boards and is a member of Financial Executives International and the AICPA.

 

9



 

PART II

 

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
 

The Common Stock is traded on the New York Stock Exchange under the symbol CGC.  The following table states the per-share high and low sales prices of the Common Stock:

 

 

 

Fiscal 2005

 

Fiscal 2004

 

Quarter

 

High

 

Low

 

High

 

Low

 

December 31

 

$

21.80

 

$

20.00

 

$

21.99

 

$

19.41

 

March 31

 

$

21.48

 

$

19.68

 

$

23.05

 

$

20.76

 

June 30

 

$

20.59

 

$

18.05

 

$

22.52

 

$

19.10

 

September 30

 

$

22.80

 

$

20.01

 

$

22.20

 

$

19.35

 

 

At September 30, 2005, there were 5,350 registered holders of the Common Stock.  The following table shows for the periods indicated the dividends paid per share on the Common Stock:

 

 

 

Fiscal

 

Fiscal

 

Quarter

 

2005

 

2004

 

 

 

 

 

 

 

December 31

 

$

0.24

 

$

0.24

 

March 31

 

$

0.24

 

$

0.24

 

June 30

 

$

0.24

 

$

0.24

 

September 30

 

$

0.24

 

$

0.24

 

 

At September 30, 2005, the Company was in compliance with all indebtedness covenants and was not restricted on dividend payments.

 

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Item 6. Selected Financial Data

 

The following selected financial data are derived from the consolidated financial statements of the Company and have been restated to reflect adjustments that are further discussed in Note 3: “Restatement of Financial Statements” under Notes to Consolidated Financial Statements included in Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.

 

Consolidated Statements of Income and Comprehensive Income:

 

 

 

Year Ended September 30

 

 

 

2005

 

2004

 

2003*

 

2002*

 

2001*

 

 

 

(dollars in thousands except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenues

 

$

326,500

 

$

318,078

 

$

302,755

 

$

320,978

 

$

335,814

 

Less: Gas Purchases

 

212,958

 

202,759

 

191,887

 

209,225

 

219,795

 

Revenue taxes

 

21,827

 

21,511

 

20,193

 

21,251

 

20,987

 

Operating Margin

 

91,715

 

93,808

 

90,675

 

90,502

 

95,032

 

Cost of Operations:

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

44,223

 

40,540

 

45,514

 

43,052

 

41,027

 

Depreciation and amortization

 

17,274

 

16,325

 

15,338

 

14,926

 

13,839

 

Property and payroll taxes

 

3,786

 

3,696

 

3,532

 

3,361

 

3,182

 

 

 

65,283

 

60,561

 

64,384

 

61,339

 

58,048

 

Income From Operations

 

26,432

 

33,247

 

26,291

 

29,163

 

36,984

 

Nonoperating Expense (Income):

 

 

 

 

 

 

 

 

 

 

 

Interest

 

11,744

 

12,375

 

12,363

 

12,384

 

10,509

 

Interest charged to construction

 

(187

)

(445

)

(378

)

(219

)

(333

)

 

 

11,557

 

11,930

 

11,985

 

12,165

 

10,176

 

Amortization of debt issuance expense

 

372

 

618

 

696

 

652

 

607

 

Other

 

(376

)

(162

)

(227

)

(197

)

(313

)

 

 

11,553

 

12,386

 

12,454

 

12,620

 

10,470

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Before Income Taxes

 

14,879

 

20,861

 

13,837

 

16,543

 

26,514

 

Income Taxes

 

5,632

 

7,559

 

5,117

 

6,085

 

9,520

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

9,247

 

13,302

 

8,720

 

10,458

 

16,994

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Comprehensive Income (Loss)

 

 

 

 

 

 

 

 

 

 

 

Minimum pension liability adjustment

 

177

 

1,270

 

(2,619

)

(11,792

)

(6,502

)

Income tax benefit

 

(56

)

(448

)

937

 

4,205

 

2,341

 

Other Comprehensive Income (Loss)

 

121

 

822

 

(1,682

)

(7,587

)

(4,161

)

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income

 

$

9,368

 

$

14,124

 

$

7,038

 

$

2,871

 

$

12,833

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings Per Common Share, Basic and Diluted

 

$

0.82

 

$

1.19

 

$

0.79

 

$

0.95

 

$

1.54

 

 


* Data for 2001, 2002, and 2003 are restated as discussed in the Notes to Consolidated Financial Statements in Item 8 of this report.

 

11



 

 

 

At September 30

 

 

 

2005

 

2004*

 

2003*

 

2002*

 

2001*

 

 

 

(dollars in thousands except per share data)

 

Retained Earnings:

 

 

 

 

 

 

 

 

 

 

 

Beginning of the year

 

$

17,570

 

$

15,051

 

$

16,978

 

$

17,127

 

$

10,736

 

Net income

 

9,247

 

13,302

 

8,720

 

10,458

 

16,994

 

Exercise of stock options

 

 

 

 

(4

)

 

Common dividends

 

(10,909

)

(10,783

)

(10,647

)

(10,603

)

(10,603

)

End of the year

 

$

15,908

 

$

17,570

 

$

15,051

 

$

16,978

 

$

17,127

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital Structure:

 

 

 

 

 

 

 

 

 

 

 

Common shareholders’ equity

 

$

118,615

 

$

117,584

 

$

111,630

 

$

113,635

 

$

121,391

 

Debt:

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

173,840

 

128,900

 

142,930

 

164,930

 

125,000

 

Short-term debt

 

12,500

 

33,500

 

3,800

 

 

40,000

 

Current maturities of long-term debt

 

 

14,000

 

22,000

 

 

 

 

 

186,340

 

176,400

 

168,730

 

164,930

 

165,000

 

Total capital

 

$

304,955

 

$

293,984

 

$

280,360

 

$

278,565

 

$

286,391

 

 

 

 

 

 

 

 

 

 

 

 

 

Financial Ratios:

 

 

 

 

 

 

 

 

 

 

 

Return on common shareholders’ equity

 

7.46

%

11.03

%

7.33

%

8.27

%

13.26

%

Common stock dividend payout ratio

 

117

%

81

%

122

%

101

%

62

%

Cash dividends per common share

 

$

0.96

 

$

0.96

 

$

0.96

 

$

0.96

 

$

0.96

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed charge coverage (before income tax deduction):

 

 

 

 

 

 

 

 

 

 

 

Times interest earned

 

2.23

 

2.61

 

2.06

 

2.27

 

3.39

 

 

 

 

 

 

 

 

 

 

 

 

 

Book value per year-end share of common stock

 

$

10.39

 

$

10.44

 

$

10.03

 

$

10.29

 

$

10.99

 

 

 

 

 

 

 

 

 

 

 

 

 

Capitalization Ratios at End of Year

 

 

 

 

 

 

 

 

 

 

 

Common shareholders’ equity

 

38.9

%

40.0

%

39.8

%

40.8

%

42.4

%

Long-term debt (incl. current maturities)

 

57.0

%

48.6

%

58.8

%

59.2

%

43.6

%

Short-term debt

 

4.1

%

11.4

%

1.4

%

0.0

%

14.0

%

 

 

100.0

%

100.0

%

100.0

%

100.0

%

100.0

%

 

 

 

 

 

 

 

 

 

 

 

 

Utility Plant:

 

 

 

 

 

 

 

 

 

 

 

Utility plant - end of year

 

$

597,469

 

$

570,036

 

$

529,807

 

$

505,126

 

$

488,231

 

Accumulated depreciation

 

257,008

 

242,691

 

227,582

 

213,476

 

201,530

 

Net plant

 

$

340,461

 

$

327,345

 

$

302,225

 

$

291,650

 

$

286,701

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures, net of contributions in aid

 

$

28,011

 

$

39,019

 

$

27,693

 

$

20,734

 

$

21,649

 

Total assets

 

$

552,905

 

$

422,622

 

$

371,456

 

$

367,663

 

$

364,253

 

 

 

 

 

 

 

 

 

 

 

 

 

Number of Employees at End of Year

 

375

 

428

 

437

 

444

 

442

 

 


* Data are restated as discussed in the Notes to Consolidated Financial Statements in Item 8 of this report.

 

12



 

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Restatement of Financial Statements

 

Subsequent to the issuance of the financial statements for the year ended September 30, 2004, management determined that the Company’s deferred income tax liabilities were not correctly stated as of September 30, 2004, 2003, 2002, and 2001.  Further, the Company’s provision for deferred income taxes was not correctly stated for the years ended September 30, 2003, 2002, and 2001 under accounting principles generally accepted in the United States of America (“GAAP”).  As a result, beginning retained earnings, financial position, results of operations, and cash flows have been restated.

 

See Note 3 to the consolidated financial statements of this Report for a summary of the effects of these changes on the Company’s consolidated balance sheet as of September 30, 2004, as well as on the Company’s consolidated statements of income and comprehensive income, shareholders’ equity and cash flows for fiscal year 2003.  The accompanying Management’s Discussion and Analysis gives effect to these corrections.

 

The following is management’s assessment of the Company’s financial condition and a discussion of the principal factors that affect consolidated results of operations and cash flows for the fiscal years ended September 30, 2005, 2004, and 2003.  References herein to 2005, 2004, and 2003 refer to these fiscal years.

 

Overview

 

The Company is a local distribution company (LDC) serving approximately 227,000 customers in the States of Washington and Oregon.  Its service area consists primarily of relatively small cities and rural communities rather than larger urban areas.  The Company’s primary source of revenue and operating margin is the distribution of natural gas to end-use residential, commercial, industrial, and institutional customers.  Revenues are also derived from providing gas management and other services to some of its large industrial and commercial customers.  The Company’s rates and practices are regulated by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).

 

Key elements of the Company’s strategy:

 

                  Remain focused on the natural gas distribution business.

                  Pursue appropriate regulatory treatment, including initiatives to decouple the Company’s earnings from changing customer consumption patterns, and remove other regulatory impediments to effective management of the business.

                  Economic expansion of its customer base by prudently managing capital expenditures and ensuring new customers provide sufficient margins for an appropriate return on the new investment required to acquire the customers.

                  Continue to focus on operational efficiencies.

                  Manage cash flow to avoid the requirement of additional debt financing.

 

Opportunities and Challenges

 

The Company operates in a diverse service territory over a wide geographic area relative to the Company’s overall size and number of customers.  The economies of various parts of the service area are supported by a variety of industries and are affected by the conditions that impact those industries.  Management believes there are growth opportunities in the Company’s service area, especially in the residential and commercial segments.  Factors contributing to these opportunities include low market penetration in many of the towns served, and general population growth in the service area, including some areas of rapid growth.

 

Overall revenues and margins are also negatively impacted by higher efficiency in new home and commercial building construction, higher efficiency in gas-burning equipment, and customers taking additional measures to reduce energy usage.  The increasing cost of energy in recent years, including the wholesale cost of natural gas, continues to encourage such measures.  The Company continues to believe that energy efficiency and conservation are the most viable near-term tactics for influencing the wholesale natural gas prices.  It’s also a vital strategy for stabilizing the cost of gas over the long term.  The traditional

 

13



 

regulatory establishment of rates ties the recovery of cost to volumetric sales.  This traditional rate design creates a financial disincentive for utilities to promote conservation.  The Company is working with regulators and other stakeholders in each state to develop an acceptable decoupling mechanism that will enable the Company to promote conservation while still earning an adequate return on its invested capital and operating costs.  Similar approaches have been implemented in many states and are endorsed by a variety of organizations, including the recent endorsement by the National Association of Regulated Utility Commissions.  The results of such rate requests and other initiatives for regulatory relief are subject to significant uncertainties.

 

The Company earns approximately one third of its operating margin from industrial and electric generation customers.  Loss of major industrial customers, or unfavorable conditions affecting an industry segment, could have a detrimental impact on the Company’s earnings.  Many external factors over which the Company has no control can significantly impact the amount of gas consumed by industrial and electric generation customers and, consequently, the margins earned by the Company.

 

Revenues and margins from the Company’s residential and small commercial customers are highly weather-sensitive.  In a cold year, the Company’s earnings are boosted by the effects of the weather, and conversely in a warm year, the Company’s earnings suffer.  Peak requirements also drive the need to reinforce our systems (i.e., increase capacity).  Our operations group considers innovative approaches such as temporarily utilizing mobile gas supply rather than making large investments in long-term capacity increases, which may not be fully utilized.

 

Prospects for continuing strong residential and commercial customer growth are excellent.  The pace of new home and commercial construction remains steady in communities served by the Company.  Good potential also exists for converting homes and businesses located on or near the Company’s current lines to gas from other fuels, as well as for expanding the system into adjacent areas.  Customer count growth in this sector has been about double the average of U.S. gas utilities.

 

Our customer service call center organization recently voted to accept union representation.  The company plans to negotiate an agreement that will support our effort to cost-effectively provide superior customer service.  The timing and results of negotiations are uncertain.

 

The contract with the union representing our service mechanics and construction staff expires on April 1, 2006.  Again, we plan to negotiate an agreement that supports superior and cost-effective customer service.  The results and timing of negotiations are uncertain.

 

We continue to pursue operating efficiencies and cost reductions.  During fiscal 2004, we completed the implementation of automated meter reading capability covering our entire service area.  This reduced our staffing needs by 27 full-time equivalent positions.  During fiscal 2005, the centralization of our customer service activities and organization reductions, enabled by a variety of other improvements, reduced our staffing by over 9%.  Our current organization is able to service more customers at a lower cost than in prior years.  Changes completed during fiscal 2005 alone resulted in improving our customer-per-employee ratio from 500 to 600.  We continue to look for additional operating improvements.

 

As discussed in Item 1 (our description of the business), we carefully analyze the economics of our spending to support growth.  When justified under our tariffs, we work with developers, business owners and residents to share certain construction costs to assure a fair return to Cascade.  Non-revenue-generating spending is also managed to assure that we use the most economically attractive solutions while providing for a safe and reliable system.

 

Management continuously seeks improvement opportunities in all areas.  Our discussion above covering regulatory change, labor relations, operating practices, our organization and our investment to maintain and expand our gas delivery system are examples.  We will continue to evaluate these and other aspects of our business to improve our customer service and the returns to our shareholders.

 

RESULTS OF OPERATIONS

 

2005 versus 2004

 

The Company reported net income for 2005 of $9,247,000, or $0.82 per share, compared to $13,302,000 or $1.19 per share for 2004.  References herein to per-share earnings refer to both basic and diluted, unless otherwise indicated.  Primary factors resulting in the decrease in earnings per share include:

 

14



 

Operating Margin Factors:

 

                  Reduced natural gas usage per residential and commercial customer – $0.15 per share

                  Lower margin from gas management services – $0.11 per share

                  Unfavorable comparison of mark-to-market valuations versus 2004 – $0.06 per share

                  Lower margins from deliveries to industrial customers – $0.04 per share

 

Cost of Operations Factors:

 

                  Executive transition costs associated with changes in the Chief Executive Officer and Chief Financial Officer – $0.07 per share

                  Severance compensation associated with staffing reductions – $0.06 per share

                  Increased depreciation expenses – $0.05 per share

                  Write-offs of cancelled projects – $0.03 per share

                  Increased purchased services expenses – $0.03 per share

                  Increased uncollectible accounts expenses – $0.02 per share

 

The above unfavorable comparisons were partially offset by the following factors:

 

                  Increase in the number of residential and commercial customers – $0.18 per share

                  Revision of estimated liability for Oregon Earnings sharing – $0.05 per share

                  Lower employee benefits expense – $0.04 per share

 

2004 versus 2003

 

The Company reported net income for 2004 of $13,302,000, or $1.19 per share, compared to $8,720,000, or $0.79 per share for 2003.  Primary factors and the resulting increase (decrease) in earnings per share affecting this comparison include:

 

                  Improved margins from residential and commercial customers related to increased per-customer consumption and growth in the number of customers – $0.18 per share

                  Reduction in employee benefit expenses resulting from the successful 2003 implementation of plan changes designed to reduce costs – $0.17 per share

                  Recognition in 2003 of retirement plan curtailment losses in connection with above-mentioned plan changes – $0.08 per share

                  Favorable mark-to-market valuations in 2004 and negative valuations in 2003 – $0.07 per share

                  Contract termination charge in 2003 – $0.05 per share

 

The favorable comparisons listed above were partially offset by the following factors:

 

                  Increase in depreciation and amortization – ($0.06) per share

                  Decreased margin from electric generation customers – ($0.06) per share

                  Decreased margin from gas management services – ($0.08) per share

 

OPERATING MARGIN

 

Operating margins (revenue minus gas cost and revenue taxes) by customer category for the fiscal years ended September 30, 2005, 2004 and 2003 are set forth in the tables below:

 

15



 

Residential and Commercial Operating Margin

 

 

 

2005

 

2004

 

2003

 

 

 

(dollars in thousands)

 

Degree Days

 

5,170

 

5,212

 

5,042

 

Average Number of Customers Billed

 

 

 

 

 

 

 

Residential

 

194,469

 

184,845

 

177,300

 

Commercial

 

30,183

 

29,320

 

28,851

 

Average Therm Usage Per Customer

 

 

 

 

 

 

 

Residential

 

683

 

710

 

692

 

Commercial

 

3,474

 

3,628

 

3,473

 

Operating Margin

 

 

 

 

 

 

 

Residential

 

$

40,642

 

$

39,691

 

$

37,483

 

Commercial

 

$

21,672

 

$

22,014

 

$

21,014

 

 

Industrial and Other Operating Margin

 

 

 

2005

 

2004

 

2003

 

 

 

(dollars and therms in thousands)

 

Average Number of Customers Billed

 

 

 

 

 

 

 

Electric Generation

 

13

 

14

 

14

 

Industrial

 

718

 

737

 

741

 

Therms Delivered

 

 

 

 

 

 

 

Electric Generation

 

437,934

 

480,859

 

543,621

 

Industrial

 

406,218

 

415,740

 

395,480

 

Operating Margin

 

 

 

 

 

 

 

Electric Generation

 

$

7,663

 

$

8,013

 

$

9,032

 

Industrial

 

$

18,672

 

$

19,389

 

$

19,394

 

Gas Management Services

 

$

1,432

 

$

3,309

 

$

3,824

 

Mark-to-Market Valuations

 

$

(181

)

$

836

 

$

(315

)

Other Service Revenue

 

$

1,290

 

$

882

 

$

593

 

Oregon Earnings Sharing estimates

 

$

525

 

$

(326

)

$

(350

)

 

2005 Versus 2004

 

Residential and Commercial – Operating margin (revenue minus gas costs and revenue taxes) is primarily a function of customer growth and gas usage per customer.  The net addition of approximately 10,500 billed residential and commercial customers in 2005 contributed approximately $3,160,000 of additional margin compared to fiscal 2004.  This was mostly offset by reductions in gas usage per residential and commercial customer of 3.8% and 4.4%, respectively, which reduced margins by $2,550,000.  The addition of more efficient homes and businesses, reduced consumption per consumer, and slightly warmer weather compared to last year drove the lower consumption rates.  Weather statistics indicate that fiscal 2005 was 1% warmer than fiscal 2004 and 4% warmer than the average of the past five years.

 

Industrial – Margin from natural gas deliveries to industrial customers decreased by $717,000 year to year.  This reduction is due to a variety of reasons including contract changes reducing minimum requirements, a decline in the number of customers and reduced usage by several sectors including chemical and paper manufacturing.

 

Electric Generation – Margin from natural gas deliveries to electric generation customers decreased $350,000 for the year with the decline attributable to lower-cost hydroelectric supplies and the increased wholesale price of natural gas.  Looking ahead, gas usage by generation customers will continue to depend on the variables of regional demand for power, availability of hydro resources, and the relationship between the market price of electricity and the cost of gas.

 

16



 

Gas Management – Gas management services margin was down $1,877,000 from last year.  The Company has lost sales and margin as a result of increased competition for the sale of gas supplies to large-volume customers.

 

Oregon Earnings Sharing – The change in Oregon Earnings Sharing amounts are the result of revised estimates of liability for refunds to Oregon customers related to OPUC requirements.  As of the end of 2004, the Company estimated its liability to be $525,000.  Based on a final analysis approved by the OPUC, 2004 earnings were not sufficient to trigger a sharing with customers, and in 2005 this $525,000 was reversed.  Management also estimates that there will be no liability for 2005.

 

2004 Versus 2003

 

Residential and Commercial – Margins from residential and commercial customers increased $3,208,000.  Of this increase, approximately $2,200,000 resulted from the increase of 8,013 in the average number of customers billed.  The remaining increase stemmed primarily from increased gas usage per customer, related to somewhat cooler weather.

 

Industrial – For the year, gas distribution margins from industrial customers were essentially the same as 2003.  In the first half of the year, industrial distribution margin showed signs of recovery from the stagnation that followed the 2000 energy crisis and a prolonged recession.  However, the upward trend stalled in the third quarter, and in the fourth quarter, margins declined compared to 2003. The primary reason for the reversal of the positive trend is believed to be the higher wholesale prices of natural gas.

 

Electric Generation – Margins from electric generation customers were down $1,019,000 in 2004 compared to 2003.  Much of the decline was due to an abundance of cheap hydroelectricity and moderate regional demands for power during the first part of the year.

 

Gas Management – Margins from providing gas management services decreased $515,000 in 2004 from 2003.  Margins in 2003 were negatively impacted by an $865,000 contract termination charge.  Absent this factor, gas management margin would have decreased by $1,380,000 in 2004.  The re-emergence of energy marketers, an industry segment that all but disappeared in the wake of the Enron failure, resulted in stiff competition for gas supply sales to larger gas customers.  Cascade has lost customers to such marketers, and margins that are available for any sales are smaller than in the past.

 

COST OF OPERATIONS

 

2005 versus 2004

 

The primary drivers of the $3,683,000 (9.1%) increase in operating expenses are organizational changes in 2005.  Costs of $1,234,000 were recognized related to the replacements of the Company’s Chief Executive and Chief Financial Officers.  The expenses were primarily made up of severance compensation for the retiring executives, hiring expenses, and signing bonuses for the new executives.  In the fourth quarter of 2005, the Company eliminated 22 employee positions resulting in $1,121,000 in severance expenses.

 

Operating expenses in 2005 included the write off of $596,000 in capital projects determined to no longer be viable. The projects were primarily related to development of computer software applications.

 

Purchased services expenses in 2005 were higher by $532,000 compared to 2004. The primary driver of this increase is the costs related to the Company’s Sarbanes-Oxley compliance work, with increased costs of $337,000 over 2004.

 

Bad debts expense increased $325,000 over 2004.  Driving this increase are higher gas costs resulting in higher customer bills.  Management believes the increase also stems in part from the transition of customer service and collections activities from 15 offices to a single consolidated customer service call center.

 

Employee benefits expense decreased $625,000.  The primary drivers of the decrease were reductions in medical and dental expenses, for active employees, and in retiree medical expense.

 

Depreciation and amortization expense increased $949,000 reflecting higher depreciable assets resulting from capital spending.

 

17



 

2004 versus 2003

 

Compared to 2003, overall Cost of Operations was $3,823,000 lower for the year.  Within Cost of Operations, notable changes in Operating Expenses included the reduction in employee benefits expenses of $4,448,000.  The comparison is affected by retirement plan curtailment charges of $1,451,000 in 2003.  The remaining decrease is primarily attributed to changes in benefit plans initiated in 2003, designed to reduce costs.  Benefits expense in 2004 was also favorably impacted by recognition of $315,000 for the Medicare prescription drug subsidy, reflected as a reduction in retiree medical expense. In addition, 2003 expenses included a $524,000 severance cost.

 

The $987,000 increase in depreciation and amortization is primarily related to increases in depreciable gas distribution system assets.

 

INCOME TAXES

 

The changes in the provision for income taxes from 2004 to 2005, and from 2003 to 2004 are primarily attributable to the changes in pre-tax earnings.

 

OTHER COMPREHENSIVE INCOME (LOSS)

 

The comparisons of Other Comprehensive Income (loss) from 2005 to 2004, and from 2004 to 2003 are related to minimum pension liability adjustments. In 2005 and 2004, the value of pension plan assets continued a modest recovery from the declines experienced in 2001 and 2002. As a result of this recovery, the Company has reduced its accrual related to its unfunded accumulated benefit obligation by $177,000 and $1,270,000 for 2005 and 2004.

 

LIQUIDITY AND CAPITAL RESOURCES
 

The seasonal nature of the company’s business creates short-term cash requirements to finance customer accounts receivable and construction expenditures.  To provide working capital for these requirements, the company has a $60,000,000 bank revolving credit commitment.  This agreement has a variable commitment fee and a term that expires in October 2007.  The company also has a $10,000,000 uncommitted line of credit. As of September 30, 2005, there was $12,500,000 outstanding under these credit lines.

 

Due to the nature of Cascade’s business, which is characterized by reliable payments from a stable customer base and our expectations that capital spending will be reduced from the last few years, we expect to have limited need to source additional capital during fiscal year 2006.  For this reason, combined with the availability of short-term credit and the ability to issue long-term debt and additional equity, management believes it has adequate financial flexibility to meet its anticipated cash needs.

 

The table below shows the Company’s future commitments under contractual obligations as of September 30, 2005:

 

 

 

Amounts Due by Fiscal Year

 

Contract Category

 

2006

 

2007

 

2008

 

2009

 

2010

 

Beyond
2010

 

Total

 

 

 

(dollars in thousands)

 

Short-term Debt

 

$

12,500

 

$

 

$

 

$

 

$

 

$

 

$

12,500

 

Long-term Debt

 

 

8,000

 

 

 

 

165,840

 

173,840

 

Interest on Debt

 

12,363

 

11,686

 

11,601

 

11,601

 

11,601

 

162,236

 

221,088

 

Operating Leases

 

537

 

304

 

49

 

33

 

15

 

 

938

 

Gas Supply

 

245,968

 

196,349

 

246,884

 

120,390

 

5,165

 

 

814,756

 

Interstate Pipeline Transportation

 

36,645

 

36,645

 

36,645

 

36,535

 

34,408

 

257,444

 

438,322

 

Gas Storage and Peaking Services

 

1,738

 

1,520

 

1,520

 

1,520

 

1,520

 

6,078

 

13,896

 

Other

 

417

 

226

 

111

 

114

 

54

 

55

 

977

 

Total

 

$

310,168

 

$

254,730

 

$

296,810

 

$

170,193

 

$

52,763

 

$

591,653

 

$

1,676,317

 

 

OPERATING ACTIVITIES

 

The 2005 decline in net income contributed to lower net cash provided by operating activities.  A significant factor is reflected in Deferrals of gas cost changes, resulting from higher wholesale gas costs

 

18



 

paid this year relative to the amount built in to customer rates.  This outpaced the amount of $5,098,000 from Amortization of gas cost changes.  In October and November 2005, the Company implemented new rates designed to collect from customers the amount of fiscal 2006 gas costs, plus a temporary component designed to recover approximately $12 million of previously deferred gas costs.

 

Significant factors affecting non-cash components of net income are prepaid income taxes and deferred income taxes.  In the fourth quarter of 2004, the Company received Internal Revenue Service approval of an application to change the method of accounting for deferred gas costs for purposes of calculating current federal income taxes.  As a result, the Company is able to deduct on its federal tax returns amounts included in deferred gas cost charges.  This change is effective retroactive to the tax return for fiscal year 2001, and in 2005, the Company filed amended tax returns for its fiscal years 2001 and 2002.  Accordingly, the Company has accrued an estimated refund of federal and state income taxes for those years of $7.5 million. These refunds represent temporary differences between book and taxable income, and deferred income taxes have been accrued so that there is no impact on net income resulting from this change.  As deferred gas cost charges are amortized in future years, the Company’s income tax liability and cash payments for income taxes will increase accordingly.

 

INVESTING ACTIVITIES

 

Net capital expenditures for 2005 were approximately 28% lower than last year.  The decrease is primarily attributable to $12,515,000 expended in 2004 on a project to install electronic devices on all the Company’s customer meters to allow for automated meter reading (AMR.).  The AMR project was begun in 2003 and completed in 2004 with total expenditures on the project of approximately $16,198,000.

 

FINANCING ACTIVITIES

 

The Company retired $14 million in current maturities of long-term debt during 2005 and $22 million during 2004.  These retirements were funded with two debt issues totaling $45 million during 2005.  None of the outstanding long-term debt matures during fiscal 2006.  Additionally, during 2005, the Company reduced its short-term debt by $21 million.

 

Proceeds from issuance of common stock are primarily issuance of new stock through the dividend reinvestment plan, 401(k) plan, and on exercise of stock options.

 

ENVIRONMENTAL MATTERS
 

There are two claims against the Company for cleanup of alleged environmental contamination related to manufactured gas plant sites previously operated by companies that were subsequently merged into the Company.

 

The first claim was received in 1995 and relates to a site in Oregon.  An investigation has shown that soil and groundwater contamination exists at the site.  There are parties in addition to the Company that are potentially liable for cleanup of the contamination.  Some of these other parties have shared in the costs expended to date to investigate the site, and it is expected that these and other parties will share in the cleanup costs.  Several alternatives for remediation of the site have been identified with preliminary estimates for cleanup ranging from approximately $500,000 to $11,000,000.  It is not known at this time what share of the cleanup costs will actually be borne by the Company.

 

The second claim was received in 1997 and relates to a site in Washington.  An investigation has determined that there is evidence of contamination at the site, but there is also evidence that other property owners may have contributed to the contamination.  There is currently not enough information available to estimate the potential liability associated with this claim, but the Company and other parties may become more involved in investigations of the nature and extent of contamination, and possible remediation of the site, as increased interest has been expressed concerning its potential for redevelopment.

 

Management first intends to pursue reimbursement from its insurance carriers.  In the event the insurance proceeds do not completely cover the costs, management intends to seek recovery from its customers through increased rates.  There is precedent for such recovery through increased rates, as both the WUTC and the OPUC have previously allowed regulated utilities to increase customer rates to cover similar costs.

 

19



 

EFFICIENCY INITIATIVE – CUSTOMER SERVICE CALL CENTER

 

In January 2005, the Company began operation of a customer-service call center at its existing district office in Bellingham, Washington.  Activation of the call center was phased in, and it became fully operational in March 2005.  This call center consolidated, in one location, the Company’s customer service function, which had been spread through 15 offices.  To implement the call center, the Company incurred $855,000 capital expenditures and $313,000 transitional expenses.  After factoring in the transitional expense, there was a small net decrease in expense compared to 2004.  Management expects fiscal 2006 to benefit from a full year of approximately $750,000 in reduced costs, in addition to improved customer service.

 

CRITICAL ACCOUNTING POLICIES

 

The Company’s financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).  In following GAAP, management exercises judgment in selection and application of accounting principles.  Management considers Critical Accounting Policies to be those where different assumptions regarding application could result in material differences in financial statements.

 

USE OF ESTIMATES

 

The preparation of financial statements in conformity with GAAP 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.  The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC.  Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, unbilled revenue, valuation of derivative instruments, and in the determination of depreciable lives of utility plant.  On an ongoing basis, management evaluates the estimates used based on historical experience, current conditions, and on various other assumptions believed to be reasonable under the circumstances.  Actual results may differ from these estimates under different assumptions or conditions.

 

REVENUE RECOGNITION

 

The Company recognizes operating revenues based on deliveries of gas and other services to customers.  This includes estimated revenues for gas delivered but not billed to residential and commercial customers from the latest meter reading date to the end of the accounting period.

 

REGULATORY ACCOUNTING

 

The Company’s accounting policies and practices are generally the same as used by unregulated companies for financial reporting under GAAP.  However, Statement of Financial Accounting Standards (FAS) No. 71, “Accounting for the Effects of Certain Types of Regulation”, requires regulated companies to apply accounting treatment intended to reflect the financial impact of regulation.  For example, in establishing the rates to be charged to the Company’s retail customers, the WUTC and the OPUC may not allow the Company to charge its customers for recovery of certain expenses in the same period they are incurred.  Instead, rates are expected to be established to recover costs that were incurred in a prior period.  In this situation, following FAS No. 71 requires the Company to defer these costs and include them as regulatory assets on the balance sheet.  In the subsequent period when these costs are recovered from customers, the Company then amortizes these costs as expense in the income statement in an amount equivalent to the amounts recovered.  Similarly, certain revenue items, or cost reductions, may be deferred as regulatory liabilities, which are later amortized to the income statement as customer rates are reduced.  In order to apply the provisions of FAS No. 71, the following conditions must apply:

 

                  An independent regulator approves the company’s customer rates.

                  The rates are designed to recover the company’s costs of providing the regulated services or products.

                  There is sufficient demand for the regulated service to reasonably assure that rates can be set at a level to recover the costs.

 

The Company periodically assesses whether conditions merit the continued applicability of FAS No. 71.  In the event the Company should determine in the future that all or a portion of its regulatory assets and

 

20



 

liabilities no longer meet the above criteria, it would be required to write off the related balances of its regulatory assets and liabilities and reflect the write-off in its income statement.

 

PENSION PLANS

 

The Company has a defined benefit pension plan substantially covering all union employees and salaried employees hired before September 30, 2003.  The Company also provides executive officers with supplemental retirement, death and disability benefits.  These plans were amended in fiscal 2003 so that, subsequent to September 30, 2003, benefits under these plans no longer accrue to non-bargaining-unit employees and officers.  The pension plan remains substantially unchanged for bargaining-unit employees at this time.

 

The Company’s pension costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, and by employee demographics including age, compensation, and length of service.  Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions of future experience.  Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation.  Changes in these assumptions may significantly affect pension costs.  Changes to the provisions of the plans may also impact current and future pension costs.  Changes in pension plan obligations resulting from these factors may not be immediately recognized as pension costs, but generally are recognized in future years over the remaining average service period of pension plan participants.

 

The Company’s funding policy is to contribute amounts equal to or greater than the minimum amounts required to be funded under the Employee Retirement Income Security Act, and not more than the maximum amounts currently deductible for income tax purposes.  The Company contributed $3,365,000 in 2005 and $3,843,000 in 2004 to the pension and supplemental executive retirement plans, and expects to contribute approximately $3,320,000 in 2006.

 

The discount rate the Company selects is based on the average of the 20-year and above Aa debt yields published by Moody’s.  These are yields considered to be consistent with the expected term of pension benefits.  At September 30, 2005, the Company used a discount rate of 5.50%, down from the 6.00% rate used at September 30, 2004.  A reduction in the discount rate results in increases in projected benefit obligation, pension liability, and pension costs.

 

In selecting an assumed long-term rate of return on plan assets, the Company considers past performance and economic forecasts for the types of investments held by the plan.  In 2005 and 2004, the Company’s assumed rate of return on plan assets was 8.25%.  A reduction in the assumed rate of return would result in increases in pension liability and pension costs.

 

DERIVATIVES

 

The Company accounts for derivative transactions according to the provisions of Statement of Financial Accounting Standards (FAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended.  These standards require that the fair value of all derivative financial instruments be recognized as either assets or liabilities on the Company’s balance sheet and the recognition of unrealized gains and losses in Other Comprehensive Income or in the calculation of Net Income, depending on the nature of the hedge.

 

Most of the Company’s contracts for purchase and sale of natural gas qualify for the normal purchase and normal sales exception under FAS No. 133, and are not required to be recorded as derivative assets and liabilities.  Accordingly, the Company recognizes revenues and expenses on an accrual basis, based on physical delivery of natural gas.  The Company applies mark-to-market accounting to financial derivative contracts.  Periodic changes in fair market value of derivatives associated with supplies for non-core customers are recognized in earnings or, if hedge accounting is applied, in Other Comprehensive Income.  The Company applies FAS No. 71 to periodic changes in fair market value of derivatives associated with supplies for core customers and records an offset in regulatory asset and regulatory liability accounts.

 

New Accounting Standards

 

Information on new accounting standards is included in the Notes to the Consolidated Financial Statements contained in Part II, Item 8, of this report.

 

21



 

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

 

The Company has evaluated its risk related to financial instruments whose values are subject to market sensitivity.  The Company has fixed-rate debt obligations but does not currently have derivative financial instruments subject to interest rate risk.  Cascade makes interest and principal payments on these obligations in the normal course of its business and may redeem these obligations prior to normal maturities if warranted by market conditions.

 

The Company’s natural gas purchase commodity prices are subject to fluctuations resulting from weather, congestion on interstate pipelines, and other unpredictable factors.  The Company’s Purchased Gas Cost Adjustment (PGA) mechanisms assure the recovery in customer rates of prudently incurred wholesale cost of natural gas purchased for the core market.  The Company primarily utilizes financial derivatives, and to a lesser extent, fixed price physical supply contracts to manage risk associated with wholesale costs of natural gas purchased for customers.

 

With respect to derivative arrangements covering natural gas supplies for core customers, periodic changes in fair market value are recorded in regulatory asset or regulatory liability accounts, pursuant to authority granted by the WUTC and OPUC, recognizing that settlements of these arrangements will be recovered through the PGA mechanism.

 

For derivative arrangements related to supplies for non-core customers, which are not covered by a PGA mechanism, periodic changes in fair market value are recognized in earnings or in Other Comprehensive Income.

 

FORWARD-LOOKING STATEMENTS

 

The Company’s discussion in this report, or in any information incorporated herein by reference, may contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.  All statements, other than statements of historical facts, are forward-looking statements, including statements concerning plans, objectives, goals, strategies, and future events or performance.  When used in Company documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, or similar words are intended to identify forward-looking statements.

 

These forward-looking statements reflect the Company’s current expectations, beliefs and projections about future events that we believe may affect the Company’s business, financial condition and results of operations, and are expressed in good faith and are believed to have a reasonable basis.  However, each such forward-looking statement involves risks, uncertainties and assumptions, and is qualified in its entirety by reference to the following important factors, among others, that could cause the Company’s actual results to differ materially from those projected in such forward-looking statements:

 

                  prevailing state and federal governmental policies and regulatory actions, including those of the Washington Utilities and Transportation Commission, the Oregon Public Utility Commission, and the U.S. Department of Transportation’s Office of Pipeline Safety, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, the maintenance of pipeline integrity, and present or prospective wholesale and retail competition;

 

                  weather conditions and other natural phenomena;

 

                  unanticipated population growth or decline, and changes in market demand caused by changes in demographic or customer consumption patterns;

 

                  changes in and compliance with environmental and safety laws, regulations and policies, including environmental cleanup requirements;

 

                  competition from alternative forms of energy and other sellers of energy;

 

                  increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, as well as consolidation in the energy industry;

 

                  the potential loss of large volume industrial customers due to “bypass” or the shift by such customers to special competitive contracts at lower per-unit margins;

 

                  risks, including creditworthiness, relating to performance issues with customers and suppliers;

 

22



 

                  risks resulting from uninsured damage to the Company’s property, intentional or otherwise, or from acts of terrorism;

 

                  unanticipated changes that may affect the Company’s liquidity or access to capital markets;

 

                  unanticipated changes in interest rates or in rates of inflation;

 

                  economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas;

 

                  unanticipated changes in operating expenses and capital expenditures;

 

                  unanticipated changes in capital market conditions, including their impact on future expenses and liabilities relating to employee benefit plans;

 

                  potential inability to obtain permits, rights of way, easements, leases, or other interests or necessary authority to construct pipelines, or complete other system expansions;

 

                  changes in the availability and price of natural gas; and

 

                  legal and administrative proceedings and settlements.

 

In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this report, or in any information incorporated herein by reference, may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.  All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements.

 

Any forward-looking statement by the Company is made only as of the date on which such statement is made.  The Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of any unanticipated events.  New factors emerge from time to time, and the Company is not able to predict all such factors, nor can it assess the impact of each such factor or the extent to which such factors may cause results to differ materially from those contained in any forward-looking statement.

 

23



 

Item 8.   Financial Statements and Supplementary Data

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of
Cascade Natural Gas Corporation
Seattle, Washington

 

We have audited the accompanying consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the ”Company”) as of September 30, 2005 and 2004, and the related consolidated statements of income and comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2005. Our audits also included the consolidated financial statement schedule listed in the Index as Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and the consolidated financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cascade Natural Gas Corporation and subsidiaries as of September 30, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

 

As discussed in Note 3, the accompanying 2004 and 2003 consolidated financial statements have been restated.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of September 30, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 9, 2005, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

 

\s\ Deloitte & Touche LLP

 

 

Seattle Washington
December 9, 2005

 

24



 

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 

(Dollars in thousands except per-share data)

 

 

 

Year Ended September 30,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

(restated,
see Note 3)

 

Operating Revenues

 

$

326,500

 

$

318,078

 

$

302,755

 

Less

 

 

 

 

 

 

 

Gas purchases

 

212,958

 

202,759

 

191,887

 

Revenue taxes

 

21,827

 

21,511

 

20,193

 

Operating Margin

 

91,715

 

93,808

 

90,675

 

 

 

 

 

 

 

 

 

Cost of Operations

 

 

 

 

 

 

 

Operating expenses

 

44,223

 

40,540

 

45,514

 

Depreciation and amortization

 

17,274

 

16,325

 

15,338

 

Property and miscellaneous taxes

 

3,786

 

3,696

 

3,532

 

 

 

65,283

 

60,561

 

64,384

 

 

 

 

 

 

 

 

 

Income from operations

 

26,432

 

33,247

 

26,291

 

 

 

 

 

 

 

 

 

Nonoperating Expense (Income)

 

 

 

 

 

 

 

Interest

 

11,744

 

12,375

 

12,363

 

Interest charged to construction

 

(187

)

(445

)

(378

)

 

 

11,557

 

11,930

 

11,985

 

Amortization of debt issuance expense

 

372

 

618

 

696

 

Other

 

(376

)

(162

)

(227

)

 

 

11,553

 

12,386

 

12,454

 

 

 

 

 

 

 

 

 

Income Before Income Taxes

 

14,879

 

20,861

 

13,837

 

 

 

 

 

 

 

 

 

Income Taxes

 

5,632

 

7,559

 

5,117

 

 

 

 

 

 

 

 

 

Net Income

 

9,247

 

13,302

 

8,720

 

 

 

 

 

 

 

 

 

Other Comprehensive Income (Loss):

 

 

 

 

 

 

 

Minimum pension liability adjustment

 

177

 

1,270

 

(2,619

)

Income tax benefit

 

(56

)

(448

)

937

 

Other Comprehensive Income (Loss)

 

121

 

822

 

(1,682

)

 

 

 

 

 

 

 

 

Comprehensive Income

 

$

9,368

 

$

14,124

 

$

7,038

 

 

 

 

 

 

 

 

 

Earnings Per Common Share, Basic and Diluted

 

$

0.82

 

$

1.19

 

$

0.79

 

 

 

 

 

 

 

 

 

Dividends Paid Per Common Share

 

$

0.96

 

$

0.96

 

$

0.96

 

 

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

 

25



 

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

 

 

 

September 30,

 

 

 

2005

 

2004

 

 

 

(Dollars in thousands)

 

ASSETS

 

 

 

Utility Plant

 

$

597,469

 

$

570,036

 

Less accumulated depreciation

 

257,008

 

242,691

 

 

 

340,461

 

327,345

 

Construction work in progress

 

2,021

 

7,229

 

 

 

342,482

 

334,574

 

Other Assets

 

 

 

 

 

Investments in non utility property

 

202

 

202

 

Notes receivable, less current maturities

 

46

 

43

 

 

 

248

 

245

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

 

1,128

 

499

 

Accounts receivable and current maturities of notes receivable, less allowance of $1,319 and $1,028 for doubtful accounts

 

23,163

 

15,001

 

Prepaid expenses and other assets

 

9,463

 

18,674

 

Derivative instrument asset - energy commodity

 

91,957

 

17,983

 

Materials, supplies, and inventories

 

14,142

 

13,268

 

Deferred income taxes

 

2,292

 

955

 

 

 

142,145

 

66,380

 

Deferred Charges and Other

 

 

 

 

 

Gas cost changes

 

16,630

 

12,288

 

Derivative instrument asset - energy commodity

 

43,440

 

3,952

 

Other

 

7,960

 

5,183

 

 

 

68,030

 

21,423

 

 

 

$

552,905

 

$

422,622

 

 

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

 

26



 

 

 

September 30,

 

 

 

2005

 

2004

 

 

 

 

 

(restated,
see Note 3)

 

 

 

(dollars in thousands)

 

COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES

 

 

 

 

 

Common Shareholders’ Equity

 

 

 

 

 

Common stock, par value $1 per share; Authorized, 15,000,000 shares Issued and outstanding, 11,413,019 and 11,268,069 shares

 

$

11,413

 

$

11,268

 

Additional paid-in capital

 

103,781

 

101,354

 

Accumulated other comprehensive loss

 

(12,487

)

(12,608

)

Retained earnings

 

15,908

 

17,570

 

 

 

118,615

 

117,584

 

 

 

 

 

 

 

Long-Term Debt

 

173,840

 

128,900

 

Current Liabilities

 

 

 

 

 

Short-term debt

 

12,500

 

33,500

 

Current maturities of long-term debt

 

 

14,000

 

Accounts payable

 

17,841

 

12,923

 

Property, payroll, and excise taxes

 

5,520

 

5,287

 

Dividends and interest payable

 

6,920

 

7,125

 

Regulatory liabilities

 

91,217

 

17,209

 

Other current liabilities

 

8,209

 

8,972

 

 

 

142,207

 

99,016

 

Deferred Credits and Other Non-current Liabilities

 

 

 

 

 

Income taxes

 

42,273

 

38,019

 

Investment tax credits

 

1,156

 

1,303

 

Retirement plan obligations

 

19,042

 

20,780

 

Regulatory liabilities

 

50,584

 

10,515

 

Other

 

5,188

 

6,505

 

 

 

118,243

 

77,122

 

Commitments and Contingencies (Note 12)

 

 

 

 

 

$

552,905

 

$

422,622

 

 

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

 

27



 

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY

 

(Dollars in thousands except per-share data)

 

 

 

 

 

 

 

 

 

Accumulated

 

 

 

 

 

 

 

 

 

Additional

 

Other

 

 

 

 

 

Common Stock

 

Paid-In

 

Comprehensive

 

Retained

 

 

 

Shares

 

Par Value

 

Capital

 

Income (Loss)

 

Earnings

 

Balance October 1, 2002

 

 

 

 

 

 

 

 

 

 

 

As previously reported

 

11,045,095

 

$

11,045

 

$

97,360

 

$

(11,748

)

$

17,524

 

Cumulative correction (see Note 3)

 

 

 

 

 

 

 

 

 

(546

)

Balance October 1, 2002 (as restated)

 

11,045,095

 

11,045

 

97,360

 

(11,748

)

16,978

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

Common stock, $.96 per share

 

 

 

 

 

 

 

 

 

(10,647

)

Other comprehensive income (loss)

 

 

 

 

 

 

 

(1,682

)

 

 

Issuance of common stock

 

86,765

 

87

 

1,517

 

 

 

 

 

Net Income (as restated)

 

 

 

 

 

 

 

 

 

8,720

 

Balance, September 30, 2003 (as restated)

 

11,131,860

 

11,132

 

98,877

 

(13,430

)

15,051

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

Common stock, $.96 per share

 

 

 

 

 

 

 

 

 

(10,783

)

Other comprehensive income

 

 

 

 

 

 

 

822

 

 

 

Issuance of common stock

 

136,209

 

136

 

2,477

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

 

 

13,302

 

Balance, September 30, 2004 (as restated)

 

11,268,069

 

11,268

 

101,354

 

(12,608

)

17,570

 

Cash dividends:

 

 

 

 

 

 

 

 

 

 

 

Common stock, $.96 per share

 

 

 

 

 

 

 

 

 

(10,909

)

Other comprehensive income

 

 

 

 

 

 

 

121

 

 

 

Issuance of common stock

 

144,950

 

145

 

2,427

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

 

 

9,247

 

Balance, September 30, 2005

 

11,413,019

 

$

11,413

 

$

103,781

 

$

(12,487

)

$

15,908

 

 

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

 

28



 

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Dollars in thousands)

 

 

 

Year Ended September 30,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

(restated, see
Note 3)

 

Operating Activities

 

 

 

 

 

 

 

Net Income

 

$

9,247

 

$

13,302

 

$

8,720

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation and amortization

 

17,274

 

16,325

 

15,338

 

Deferrals of gas cost changes

 

(9,440

)

(7,001

)

1,336

 

Amortization of gas cost changes

 

5,098

 

6,296

 

5,868

 

Other deferrals and amortizations

 

76

 

1,099

 

6,032

 

Deferred income taxes and tax credits - net

 

2,771

 

12,972

 

3,188

 

Change in current assets and liabilities

 

4,125

 

(10,427

)

(3,782

)

Net cash provided by operating activities

 

29,151

 

32,566

 

36,700

 

 

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

 

 

Construction expenditures

 

(28,893

)

(39,465

)

(28,551

)

Customer contributions in aid of construction

 

882

 

446

 

858

 

Net cash used by investing activities

 

(28,011

)

(39,019

)

(27,693

)

 

 

 

 

 

 

 

 

Financing Activities

 

 

 

 

 

 

 

Proceeds from long-term debt, net

 

42,886

 

 

 

Repayment of long-term debt

 

(14,060

)

(22,030

)

 

Changes in short-term debt

 

(21,000

)

29,700

 

3,800

 

Proceeds from issuance of common stock

 

2,572

 

2,613

 

1,604

 

Dividends paid

 

(10,909

)

(10,783

)

(10,647

)

Net cash used by financing activities

 

(511

)

(500

)

(5,243

)

 

 

 

 

 

 

 

 

Net Increase (Decrease) in Cash and Cash Equivalents

 

629

 

(6,953

)

3,764

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents

 

 

 

 

 

 

 

Beginning of year

 

499

 

7,452

 

3,688

 

End of year

 

$

1,128

 

$

499

 

$

7,452

 

 

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

 

29



 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1 - Nature of Business

 

Cascade Natural Gas Corporation (the Company) is a local distribution company (LDC) engaged in the distribution of natural gas.  The Company’s service territory consists of towns in Washington and Oregon, ranging from the Canadian border in northwestern Washington to the Idaho border in eastern Oregon.

 

As of September 30, 2005, the Company had approximately 196,000 residential customers, 30,000 commercial customers, and 719 industrial and other larger customers.  Approximately 200 of the larger industrial customers are non-core customers.

 

Residential, commercial, and smaller industrial customers are core customers who take traditional “bundled” natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation.  Sales to core customers account for approximately 24% of gas deliveries and 71% of operating margin.  The Company’s sales to its core residential and commercial customers are influenced by fluctuations in temperature, particularly during the winter season.  A warm winter season will tend to reduce gas consumption.  Over the longer term, these fluctuations tend to offset each other, as rates charged to customers are developed based on the assumption of normal weather.  However, consumption is also influenced by energy efficiency of customers’ appliances as well as consumer decisions to reduce natural gas usage in response to higher prices.

 

Non-core customers are generally large industrial, electric generation, and institutional customers who have chosen “unbundled” service, meaning that they select from among several supply and upstream pipeline transportation options, independent of the Company’s distribution service.  The Company’s margin from non-core customers is derived primarily from this distribution service, as well as gas management services.  The principal industrial activities of its customers include the generation of electricity, processing of food, processing of forest products, production of chemicals, and refining of crude oil.

 

The Company is subject to regulation of most aspects of its operations by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).  It is subject to regulatory risk primarily with respect to recovery of costs incurred.  Various deferred charges and deferred credits reflect assumptions regarding recovery of certain costs through temporary customer rate adjustments during future periods.

 

Note 2 - Summary of Significant Accounting Policies

 

The Company’s accounting records and practices conform to the requirements of the uniform system of accounts prescribed by the WUTC and the OPUC.

 

Principles of consolidation:  The consolidated financial statements include the accounts of Cascade Natural Gas Corporation and its wholly-owned subsidiaries:  Cascade Land Leasing Co.; CGC Properties, Inc.; CGC Energy, Inc.; and CGC Resources, Inc.  All inter-company transactions are eliminated in consolidation.

 

Utility plant:  Utility plant is stated at the historical cost of construction or purchase.  These costs include payroll-related costs such as taxes and other employee benefits, supervisory costs, general and administrative costs, and the cost of funds used during construction.  Maintenance and repairs of property, and replacements and renewals of items deemed to be less than units of property, are charged to operations.  Units of utility plant, retired or replaced, are credited to property accounts at cost.  Such amounts plus removal cost, less salvage, are charged to accumulated depreciation.  In the case of a sale of non-depreciable property or major operating units, the resulting gain or loss on the sale is included in earnings.

 

Depreciation of utility plant is computed using the straight-line method.  The Company periodically conducts depreciation studies to establish and update asset depreciation lives.  Asset lives used for computing depreciation range from six to seventy years, and the weighted average annual depreciation rate is approximately 3.0%.  The Company periodically reviews the carrying amount of its utility plant and other long-lived assets for impairment.  An asset is considered impaired when estimated future cash flows are less than the carrying amount of the asset.  In the event the carrying amount of such asset is deemed not recoverable, the asset is adjusted to its fair value.  Fair value is determined based on discounted future cash flow.

 

The Company periodically reviews items, such as its franchises and easements, which may give rise to asset retirement obligations (ARO).

 

30



 

Investments in non-utility property:  Real estate, carried at the lower of cost or estimated net realizable value, is the primary investment.

 

Cash and cash equivalents:  For purposes of reporting cash flows, the Company accounts for all liquid investments with a purchased maturity of three months or less as cash equivalents.  The following provides additional information to the Consolidated Statements of Cash Flows:

 

 

 

2005

 

2004

 

2003

 

 

 

(dollars in thousands)

 

Changes in current assets and current liabilities:

 

 

 

 

 

 

 

Accounts and notes receivable

 

$

(872

)

$

(2,696

)

$

2,327

 

Income taxes

 

2,062

 

(12,026

)

1,156

 

Inventories

 

(875

)

1,468

 

(180

)

Prepaid expenses and other assets

 

(144

)

(504

)

108

 

Accounts payable and accrued expenses

 

3,925

 

3,967

 

(7,192

)

Other

 

29

 

(636

)

(1

)

Net change in current assets and current liabilities

 

$

4,125

 

$

(10,427

)

$

(3,782

)

Cash payments:

 

 

 

 

 

 

 

Interest (net of amounts capitalized)

 

$

11,637

 

$

12,839

 

$

12,288

 

Income taxes

 

$

 

$

4,610

 

$

 

 

Materials, supplies and inventories:  Materials and supplies for construction, operations, and maintenance are recorded at cost.  Inventories of natural gas are recorded at lower of cost or market.

 

Regulatory accounts:  The Company follows Statement of Financial Accounting Standards (FAS) No. 71, “Accounting for the Effects of Certain Types of Regulation”.  This statement provides for the deferral of certain costs and benefits that would otherwise be recognized in revenue or expense, if it is probable that future rates will result in recovery from customers or refund to customers of such amounts.

 

Regulatory assets (liabilities) at September 30, 2005 and 2004 include the following:

 

 

 

2005

 

2004

 

 

 

(dollars in thousands)

 

Non-current Assets

 

 

 

 

 

Gas cost changes

 

$

16,630

 

$

12,288

 

Unamortized loss on reacquired debt

 

1,659

 

1,887

 

Gas supply hedging

 

1,185

 

40

 

Other

 

544

 

501

 

Current Liabilities

 

 

 

 

 

Gas supply hedging

 

(91,217

)

(17,209

)

Non-current Liabilities

 

 

 

 

 

Deferred income taxes

 

(7,044

)

(5,971

)

Gas supply hedging

 

(43,440

)

(3,941

)

Other, net

 

(100

)

(603

)

  Net

 

$

(121,783

)

$

(13,008

)

 

Under Non-current Assets, regulatory assets related to Unamortized loss on reacquired debt, Gas supply hedging, and Other are included on the Consolidated Balance Sheets in “Other Deferred Charges”.

 

Revenue recognition:  The Company recognizes operating revenues based on deliveries of gas to customers.  This includes estimated revenues for gas delivered but not billed to residential and commercial customers from the latest meter-reading date to the end of the accounting period.

 

Allowance for doubtful accounts:  With respect to its residential and commercial customer accounts, the Company establishes an allowance for doubtful accounts based on historical trends and ratios of write-offs to revenues.  With respect to industrial customer accounts, which are generally significantly larger than

 

31



 

residential and commercial, a specific allowance is established for accounts determined to be at risk of collection.

 

Leases:  The Company leases a portion of its vehicle fleet.  These leases are classified as operating leases.  The Company’s primary obligation under these leases is for a twelve-month period, with options to extend the lease thereafter.  Commitments beyond one year are not material.  Rent expense under operating leases totaled $641,000, $776,000, and $835,000 for fiscal years ended September 30, 2005, 2004, and 2003, respectively.

 

Federal income taxes:  Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using currently enacted tax rates.  The Company normalizes temporary differences between book income and taxable income, with the exception of depreciation differences on assets placed in service prior to 1981, consistent with the policies of the WUTC and OPUC.  With respect to utility plant placed in service after 1980, the Company calculates its deferred income tax provision to conform to the Federal normalization requirements, as approved by the WUTC and OPUC.

 

Investment tax credits:  Investment tax credits were deferred and are amortized over the remaining life of the properties that gave rise to the credits.

 

Use of estimates:  The preparation of financial statements, in conformity with accounting principles generally accepted in the United States of America, 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 these estimates.  The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC.  Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, values of derivative instruments, unbilled revenue, and in the determination of depreciable lives of utility plant.

 

Stock-based compensation:  Compensation cost for stock options is measured as the excess of the market price of the Company’s stock at the date of the grant over the price the employee must pay to acquire the stock.  The Company has accounted for its stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” rather than using the fair-value-based method prescribed under FAS No. 123, “Accounting for Stock-Based Compensation.”  The Company has adopted the disclosure requirements of FAS No. 123.  See Note 7 for more information about the Company’s stock-based compensation plan.  Had compensation expense been determined in accordance with FAS No. 123, the Company’s net income and earnings per share would have been as follows:

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

(restated)

 

 

 

(in thousands except per-share data)

 

Net Income

 

 

 

 

 

 

 

As reported

 

$

9,247

 

$

13,302

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