ML031050468
| ML031050468 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 04/07/2003 |
| From: | Mecredy R Rochester Gas & Electric Corp |
| To: | Clark R Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML031050468 (75) | |
Text
Robert C. Mecredy Vice President Always at Your Service Nuclear Operations April 7, 2003 Mr. Robert L. Clark Office of Nuclear Regulatory Regulation U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D.C. 20555
Subject:
Annual Corporate Financial Report R.E. Ginna Nuclear Power Plant Docket No. 50-244
Dear Mr. Clark:
Pursuant to 10 CFR 50.71 (b), Rochester Gas and Electric Corporation (RG&E) submits the attached Energy East Corporation Annual Report for 2002.
Very truly yours, 1000704 An equal opportunity employer 89 East Avenue I Rochester, NY 14649 tel (585) 546-2700 www.rge.com An Energy East Company
(>-r i\
i, l,
1
,-4I Carl,"
II --
J II;--
mIij
. , 1,
- , I II
'.. -,.,o --, w
, 4 e, -
, i 'A
'I,W4 " ";,..l4k-l All ma Il
.7
,A
~-
tN
./ _, I;
a1 - ; .< '.~
i 4.
,;,9.¢A IrzI
,,,,1,'A, ,,
o,, / ! - ~E
/ , B; -, - , /,
A year of analysis and integration
U- A -
- - S - - - -- 6
CEO LETTER TO SHAREHOLDERS FEBRUARY 18,2003
Most equity investors will look back on 2002 as another disappointing year. Difficult economic conditions were aggravated by a crisis in investor confidence brought about by corporate scandals and malfeasance. The utility industry contributed to this "confidence crisis" as strategic choices made by a number of utilities to turbo-charge growth beyond that available in their regulated business simply did not work out.
Despite this market turmoil, Energy East common stock returned 16% in 2002, outperforming the Standard & Poor's Utility Index, which lost 33%, and the Standard & Poor's 500, which lost 23%.
In addition, in January we increased our common stock dividend for the sixth consecutive year. Over that time period, Energy East's dividend has increased by more than 40%. We have been able to achieve steady cash flows, solid earnings and consistent dividend growth by staying focused on our core business -
a super regional, "pipes and wires" energy delivery company.
Energy East has not invested in speculative generation plants, nor do we have any trading or international businesses. Energy East derives predominantly all of its earnings, and cash flow, from conservatively managed, regulated, retail energy delivery businesses. I firmly believe that there is a niche in every investor's portfolio for companies that have strategies such as ours.
1
c Last year, we set the following objectives for 2002:
0
> Complete our merger with RGS Energy L
E T > Implement long-term incentive-based rate plans for NYSEG's T
E natural gas business, as well as the electric and natural gas R
businesses of Rochester Gas and Electric (RG&E), the primary subsidiary of RGS Energy;
> Further integrate the five electric and natural gas utilities that we acquired since 2000; and
> Continue to provide our customers with a reliable, essential, energy infrastructure, their choice of commodity supplier, stable delivery prices, and excellent customer service.
I am proud to say that through the hard work of the entire Energy East team, we accomplished nearly all of these objectives.
essentia I make sure the energy delivery infrastructure-our pipes and wires -remains reliable. '1
_- CMP Maine is the most tree-covered state in the nation. However, CMP customers enjoy 99.9 percent reliability.
r MD NYSEG Infrared sensor technologies are used to inspect On Energy East Our operating utilities have always met or exceeded k'W transmission and distribution facilities their service reliability targets.
2 to identify problems before they affect customers.
10, I 4
(00,011,04 A*
i II 1-I vf 1-i I-I, -"T I -
71E
""I-, I I1: :M s ,
7_ It .K
N 0 l f f ,
in im" W Now
-Lf a
a
-aVA
-( 7m imlaks" ofi I
5-_ 6 k
11 I
I t - -----
t, -
/-Z-I i . -
X V fr - I a At.rfia
E E
Although we completed the RGS Energy strategic combination,
° the earnings of RG&E were disappointing in 2002. We do, L
E however, expect pending regulatory proceedings to result T in improved earnings for both their natural gas and electric E operations in 2003. We were not able to reach agreement R
with the New York State Public Service Commission (PSC) on long-term incentive-based rate plans at RG&E. On the other hand, the PSC did approve a long-term natural gas rate plan for NYSEG that extends through 2008. Long-term rate agreements are desirable because they benefit customers and shareholders alike, as they allow a sharing of the savings created by our strategic combinations.
2002 -was a year in which we dedicated ourselves to the enormously complicated work associated with achieving the original cost savings and efficiency targets we established for our five strategic combinations. Specifically, we initiated three major merger-related efforts - IntegratingEExcellence, Project Spartan, and Information Technology and Supply Chain Optimization.
professional I want to hear a smile in my customer's voice.
CNG We surpassed Service Quality N SCG Our customers give us high marks standards for customer satisfaction, call center for service (87.3%), inpart due to our new "We performance, call center response time and Want to Know" line established for customers to accuracy of meter reading. register comments, suggestions and complaints. 5
c IntegratingEExcellence is an employee driven, enterprise-wide, self-examination of how we conduct our business at each of the operating companies. Hundreds of key employees participated in an in-depth and introspective review, which generated thousands of ideas and identified the best practices throughout our organization, which will result in a substantial reengineering of various operating processes.
Project Spartan is a strategic sourcing approach across the enterprise, which will result in hundreds of new standardized contracts with suppliers that will deliver future cost savings.
These comprehensive and unique efforts resulted in a number K of intangible benefits. I, the operating company Presidents, our Chief Integration Officer and the head of Human Resources, spent five months, from June to November, two to three days a week, on IntegratingEExcellence and phase one of Project Spartan. We brought our people together from the various operating companies for the first time, shared ideas, debated strengths and weaknesses and continued to build the culture of our new organization.
safe & secure I take very seriously my responsibility to 1
protect our customers and our complex operating system.
WIA
.771 F1=[
I N- Energy East Our Integrating N- CMP Our partnership with state and local economic EExcellence initiative identified development agencies resulted ina new financial services best practices to be implemented firm inSouth Portland and a distribution center in the City 8 enterprise-wide. of Lewiston, creating the potential for 500 new jobs.
IK
- A A:
si AI MM NYSEG Our award-winning No CNG Employees joined a Community Watch program has helped team of local officials, neighborhood over 1,000 upstate New York neighbors representatives and area merchants to in need of assistance in the past year. reconstruct Park Street in Hartford and 9 helped develop businesses inthat area.
E These three initiatives, once fully implemented, are expected to
° produce annual savings in excess of $80 million and will begin E
- to take hold in 2003. As you will note in our financial statements, T a one-time pre-tax restructuring charge to earnings of $41 million Tl E was recorded in 2002 as a result of these initiatives.
R While much of our focus in 2002 was on completing the RGS Energy merger and our integration initiatives, we did not lose sight of our most fundamental, yet critical, goal of providing outstanding customer service. Performance was excellent once again in 2002 as all of our utilities continued to meet their targets for reliability and customer satisfaction. Our long-term rate agreements add to customer satisfaction by providing them stable delivery prices for extended periods of time with a choice in their supplier of electricity or natural gas.
As I have reported in previous letters, we have been systematically exiting under-performing or non-core businesses. This year we sold Berkshire Services Solutions and a technology fund investment. Most of these non-core businesses we are exiting were inherited with our acquisitions.
confidence- I anticipate, so we are prepared.
Energy East Project Spartan Now CNG Fire and police standardized materials and equipment personnel rely on us for training in specifications and identified common the area of natural gas emergencies.
10 vendors for all of our operating companies.
N Kb
_M Energy East We have always, and will continue to act in accordance with the highest standards of ethical conduct, and meet any new requirements for financial 12 transparency and accountability.
OWN_ Energy East We complied with the I increased auditing and reporting requirements of the Sarbanes-Oxley Act. 13
C E
While Energy East has minimal electric generation, we do
° have a vested interest in making deregulation of energy supply L successful because we want our customers to benefit from the E
T lowest supply prices possible. Therefore, we have been at the T
E forefront in promoting the combining of regional transmission R
organizations in New York, New England and the Mid-Atlantic states in order to provide greater supply liquidity in the marketplace, and asking regulators to develop financial incentives that encourage infrastructure investments. In New York new generating stations have not been built as state regulators thought they would be when they ordered us to sell our generating plants, and approximately one-third of existing New York power plants are now owned by financially troubled nonutility generators.
Energy East will continue to be heard in the public policy arena on these matters.
Given the spotlight over the past year on the quality of corporate governance in both our industry and others, it is important to emphasize that Energy East is a company that has always taken corporate governance seriously and respects our investors' need for full disclosure. We strive to make our financial statements transparent. Additionally, our Board is structured to provide keen and objective oversight. Other than myself, all members of Energy East's Board of Directors are independent, and our Directors receive a portion of their compensation in Energy East stock. In fact, we are already in compliance with most of the proposed New York Stock Exchange rules on effective corporate governance.
- MAR 13 Energy East announces support for three-region RTO 14 JAN 11 Dividend raised FEB 27 NYPSC approves APR 1 System-wide natural - MAY 1 Project Spartan 4to 96¢ per share NYSEG long-term electric rate gas supply and optimization begins review of supply chain plan and RGS Energy merger contract extended mmm! . 0 0 FEB 22 Connecticut 0 APR 12 240 common " MAY 15 Energy East receives DPUC approves SCG and ONG stock dividend declared high scores incustomer satisfaction long-term rate plans inanational independent survey
Every day we at Energy East are focused on meeting our customer obligations and executing our business strategies. Please take note of the value themes as you read this annual report.
They represent how we conduct our business and what is important to the Energy East team.
Over the past three years, we have built a super regional, "pipes and wires" energy delivery company, and have consistently delivered shareholder value. We are confident that Energy East is getting positioned to deliver modest, but sustainable, earnings and dividend growth F
over the long term.
E B
R On behalf of the Board of Directors, we thank you U
for your continued support.
A R
) k+ 1k, szQ4v 8
Wesley W. von Schack 0 Chairman, President &
0 3 Chief Executive Officer 0 JUN 17 Enterprise-wide Integrating "- JUL 11 24¢ common O AUG 8 CEO and CFO EExcellence initiative begins stock dividend declared attest to the accuracy of JUN 25 Energy East JUL 314% interest current and previously OCT 24 Energy East 2001 annual report wins in Vermont Yankee nuclear filed financial statements announces early retirement 15 ARC award plant sold program at operating utilities AnI
- JUN 15 $400 million I- JUN 28 RGS Energy - License renewal tor RG&E's Ginna nuclear I- OCT 11 24¢ common 0- NOV 20 NYPSC long-term notes issued merger completed plant filed with NRC stock dividend declared approves NYSEG natural to fund RGS Energy merger - Energy East receives high scores in power quality gas long-term rate plan and reliability in a national independent survey
We take ownership and financial responsi y for our actions.
accoun I I I
II 1
I I
I F1I
\ Ill I I - pi Ii, rn-16
\\
-mA
__ M-J
--- I
_~ _
- a
f Per Common Share 2002 2001 % Change Earnings $1.44 $1.61 (11)
Dividends Paid $.96 $.92 4 Book Value at Year End $16.97 $15.26 11 Price at Year End $22.09 $18.99 16 Other Common Stock Information (Thousands)
Average Common Shares Outstanding 131,117 116,708 12 Common Shares Outstanding at Year End 144,966 116,718 24 Operating Results (Thousands)
Total Operating Revenues $4,008,918 $3,759,787 7 Total Operating Expenses $3,416,742 $3,122,899 9 Net Income $188,603 $187,607 1 Energy Distribution:
Megawatt-hours -
Retail Deliveries 26,869 23,238 16 Wholesale Deliveries 5,330 6,048 (12)
Dekatherms -
Retail Deliveries 181,859 148,000 23 Wholesale Deliveries 7,074 9,298 (24)
Total Assets at Year End (Thousands) $10,269,879 $7,269,232 41 highlights 0
18
Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources Restructuring In 2002 Energy East Corporation (Energy East or the company) initiated a corporate restructuring to achieve optimum organizational efficiency and effectiveness. The savings from this initiative are essential for the company to meet the rate reduction or efficiency targets imputed in utility rates by regulators, as well as to meet the expectations of customers and investors. In the fourth quarter of 2002 Energy East recorded $41 million of restructuring expenses, including $5 million for Central Maine Power Company (CMP), $26 million for New York State Electric & Gas Corporation (NYSEG) and a total of $10 million for The Berkshire Gas Company (Berkshire Gas), Connecticut Natural Gas Corporation (CNG) and The Southern Connecticut Gas Company (SCG).
The restructuring expenses would have been $36 million higher, however Rochester Gas and Electric Corporation (RG&E) was required by a New York State Public Service Commission (NYPSC) order approving RGS Energy Group, Inc.'s (RGS Energy) merger with the company to defer its portion of the restructuring charge for future recovery in rates. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced the company's 2002 net income by $24 million or 19 cents per share. Included in those amounts are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%, by April 30, 2003. That includes approximately 70 from CMP, 260 from NYSEG, 245 from RG&E and 75 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.
Energy East and RGS Energy Merger On June 28, 2002, Energy East completed its merger with RGS Energy. Under the merger agreement 45% of RGS Energy common stock, 15.6 million shares, was converted into 27.5 million shares of Energy East common stock valued at $612 million. The value of the shares issued was determined based on the market price of Energy East's stock at the end of the day on June 27, 2002. The remaining 55% of the RGS Energy common stock was exchanged for $753 million in cash, which was $39.50 per RGS Energy share. The purchase price was about
$1.4 billion, which includes $11 million of merger-related costs. The transaction was accounted for using the purchase method. Energy East's consolidated statements of income and cash flows include RGS Energy's results of operations beginning with July 2002. (See Note 3 to the Consolidated Financial Statements.)
As a result of the merger RGS Energy became a wholly-owned subsidiary of Energy East. RG&E continues to be a wholly-owned subsidiary of RGS Energy and NYSEG became a wholly-owned subsidiary of RGS Energy.
Electric Delivery Business The company's electric delivery business consists primarily of its regulated electricity generation, transmission and distribution operations in upstate New York and Maine. 19 Regional Transmission Organization (RTO) > In July 2001 the Federal Energy Regulatory Commission (FERC) issued an order requiring the New York Independent System Operator (NYISO) and neighboring New England and Mid-Atlantic independent system operators (ISOs) to negotiate to form a single Northeast RTO. The NYISO
.. ~. ...;.. v.4 - .; .. u.A: ... L..Z. **c'rr- D_-.f and other parties involved in negotiating the formation of the Northeast RTO participated in mediation facilitated by a FERC administrative law judge (ALJ), leading to a business plan detailing the process to develop a Northeast RTO. The business plan, coupled with an ALJ's report, were submitted to the FERC. NYSEG, CMP and RG&E have consistently advocated the formation of a Northeast/Mid-Atlantic RTO, including PJM Interconnection, L.L.C.
(PJM), or functionally combined markets throughout the Northeast because they believe that a larger wholesale power market is essential to facilitate greater liquidity and competition.
In January 2002 the ISO New England, Inc. (ISO New England) and the NYISO entered into an agreement to consider forming an RTO, and PJM entered into an agreement to form common market systems with the Midwest ISO. The ISO New England and the NYISO submitted a joint petition to the FERC on August 23, 2002, asking for a declaratory order stating that a merger of the two ISOs, as described in the petition, would satisfy FERC requirements for an RTO. On November 22, 2002, the ISO New England and the NYISO withdrew their proposal, citing opposition from stakeholders, including CMP, NYSEG and RG&E. The companies opposed the proposal because, among other things, it failed to demonstrate that the benefits outweighed the costs and failed to recognize the need for a larger market.
In October 2001 FERC commenced a proceeding to consider national standard market design issues and on July 31, 2002, issued a Notice of Proposed Rulemaking (the SMD NOPR). The SMD NOPR proposes rules that would require, among other things, changes in the wholesale power markets, transmission planning services and charges, market power monitoring and mitigation, and the organization and structure of ISOs. CMP, NYSEG and RG&E filed comments jointly with other transmission owners in November 2002 and January 2003. The companies generally support the proposed SMD because it would functionally combine the Northeast markets.
The companies plan to file additional comments in 2003. The proposals in the SMD NOPR include the adoption of an energy market based on locational marginal pricing (LMP), which represents a significant change for some regions of the country. The NYISO already operates a market based on LMP, and ISO New England is in the process of developing and implementing an LMP system.
Transmission Planning and Expansion > In June and July 2001 FERC issued orders that addressed a number of transmission planning and expansion issues that would directly affect CMP, NYSEG and RG&E as transmission owners. The FERC orders discussed giving exclusive responsibility for the transmission planning process to a Northeast RTO, rather than the transmission owners. The orders also discussed redefining the cost-sharing responsibilities of interconnecting generators for transmission expansion costs. On April 24, 2002, and August 16, 2002, FERC issued NOPRs regarding generation interconnection terms, conditions and cost allocation. FERC is expected to issue a final rule in 2003. Additional transmission planning and expansion proposals are included in the SMD NOPR. The company is unable to predict the ultimate effect, if any, of the expected rulemakings on its transmission system or on future capital expenditures.
On January 15, 2003, FERC issued a proposed policy statement on transmission pricing. FERC proposes a 50 basis point return on equity adder on facilities over which transmission owners turn control to an RTO. The NYISO and ISO New England satisfy most of the requirements of an RTO. Additionally, FERC proposes that unaffiliated third parties will receive the equivalent of an additional 150 basis point adder applicable to transmission facilities that transmission owning utilities divest. Finally, FERC proposes a 100 basis point adder for new transmission facilities found appropriate through an RTO planning process. The company is evaluating FERC's policy proposal and plans to file comments.
Electric Transmission Rates > On June 28, 2002, CMP made its required annual informational filing with FERC updating its local transmission formula rates. CMP's annual transmission revenue requirement increased by
$0.6 million reflecting increased costs associated with transmission constraints during periods of high demand.
2 Rates pursuant to this filing became effective June 1, 2002, and reflect actual cost and revenues from the 2001 calendar year.
Sale of Nuclear Interests > (See Note 10 to the Consolidated Financial Statements.) On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's
4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs. The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.
In November 2001 NYSEG sold its 18% interest in the Nine Mile Point 2 nuclear generating station (NMP2) to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale. For its share of NMP2, NYSEG received at closing $59 million in cash and a $59 million 11% promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. (See Note 10 to the Consolidated Financial Statements.)
Upon completion of the sale of NMP2, an asset sale gain of approximately $110 million was recorded, in accordance with the NYPSC's order, as a regulatory liability under Financial Accounting Standards Board (FASB)
Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (Statement 71). The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.
CMP Alternative Rate Plan > In September 2000 the Maine Public Utilities Commission (MPUC) approved CMP's Alternative Rate Plan (ARP 2000). ARP 2000 applies only to CMP's state jurisdictional distribution revenue requirement and excludes revenue requirements related to stranded costs and transmission services.
The revenue requirement related to transmission services is established by FERC. Recovery of stranded costs, primarily overmarket nonutility generator (NUG) contracts and nuclear decommissioning costs, has been provided for under Maine's Restructuring Law. ARP 2000 began January 1, 2001, and continues through December 31, 2007, with price changes, if any, occurring on July 1, in the years 2002 through 2007.
On June 25, 2002, the MPUC approved a filing allowing CMP's distribution prices to change effective July 1, 2002.
As a result, distribution rates for customers not subject to special contracts decreased by 4.84%. The reduction reflects a decrease of 3.03% in distribution rates resulting from expiring amortizations and the application of a price cap mechanism, and an additional one-time decrease of 1.81% reflecting over-collections of certain costs, such as for low-income assistance programs and insurance proceeds related to environmental remediation.
CMP Electricity Supply Responsibility > Under Maine Law adopted in 1997 CMP was mandated to sell its generation assets and relinquish its supply responsibilities. CMP no longer owns any generating assets but does retain its power entitlements under long-term contracts from NUGs and a power purchase contract with Vermont Yankee, and its ownership interests in three nuclear facilities that have been shut down. CMP's retail electricity prices are set to provide recovery of the costs associated with these ongoing obligations.
Under Maine Law the MPUC can mandate that CMP be a standard-offer provider for supply service if the MPUC should deem bids by competitive suppliers to be unacceptable. CMP has no standard-offer obligations through August 2003. If in the future CMP should have standard-offer obligations there would be no effect on net income because CMP is ensured cost recovery through Maine Law. CMP's revenues and purchased power costs will fluctuate, however, as its status as a standard-offer provider changes. (See Operating Results for the Electric Delivery Business and Note 9 to the Consolidated Financial Statements.)
In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy, Inc.
for larger customers. 21 MPUC Stranded Cost Proceeding > In December 2001 the MPUC approved a stipulation among CMP, the Office of the Public Advocate and the Industrial Energy Consumer Group settling all issues related to the setting of CMP's stranded cost revenue requirement for the period March 1, 2002, through February 28, 2005. In January 2002 CMP submitted a compliance filing to the MPUC setting the three-year stranded cost revenue requirement.
tte ej M *~ . *- I :n v r .r -gg % j.nC..%s * .. ..-. % a ,"I
- S The amount of the revenue requirement reflects the ongoing costs related to CMP's remaining nondivested generating resources and the decommissioning of two nuclear power plants, offset by revenues to be received for the output from the remaining nondivested generating resources and amortization of amounts from CMP's gain on sale of generation assets account. Under the terms of the stipulation, parties can request a review of stranded costs if revenues differ significantly from anticipated costs. On December 17, 2002, the MPUC initiated an investigation to review CMP's current level of recovery of stranded costs, including the costs associated with decommissioning the Yankee Atomic plant. As ordered by the MPUC in this proceeding, CMP made its initial filing on February 7, 2003, concluding that no change in the current stranded costs rate is appropriate. CMP expects the MPUC to act on its filing by July 1, 2003.
NYSEG Electric Rate Plan > In February 2002 the NYPSC issued an Order (NYPSC February 2002 Order) approving a five-year NYSEG electric rate plan, which extends through December 31, 2006, and Energy East's merger with RGS Energy. The electric rate plan resulted from a settlement reached by the company, NYSEG, RGS Energy, RG&E, the NYPSC Staff, the Attorney General of the State of New York, the New York State Consumer Protection Board, Multiple Intervenors and other parties. NYSEG's 1998 electric rate and restructuring agreement and an NYPSC Order issued in January 2002, regarding temporary rates for NYSEG's electric customers, were superseded by the NYPSC February 2002 Order. The NYPSC February 2002 Order also provided for the discontinuance of several outstanding NYSEG proceedings. NYSEG's and the company's earnings were lower in 2002 (one year earlier than expected) as a result of the electric rate plan because NYSEG's electric rates now reflect the sale of generation assets that was completed in 1999.
The NYPSC February 2002 Order reduced annualized electric rates by $205 million for NYSEG customers effective March 1, 2002, which amounted to an overall average reduction of 13% for most customers. In the first rate year ending December 31, 2002, approximately $55 million of the annualized reduction was funded with the partial amortization of an asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2. The NYPSC February 2002 Order also requires equal sharing of earnings between NYSEG customers and shareholders of returns on equity in excess of 15.5% for 2002, and equal sharing on the greater of returns on equity in excess of 12.5% on electric delivery, or 15.5% on the total electric business (including supply) for each of the years 2003 through 2006. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45%
equity ratio, which approximates $700 million.
NYPSC-mandated Contracts with Two Customers > In March and April 2002 the NYPSC issued orders directing NYSEG to enter into long-term electric service contracts with Nucor Steel Auburn, Inc. and Corning Incorporated, that in NYSEG's opinion contain unduly low and preferential rates. In April 2002 NYSEG petitioned for rehearing of these orders on the basis that each order, and each underlying contract, violates law, NYSEG's tariffs and NYPSC guidelines. In May 2002 the NYPSC denied NYSEG's petitions for rehearing. On July 24, 2002, NYSEG filed a petition with the New York State Supreme Court, Albany County, asking the court to overturn the NYPSC's orders directing NYSEG to enter into the long-term electric service contracts because the rates and the terms of those mandated contracts are unduly preferential and violate the law, NYSEG's tariffs and the NYPSC's guidelines.
Oral arguments were held in the proceeding on September 13, 2002. On December 9, 2002, the State Supreme Court dismissed NYSEG's petition. NYSEG has appealed that dismissal to the Appellate Division, Third Department, of the New York State Supreme Court. On September 24, 2002, and November 25, 2002, consistent with the NYPSC's orders, NYSEG signed the mandated contracts under protest, subject to review by the courts.
Lost revenues associated with these long-term electric service contracts are recovered through the asset sale gain account created by NYSEG's sale in 2001 of its interest in NMP2 and do not affect earnings. After giving effect to the amortization of the asset sale gain account to fund the first year of the electric rate reduction (See NYSEG 22 Electric Rate Plan), the remaining balance would be entirely consumed by discounts offered to these two large
< industrial customers. NYSEG believes that the remaining balance should not be used for discounts provided to just two customers, but should be available to fund other economic development projects and for the recovery of uncontrollable costs.
Nonutility Generation > In December 1999 NYSEG notified the owners of Allegheny Hydro No. 8 and Allegheny Hydro No. 9 demanding that they each provide adequate assurance that they will perform their individual contractual obligations under two power purchase agreements with NYSEG, including the obligation to pay back overpayments made by NYSEG over the course of the agreements. Such overpayments are the cumulative difference between the rate NYSEG pays for power under the agreements and its actual avoided costs. At the end of 2002 this cumulative overpayment was more than $170 million and is expected to grow substantially by 2030 when both agreements expire. Allegheny and its lenders filed a motion in the New York State Supreme Court (N.Y. County) seeking a declaration that NYSEG's demand for adequate assurance was improper. The motion was denied by the court in September 2002. Unless a settlement can be reached, the matter is expected to proceed to trial.
CMP and NYSEG together expensed approximately $611 million for NUG power in 2002. They estimate that their combined NUG power purchases will total $613 million in 2003, $632 million in 2004, $642 million in 2005,
$578 million in 2006 and $544 million in 2007. CMP and NYSEG continue to seek ways to provide relief to their customers from above-market NUG contracts that state regulators ordered the companies to sign, and which, in 2002, averaged 8.7 cents per kilowatt-hour for CMP and 8.3 cents per kilowatt-hour for NYSEG. Recovery of these NUG costs is provided for in CMP's and NYSEG's current regulatory plans. (See Note 9 to the Consolidated Financial Statements.)
RG&E 2002 Electric and Gas Rate Proceeding > On February 15, 2002, RG&E filed a request with the NYPSC for new electric and natural gas rates to go into effect on January 15, 2003. Subsequently, the date for a decision by the NYPSC was extended to March 2003 with a "make-whole" provision under which rates and any associated mechanisms would be adjusted to put RG&E and its customers in the same position they would have been had rates been allowed to go into effect as of January 15, 2003. The filing included both a traditional single-year filing and elements of a multi-year proposal for potential settlement negotiations. The single-year filing, as updated, provides a basis to increase annual electric rates by $40 million, or 5.7%, and increase annual natural gas rates by $19 million, or 6.6%, for the 12-month period ending June 30, 2003. RG&E's current base rates for electric and natural gas service will remain in effect until a new order is issued by the NYPSC. A lack of progress did not justify continuation of settlement discussions at that time and the parties proceeded on a litigation track.
Evidentiary hearings took place in late October 2002. On December 17, 2002, the ALJ in this proceeding issued a recommended decision that, if approved, would result in a $9 million, or 3.3%, overall increase for natural gas service and no increase for electric service. Briefs on exception to the recommended decision were filed on January 7, 2003. Briefs opposing exceptions were filed on January 17, 2003. Following the submission of briefs settlement conferences in the natural gas proceeding were held.
As part of the current RG&E rate proceeding, the ALJ found RG&E to have excess electric earnings of $45 million, including interest, from RG&E's prior rate plan. RG&E continues to believe its reserve of $26 million for the estimated five-year excess earnings is appropriate. The calculation of the excess earnings will be subject to final approval by the NYPSC. RG&E is unable to predict what the NYPSC's ultimate determination of excess earnings under RG&E's prior rate plan will be.
Ginna Station > Several nuclear power plant operators have identified defects in their reactor vessel heads, which has prompted heightened Nuclear Regulatory Commission (NRC) oversight. During the summer of 2001 RG&E thoroughly reviewed this issue and an inspection plan was implemented during the spring 2002 refueling outage.
Although the inspection demonstrated that the Ginna nuclear generating station (Ginna) could continue to operate with the existing head, RG&E decided to replace the reactor vessel head in order to avoid significant expenditures associated with maintenance, inspections and length of future outages. The replacement is scheduled to be completed during the fall 2003 refueling outage. The duration of the 2003 refueling outage is not expected to 23 be significantly different than the duration of previous outages. The cost of the replacement is estimated to be
$13 million and is expected to be recovered in rates.
", 11~.1 . . It t -i' :}I:'_t.S.I1
."3.:**': .. a7,, 01 4Ji .h...Xi'er s.' 1i i.
Idi 6 . a*us :' .10 . .. .. ... t.',,, .a;;1 d . *: i..4 $ ,.'.
Ginna Relicensing > The Ginna station operating license expires in 2009. On July 31, 2002, RG&E filed a license renewal application with the NRC, which, if approved, would extend the license through September 2029. The NRC has deemed the application complete. The NRC held two sets of public meetings in 2002, and plans to hold one more in 2003. RG&E's renewal application was unopposed. A decision on this matter is expected by the end of 2004.
Natural Gas Delivery Business The company's natural gas delivery business consists of its regulated natural gas transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts.
Natural Gas Supply Agreements > Four of Energy East's natural gas companies - NYSEG, SCG, CNG and Berkshire Gas - have a two-year strategic alliance with BP Energy Company, effective April 1, 2002, for the acquisition, optimization and management of certain natural gas supply, transportation and storage services, including portfolio management. The alliance provides the companies with greater supply flexibility, enhances the benefits of a larger natural gas portfolio and is based on sharing incremental savings. The companies still own and control their natural gas assets and work with BP Energy to obtain the lowest cost supply while maintaining reliability of service. The Energy East natural gas companies have received the required regulatory approvals concerning the alliance.
RG&E entered into a two-year supply portfolio management agreement that began April 1, 2002, with Dynegy Marketing and Trade, for Dynegy to assist RG&E in the cost-effective management of RG&E's firm contractual rights to natural gas supply, transportation and storage services. The agreement is designed to ensure that RG&E can reliably meet its customers' supply requirements while seeking to minimize the annual delivered cost of natural gas. On October 16, 2002, Dynegy announced that it would exit the marketing and trading business over the next several months. As a result of Dynegy's actions RG&E terminated its agreement with Dynegy and entered into a new portfolio management agreement with Entergy-Koch Trading, LP. The new arrangement with Entergy-Koch will extend through March 31, 2004, and includes the same reliability and cost-minimization objectives as the prior agreement with Dynegy. RG&E is assessing its position relative to the Dynegy termination and will take appropriate action to resolve any outstanding issues.
NYSEG Natural Gas Rate Plan > On November 20, 2002, the NYPSC approved the joint proposal that NYSEG filed with the NYPSC on September 13, 2002, and that had been endorsed by NYPSC Staff, the NY State Consumer Protection Board, large customer groups and numerous gas marketers. The approved natural gas rate plan became effective October 1, 2002, freezes overall delivery rates through December 31, 2008, implements a gas supply charge to collect the actual costs of gas and contains an earnings sharing mechanism. The earnings sharing mechanism requires equal sharing of earnings between NYSEG customers and shareholders of returns on equity in excess of 11.5% for the 27-month period ended December 31, 2004, and in excess of 12.5% for each of the calendar years from 2005 through 2008. For purposes of earnings sharing, NYSEG is required to use the lower of its actual equity or a 45% equity ratio, which approximates $240 million.
Connecticut Regulatory Proceedings > During 2001 the Connecticut Office of Consumer Counsel (OCC) filed appeals in State Superior Court arguing that the Connecticut Department of Public Utility Control's (DPUC) order in December 2000 approving an SCG multi-year incentive rate plan (IRP) and its order in May 2001 approving a CNG IRP were unlawful. In March 2001 the OCC filed a Motion to Stay the implementation of the DPUC's order concerning the SCG IRP, but the court denied the motion in June 2001. In August 2001 the court appeals for SCG's and CNG's IRPs were combined.
24 In October 2001 SCG and CNG reached a settlement with the OCC, also endorsed by Prosecutorial Staff of the DPUC, resolving numerous outstanding regulatory and legal proceedings. The proceedings resolved by the settlement include a review of past SCG affiliate transactions, SCG's Purchased Gas Adjustment Clause (PGA) charges and credits, alleged overearnings at SCG and CNG, and a court appeal of the DPUC-approved IRPs for SCG and CNG.
SCG and CNG received a final decision from the DPUC approving the settlement in February 2002. The settlement provided rate reductions of $1.5 million for SCG and $0.5 million for CNG, effective October 1, 2001, extends the approved IRPs for an additional year through September 2005 and maintains an earnings sharing mechanism (ESM) that generally shares any earnings above the authorized returns on equity equally between shareholders and customers. The settlement also permits the recovery of SCG deferred gas costs through the PGA and through the customer portion of earnings sharing by the end of the IRP in 2005. Merger-enabled gas costs savings for both companies are also shared equally between customers and shareholders, with the shareholder portion recovered through the PGA.
In June 2002 the DPUC initiated proceedings to address the need for an interim rate decrease for SCG. Upon review of SCG's financial reports the DPUC concluded that a rate decrease was not required. SCG's earnings in excess of its allowed rate of return were primarily the result of merger-enabled gas costs savings and provided a direct benefit to customers because of the ESM that is an integral part of SCG's IRP.
In April 2002 the DPUC initiated a semiannual review of CNG's PGA. The DPUC issued its draft decision in December 2002, disallowing approximately $1 million of natural gas costs that would be returned to customers through the PGA. As a result, at December 31, 2002, CNG recognized a liability of $1 million for those costs.
The DPUC has postponed its final decision in this matter.
Berkshire Gas Rate Increase > In January 2002 the Massachusetts Department of Telecommunications and Energy (DTE) approved a rate increase of $2.3 million, or 4.5%, on total annual revenues for Berkshire Gas. The new rates became effective February 1, 2002. The DTE's approval included Berkshire Gas' proposal for a 10-year incentive-based rate plan with a midperiod review after five years. After the initial rate increase, rates will be frozen until September 2004, at which time rates will be adjusted annually based on inflation less a 1% consumer dividend. The DTE also approved Berkshire Gas' proposed rate design based on seasonal rates for residential and small commercial and industrial customers that are the same in the winter and summer. Berkshire Gas' proposal for service quality enhancements will be addressed in another proceeding.
RG&E 2002 Electric and Gas Rate Proceeding > See Electric Delivery Business.
NYPSC Collaborative on End State of Energy Competition > In March 2000 the NYPSC instituted a proceeding to address the future of competitive natural gas and electricity markets, including the role of regulated utilities in those markets. Other objectives of the proceeding include identifying and suggesting actions to eliminate obstacles to the development of those competitive markets and providing recommendations concerning Provider of Last Resort and related issues. In a separate phase of this proceeding, the NYPSC issued an order in November 2001 directing the development of embedded cost of service studies for use in implementing unbundled rates.
The embedded cost of service studies have been filed and are currently under review.
Other Businesses The company's other businesses include a nonutility generating company, a liquid fuels distribution company, a retail energy marketing company, telecommunications assets, a propane distribution company, a district heating and cooling system, a FERC-regulated liquefied natural gas peaking plant and an energy services and construction company.
Sale of Other Businesses > The company continues to rationalize its nonutility businesses to ensure they fit its strategic focus. On August 12, 2002, Berkshire Service Solutions, Inc., an energy services provider and a subsidiary of Berkshire Energy Resources (Berkshire Energy), was sold at a loss of about $2 million. 25 Berkshire Energy is a wholly-owned subsidiary of Energy East. During the fourth quarter of 2002 CNE <2 Venture Tech Inc., a subsidiary of Connecticut Energy Corporation (CNE), sold its 5% interest in the Nth Power Technologies Fund II, LP, at a loss of about $1 million.
st.4iz~..%e"'s<'~l
'.' '..,b.atS.. ,-'.U.Aut: MS~.8a'2';tg'JL¶SgwemueahrbPZTUy U! t ~ .:Z; aS~
iAYe .t*If .h ~.7 C-; &.'I.* itudgls Maine Natural Gas > In June 2001 Maine Natural Gas began construction of a new natural gas distribution system to serve the towns of Bowdoin, Brunswick and Topsham, Maine. It has served natural gas to certain larger customers since November 2001 and began serving residential and commercial customers in early 2002.
Maine Natural Gas is also expanding its distribution system in Windham and Gorham, Maine.
Natural Gas Storage Facility > In August 2001 Seneca Lake Storage, Inc. (SLSI), a subsidiary of the company, announced plans to develop a high-deliverability natural gas storage facility in depleted salt caverns in the Town of Reading, New York. SLSI is currently assessing the demand for the facility. The storage facility would be linked to interstate pipelines, have a working gas capacity of 300,000 dekatherms (dth) and be capable of delivering up to 50,000 dth a day. In February 2002 FERC issued a certificate allowing the construction of certain natural gas storage facilities and requiring that the facilities be completed and made available for service within one year of the order. In December 2002 FERC granted a request by SLSJ to modify the certificate to extend by one year the date within which SLSI has to complete construction of the proposed facilities and initiate service.
Other Matters Accounting Issues Statement 71 > Statement 71, Accounting for the Effects of Certain Types of Regulation, allows companies that meet certain criteria to capitalize, as regulatory assets, incurred costs that are probable of recovery in future periods. Those companies record, as regulatory liabilities, obligations to refund previously collected revenue or obligations to spend revenue collected from customers on future costs.
The company believes its public utility subsidiaries will continue to meet the criteria of Statement 71 for their regulated electricity and natural gas operations in New York State, Connecticut, Maine and Massachusetts; however, the company cannot predict what effect a competitive market or future actions of the NYPSC, MPUC, DPUC or DTE will have on their ability to continue to do so. If the company's public utility subsidiaries can no longer meet the criteria of Statement 71 for all or a separable part of their regulated operations, they may have to record as expense or revenue certain regulatory assets and liabilities.
Statement 143 > In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The company adopted Statement 143 as of January 1, 2003.
The adoption of Statement 143 did not have a material effect on the company's financial position or results of operations. (See Note 1 to the Consolidated Financial Statements.)
Statement 145 > In April 2002 the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.
Early application of the provisions of Statement 145 is encouraged and the company elected to do so beginning in April 2002. The company now classifies the aggregate of gains and/or losses from the early extinguishment of debt as other income or other deductions on its income statement, as appropriate, instead of as an extraordinary item. The company has reclassified such extraordinary items presented on its income statements in prior periods.
The remaining provisions of Statement 145 did not have a material effect on the company's financial position or results of operations.
Statement 146 > In June 2002 the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. Statement 146 requires that a liability for a cost associated 26 with an exit or disposal activity be recognized when the liability is incurred, rather than at a plan or commitment date for the exit or disposal activity. It establishes fair value as the objective for initial measurement of the liability. The provisions of Statement 146 are effective for exit or disposal activities initiated after December 31, 2002. The company and its subsidiaries have determined that their adoption of Statement 146, on January 1, 2003, did not have a material effect on their results of operations or financial position.
Contractual Obligations and Commercial Commitments At December 31, 2002, the company's contractual obligations and commercial commitments that will become due during the next five years are:
2003 2004 2005 2006 2007 (Thousands)
Contractual Obligations Long-term debt $542,909 $41,322 $59,229 $338,967 $230,695 Capital lease obligations 2,495 2,517 2,382 2,190 2,055 Operating leases 16,572 15,663 13,955 12,281 12,222 Nonutility generator purchase power obligations 613,398 631,647 641,954 578,011 543,644 Nuclear plant obligations 58,134 54,078 60,448 61,742 52,045 Unconditional purchase obligations 297,123 260,024 218,672 188,439 175,622 Other long-term obligations 8,015 8,735 8,816 6,819 5,909 Total contractual cash obligations $1,538,646 $1,013,986 $1,005,456 $1,188,449 $1,022,192 Other Commercial Commitments Lines of credit $754,750 $258,000 $258,000 -
Standby letters of credit 334,100 334,100 - -
Guarantees 61,600 2,500 - -
Total commercial commitments $1,150,450 $594,600 $258,000 -
Energy East has two revolving credit agreements in which it covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization was 0.59 to 1.00 at December 31, 2002.
CMP has a revolving credit facility, which is secured by its accounts receivable, in which it covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00.
Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
NYSEG and RG&E have a joint revolving credit agreement in which they each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity for the party in default. At December 31, 2002, the ratio of earnings before interest expense and income tax to interest expense was 3.4 to 1.0 for NYSEG and 2.3 to 1.0 for RG&E, and the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.52 to 1.00 for RG&E.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed 27 0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
.. j--a *P..- *. I *1l.ATr w 7. S * . ~
Critical Accounting Policies In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. The company's most critical accounting policies include the determination of the appropriate accounting for its pensions and other postretirement benefits, the effects of utility regulation on its financial statements and its risk management activities and the estimates and assumptions used to complete its annual goodwill and other intangibles impairment analyses.
Goodwill and Other Intangible Assets > As required by Statement 142, effective January 1, 2002, the company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized and are reviewed for impairment. The impairment test includes various assumptions. The primary assumptions are the discount rate and forecasted cash flows. Changes in those assumptions could have a significant effect on the company's determination of an impairment. (See Note 4 to the Consolidated Financial Statements.)
Pension and Other Postretirement Benefit Plans > The company has pension and other postretirement benefit plans covering substantially all of its employees. In accordance with Statement of Financial Accounting Standards No. 87, Employer's Accounting for Pensions, and Statement of Financial Accounting Standards No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, the valuation of benefit obligations and the performance of plan assets are subject to various assumptions. The primary assumptions include the discount rate.
expected return on plan assets, rate of compensation increase, health care cost inflation rates, expected years of future ser-vice under the pension benefit plans and the methodology used to amortize gains or losses. Changes in those assumptions could also have a significant effect on the company's noncash pension income or expense or on the company's postretirement benefit costs. As of December 31, 2002, the company decreased the discount rate from 7.0% to 6.5% and the expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
(See Results of Operations - Other Items.)
Risk Management > See Quantitative and Qualitative Disclosures About Market Risk and Note 1 to the Consolidated Financial Statements.
Utility Regulation > The company's regulated utilities are subject to regulation by their respective state regulatory commissions and the FERC. Approximately 90% of the company's revenues are derived from operations that are accounted for pursuant to Statement 71. The rates the utilities charge their customers are based upon cost basis regulation reviewed and approved by those regulatory commissions. (See Accounting Issues Statement 71.)
Investing and Financing Activities Investing Activities > Capital spending totaled $229 million in 2002, $223 million in 2001 and $168 million in 2000, including capital spending for RGS Energy and nuclear fuel for RG&E beginning July 1, 2002. Capital spending does not include the amounts representing the company's merger transaction for RGS Energy in 2002 nor the four merger transactions in 2000. (See Note 3 to the Consolidated Financial Statements.) Capital spending in all three years was financed with internally generated funds and was primarily for the extension of energy delivery service, necessary improvements to existing facilities and compliance with environmental requirements 28 and governmental mandates.
Capital spending is projected to be $338 million in 2003, which includes RGS Energy and nuclear fuel. It is expected to be paid for with internally generated funds and will be primarily for the same purposes described above and merger integration. (See Note 9 to the Consolidated Financial Statements.)
The company's pension plans generated pretax noncash pension income (net amounts capitalized) of $70 million in 2002, compared to $76 million in 2001 and $68 million in 2000. The company expects noncash pension income (net amounts capitalized) for 2003 to decline, affecting earnings by approximately 15 cents per share as compared to 2002. That expected decrease is due to the significant equity market declines over the past several years and revised actuarial assumptions including the discount rate used to compute its pension liability (reduced from 7% to 6.5% as of December 31, 2002) and return on assets (reduced from 9% to 8.75% effective January 1, 2003). The company anticipates minimal funding requirements in 2003 as total plan assets approximates the projected benefit obligation. The company is currently unable to predict the effect that future equity market performance will have on pension income for 2004 and beyond. (See Note 15 to the Consolidated Financial Statements.)
Financing Activities > (See Note 6 to the Consolidated Financial Statements.)
The company raised its common stock dividend 4% in January 2003 to a new annual rate of $1.00 per share.
During 2002 the company repurchased 113,500 shares of its common stock at an average price of $18.85 per share. Future repurchases will depend on expected cash flows, alternative uses of cash, and overall economic and market conditions.
In August 2001 the company began issuing new common shares through its Dividend Reinvestment and Stock Purchase Plan (DRIP) rather than purchasing them on the open market. During 2002 the company issued 852,824 shares at an average price of $20.92 per share through its DRIP, substantially out of treasury stock.
The company expects to issue approximately one million shares per year under this plan.
In December 2002 the company amended its DRIP to allow nonshareholders who reside in Connecticut, Maine, Massachusetts or New York State to enroll directly in the Plan by making an initial cash investment.
The company and its subsidiaries have credit agreements with various expiration dates in 2003 and 2005. The agreements provided for maximum borrowings of $755 million at December 31, 2002 and 2001. (See Contractual Obligations and Commercial Commitments.)
The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements (see above) to finance certain refundings and for other corporate purposes. There was $322 million of such short-term debt outstanding at December 31, 2002, and $173 million outstanding at December 31, 2001.
The weighted-average interest rate on short-term debt was 2.1% at December 31, 2002 and 2.6% at December 31, 2001.
In May 2001 the company filed a shelf registration statement with the Securities and Exchange Commission (SEC) to sell up to $1 billion in an unspecified combination of debt and trust preferred securities. The company has issued $995 million of debt and trust preferred securities under the shelf registration statement to fund the cash portion of the consideration for the merger with RGS Energy, for general corporate purposes, such as short-term debt reduction and to fund an equity contribution to NYSEG in 2001. (See Energy East and RGS Energy Merger.)
In June 2002 the company issued $400 million of 6.75% 10-year notes due June 2012 under the shelf registration statement described above. The proceeds were used to help fund the RGS Energy merger.
In July 2002 the company entered into a fixed-to-floating interest rate swap on the company's 5.75% notes due November 2006. The company receives a fixed rate of 5.75% and will pay a rate based on the six month London Interbank Offered Rate (LIBOR) plus 1.565%, on a notional amount of $250 million through November 2006.
In July 2002 the company terminated a fixed-to-floating interest rate swap on the company's 8.05% notes due November 2010. The company received $16 million, the value of the swap on the date of termination, and will 29 amortize about $15 million of that gain over the remaining life of the notes.
CMP issued the following Series E Medium Term Notes, the proceeds of which were used to repay $50 million of maturing medium-term notes, as well as short-term debt and for general corporate purposes in 2002: in May 2002
- $37.5 million, 6.50%, due May 2009 and $37.5 million, 6.65%, due May 2012; in August 2002 - $15 million,
- ." -. at. , : .; .I. a ~,
El.-. :V _. ' it- z kSa tlW tr a : i-,,
, ;i La-.,yt ** e *.b *: y i .
- 5.70%, due August 2012; in September 2002 - $15 million, 4.25%, due September 2007; and in November 2002 -
$15 million, quarterly adjustable rate based on the three month LIBOR plus 0.6%, due January 2006.
In May 2002 NYSEG redeemed, at a premium, $150 million of 8 7/8% Series first mortgage bonds due November 1, 2021, and redeemed, at par, the remaining $21.34 million of two 9 7/8% Series first mortgage bonds due 2020. The redemptions were financed with internally generated cash and the proceeds from the prepayment of a promissory note by Constellation Nuclear in April 2002. (See Sale of Nuclear Interests). NYSEG incurred a $10 million reduction to earnings in the second quarter of 2002 as a result of these redemptions, but will save over $16 million each year in interest costs. (See Other Matters, Statement 145.)
In November 2002 NYSEG issued $150 million of 4 3/8% unsecured notes due November 2007 and $100 million of 5 112% unsecured notes due November 2012. NYSEG used the net proceeds from those notes to refund commercial paper that was used in October 2002 to repay $150 million of maturing 6 3/4% Series first mortgage bonds and to repay $100 million of 8.30% Series first mortgage bonds that were called on December 15, 2002.
In 2003 NYSEG plans to call its remaining first mortgage bonds: $50 million of 7.55% Series first mortgage bonds callable on April 1, 2003, and $100 million of 7.45% Series first mortgage bonds callable on July 15, 2003.
Additional financing needed by NYSEG to call its remaining first mortgage bonds is expected to be completed in June 2003. Through financial instruments issued in September 2002, NYSEG has locked in the 10-year treasury rate component of that financing at an average rate of 4.085%.
On January 9, 2003, RG&E used a $50 million equity contribution from its parent, RGS Energy, along with internally generated funds, to pay off the remaining $80 million balance of a 7% promissory note that was due to mature in 2014.
In July 2002 CNG paid at maturity $10 million of medium term notes using short-term debt. In October 2002 CNG redeemed $3.5 million of Series AA first mortgage bonds, including $2.5 million pursuant to a sinking fund provision and $1 million at a premium, using short-term debt.
Quantitative and Qualitative Disclosures About Market Risk Market risk represents the risk of changes in value of a financial or commodity instrument, derivative or nonderivative, caused by fluctuations in interest rates and commodity prices. The following discussion of the companies' risk management activities includes "forward-looking" statements that involve risks and uncertainties.
Actual results could differ materially from those contemplated in the "forward-looking" statements. The companies handle market risks in accordance with established policies, which may include various derivative transactions. (See Note 1 to the Consolidated Financial Statements.)
The financial instruments held or issued by the companies are for purposes other than trading or speculation.
Quantitative and qualitative disclosures are discussed as they relate to the following market risk exposure categories: Interest Rate Risk, Commodity Price Risk and Other Market Risk.
Interest Rate Risk > The companies are exposed to risk resulting from interest rate changes on their variable-rate debt and commercial paper. The company and its subsidiaries use interest rate swap agreements to manage interest rate risk and/or to maintain desired fixed-to-floating rate ratios. Amounts paid and received under those agreements are recorded as adjustments to the interest expense of the specific debt issues. The companies estimate that, at December 31, 2002, a 1% change in average interest rates would change annual interest expense for variable rate debt by about $4.6 million for Energy East, including $0.2 million for CMP, $1.3 million for NYSEG and $0.7 million for RG&E. (See Notes 6 and 12 to the Consolidated Financial Statements.)
30 The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.
Commodity Price Risk > Commodity price risk is a significant issue for the company, NYSEG and RG&E due to volatility experienced in both the electric and natural gas wholesale markets. The companies manage this risk through a combination of regulatory mechanisms, such as allowing for the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. These measures mitigate the companies' commodity price exposure, but do not completely eliminate it.
Although CMP has no long-term supply responsibilities, the MPUC can mandate that CMP be a standard-offer provider for supply service should bids by competitive suppliers be deemed unacceptable by the MPUC. (See CMP Electricity Supply Responsibility.) In September 2001 the MPUC chose Constellation Power Source Maine, LLC as the new supplier of standard-offer electricity to CMP's residential and small commercial standard-offer class for a three-year period beginning March 1, 2002. In January 2003 the MPUC chose suppliers of standard-offer electricity for the six months beginning March 1, 2003: FPL Energy Power Marketing, Inc. for medium class customers and Select Energy, Inc. for larger customers.
All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. (See Natural Gas Supply Agreements, NYSEG Natural Gas Rate Plan and Connecticut Regulatory Proceedings.)
NYSEG and RG&E use natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures is included in the commodity cost when the related sales commitments are fulfilled.
NYSEG and RG&E use electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.
NYSEG's electric rate plan offers retail customers choice in their electricity supply including a variable rate option, an option to purchase electricity supply from an alternative energy company, and a bundled rate option. Based on the results from the enrollment period that ended December 31, 2002, approximately 30% of NYSEG's total electric load is now provided by an alternative energy company or at the market price. NYSEG's exposure to fluctuations in the market price of electricity is limited to the load required to serve those customers who select the bundled rate option, which combines delivery and supply service at a fixed price. For calendar years 2003 and 2004 the supply component is based on average electricity forward prices for 2003 and 2004 during September 2002, plus a 35% margin to cover the costs and risk that NYSEG is assuming by providing a bundled rate option to retail customers. NYSEG is actively hedging the load required to serve customers who select the bundled rate option. As of January 31, 2003, NYSEG's load was 93% hedged for on-peak periods and 87% hedged for off-peak periods in 2003 and 86% hedged for both on-peak and off-peak periods in 2004. A fluctuation of $1.00 per megawatt-hour in the price of electricity would change earnings by $0.7 million in 2003 and $1 million in 2004.
The percent of NYSEG's hedged load is based on NYSEG's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast.
RG&E faces commodity price risk that relates to market fluctuations in the price of electricity and natural gas.
Under its electric settlement, RG&E's electric rates were capped at specified levels through June 30, 2002. Owned electric generation and long-term supply contracts significantly reduce RG&E's exposure to market fluctuations for procurement of its electric supply. As of January 31, 2003, RG&E's load was 90% hedged for on-peak periods and fully hedged for off-peak periods in 2003 and fully hedged for both on-peak and off-peak periods in 2004.
A fluctuation of $1.00 per megawatt-hour in the price of on-peak electricity would change earnings by $0.2 million 31 in 2003. The percent of RG&E's hedged load is based on RG&E's load forecasts, which include certain assumptions such as historical weather patterns. Actual results could differ as a result of changes in the load compared to the load forecast. RG&E has filed a request with the NYPSC for new electric rates commencing in January 2003. The NYPSC has not ruled on the rate request; therefore, RG&E's current fixed electric rates will remain in effect until
7
- Z..' be..
¢i , *d *aua;
.I.;;.m5IA&&Gt
,i ;-.;,, ^v'a@wa** I..,,sm$ni'.RCw::T".a.. e?;,e, Am.':. ,^;.1.
.I:. ' e6:
a new rate order is issued. A new rate order is expected to be issued in March 2003, for electric rates retroactive to January 2003. (See RG&E 2002 Electric and Gas Rate Proceeding.)
While owned coal-fired and nuclear generation provides RG&E with a natural hedge against electric price risk, it also subjects it to operating risk. Operating risk is managed through a combination of strict operating and maintenance practices and the use of derivative contracts.
The broad and continued decline in credit quality across the energy supply and marketing industries combined with the withdrawal of many entities from energy trading operations could limit the company's ability to purchase electricity and place financial hedges with counterparties that meet its credit requirements. While the company has been successful in implementing its hedging strategies by finding creditworthy counterparties or requiring adequate financial assurances in the form of cash or letters of credit, continued contraction and credit deterioration across the energy supply and marketing industries may adversely affect the company's ability to effectively implement its hedging strategies going forward.
Other Market Risk > The companies' pension plan assets are primarily made up of equity and fixed income investments. Fluctuations in those markets as well as changes in interest rates cause the companies to recognize increased or decreased pension income or expense. If the expected return on plan assets were to change by 1/4%,
pension income would change by approximately $6 million. (See Note 15 to the Consolidated Financial Statements.)
Forward-looking Statements This Annual Report contains certain forward-looking statements that are based upon management's current expectations and information that is currently available. The Private Securities Litigation Reform Act of 1995 provides a safe harbor for forward-looking statements in certain circumstances. Whenever used in this report, the words "estimate," "expect," "believe," or similar expressions are intended to identify such forward-looking statements.
In addition to the assumptions and other factors referred to specifically in connection with such statements, factors that involve risks and uncertainties and that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others: the deregulation and continued regulatory unbundling of a vertically integrated industry; the companies' ability to compete in the rapidly changing and increasingly competitive electricity and/or natural gas utility markets; regulatory uncertainty in a politically-charged environment of changing energy prices; the operation of the NYISO and ISO New England; the operation of a regional transmission organization; the ability to recover nonutility generator and other costs; changes in fuel supply or cost and the success of strategies to satisfy power requirements now that most generation assets have been sold; the company's ability to expand its products and services, including its energy infrastructure in the Northeast; the company's ability to integrate the operations of Berkshire Energy, CMP Group, CNE, CTG Resources and RGS Energy with its operations and achieve anticipated synergies; market risk; the ability to obtain adequate and timely rate relief; nuclear or environmental incidents; legal or administrative proceedings; changes in the cost or availability of capital; growth in the areas in which the companies are doing business; weather variations affecting customer energy usage; authoritative accounting guidance; acts of terrorists; and other considerations, such as the effect of the volatility in the equity markets on pension benefit cost, that may be disclosed from time to time in the companies' publicly disseminated documents and filings. The companies undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.
32 Results of Operations Due to the various mergers completed by the company, its results of operations include for 2002: RGS Energy beginning with July 2002; and for 2000: CNE beginning with February 2000 and CMP Group, CTG Resources and Berkshire Energy beginning with September 2000.
2002 2001 over over 2001 2000 2002 2001 2000 Change Change (Thousands, except per share amounts)
Operating Revenues $4,008,918 $3,759,787 $2,959,520 7% 27%
Operating Income $592,176 $636,888 $513,921 (7%) 24%
Net Income $188,603 $187,607 $235,034 1% (20%)
Average Common Shares Outstanding 131,117 116,708 114,213 12% 2%
Earnings Per Share, basic and diluted $1.44 $1.61 $2.06 (11%) (22%)
Dividends Paid Per Share $.96 $.92 $.88 4% 5%
Earnings Per Share Earnings per share for 2002 were $1.44 compared to $1.61 for 2001, and include the nonrecurring items shown in the following table. The decrease in earnings for 2002 excluding nonrecurring items was primarily the result of an electric rate reduction of $205 million ordered by the NYPSC for NYSEG, effective March 1, 2002, which reduced earnings 50 cents per share. Other items that reduced earnings include: 16 cents per share for higher operating costs, such as the cost of merger integration efforts; 15 cents per share for fewer wholesale sales at lower market prices and 7 cents per share for a loss on early retirement of debt. Those decreases were significantly offset by increases of 29 cents per share due to lower natural gas costs, which includes the benefit of NYSEG's natural gas supply charge that went into effect October 1, 2002; 13 cents per share for higher electric deliveries (primarily residential and commercial) due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; and 19 cents per share due to the elimination of goodwill amortization in 2002.
Earnings per share for 2001 were $1.61 compared to $2.06 for 2000, and include the nonrecurring items shown in the following table. The increase in 2001 earnings excluding nonrecurring items was primarily due to 20 cents per share for cost control efforts, 10 cents per share due to earnings from the merged companies, I cent per share for a loss on early retirement of debt in 2000 and 4 cents per share for a loss on the sale of XENERGY in 2000.
Those increases were partially offset by 23 cents per share for lower electric and natural gas deliveries due to warmer weather and 13 cents per share for reduced electric transmission revenues.
2002 2001 2000 Earnings per share, basic and diluted $1.44 $1.61 $2.06 Restructuring expenses .19 - -
Writedown of investment in NEON Communications (See Note 12 to the Consolidated Financial Statements) .06 .39 -
Benefit from sale of coal-fired generation assets - - (.07)
Earnings Per Share, excluding nonrecurring items $1.69 $2.00 $1.99 The company provides information on earnings exclusive of nonrecurring items because it believes this information may be helpful to investors in assessing the company's results of ongoing operations. The company cautions investors that its view of nonrecurring items may differ from that of other companies and earnings exclusive of nonrecurring items should not be used as a surrogate for reported earnings prepared in accordance with generally accepted accounting principles.
Other Items 33 Other operating expenses includes net periodic pension benefit income of $70 million in 2002, $76 million in 2001 and $68 million in 2000. Other operating expenses would have been $6 million lower for 2002 and would have been $8 million higher for 2001 without those changes in net periodic pension benefit income. Net periodic pension benefit income represented 22% of net income for 2002, 24% for 2001 and 17% for 2000. The earnings
.l..'A_'ia Lts 'e t5ax^.> *u ' ed;:e aSh.afl.h&ag
. , i.,Cgr. .. Ad. <t1 f+ '4 .
- n. riof .P'.ea.
effect from differences between actual and projected pension benefit income was based on any earnings sharing mechanisms approved by state utility commissions.
Other (income) decreased $8 million in 2002 primarily due to a decrease in miscellaneous income of $6 million, and decreased $14 million in 2001 primarily due to an $18 million decrease in interest income largely due to funds used to finance the company's merger transactions in 2000. Other deductions increased $10 million in 2002 primarily due to NYSEG's $16 million loss on early retirement of debt and were unchanged in 2001. (See Financing Activities and Note 1 to the Consolidated Financial Statements.)
Interest charges increased $41 million in 2002 including $34 million because of the addition of RGS Energy and
$17 million for additional borrowings to finance the company's merger transaction with RGS Energy. Those increases were partially offset by $10 million of interest savings due to NYSEG's refinancings and repayments of first mortgage bonds. Interest charges increased $65 million in 2001 due to a $32 million increase for additional borrowings to finance the company's merger transactions, including the RGS Energy merger, and a $32 million increase for interest charges due to the acquisitions of CNE, CMP Group, CTG Resources and Berkshire Energy in 2000.
The $18 million increase in preferred stock dividends in 2002 includes $16 million due to the company's issuance of trust preferred securities in July 2001 and $2 million because of the addition of RGS Energy. Preferred stock dividends increased $13 million in 2001 due to the company's issuance of trust preferred securities in July 2001.
The effective tax rate was 31% in 2002 and 43% in 2001. The decrease is the result of various items including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.
Operating Results for the Electric Delivery Business 2002 2001 over over 2001 2000 2002 2001 2000 Change Change (Thousands)
Deliveries - Megawatt-hours Retail 26,869 23,238 17,133 16% 36%
Wholesale 5,330 6,048 6,214 (12%) (3%)
Operating Revenues $2,568,247 $2,504,896 $2,023,610 3% 24%
Operating Expenses $2,119,218 $1,951,475 $1,540,953 9% 27%
Operating Income $449,029 $553,421 $482,657 (19%) 15%
Operating Revenues > The $63 million increase in operating revenues for 2002 is primarily due to the addition of RG&E's delivery revenues of $369 million and increased retail deliveries of $33 million primarily due to warmer summer weather in 2002. Those increases were partially offset by a reduction of $138 million because CMP is no longer the standard-offer provider for the supply of electricity effective in March 2002; $114 million due to a rate reduction for NYSEG, effective March 1, 2002; and lower wholesale revenues of $64 million primarily due to lower market prices for electricity.
Operating revenues for 2001 increased $481 million compared to 2000 primarily due to the first full year of CMP's delivery revenues, which added $565 million, and amortization of deferred gains of $9 million. Those increases were partially offset by $37 million due to lower wholesale deliveries because of warmer weather, $32 million as a result of CMP no longer collecting revenue for the supply of electricity to certain retail customers and $22 million 34 due to reduced transmission revenues.
Operating Expenses > Operating expenses for 2002 increased $168 million. The increase in operating expenses for 2002 was $131 million excluding $25 million for restructuring expenses in 2002 and $12 million for the effect of the sale of NYSEG's share of NMP2 in 2001. That increase includes $291 million for the addition of RG&E's
operating expenses; $15 million of purchased power costs for higher retail deliveries due to warmer summer weather in 2002 and colder winter weather in the fourth quarter of 2002; $15 million for merger integration efforts; and $44 million for purchased power costs to replace energy previously provided by NMP2, which was partially offset by a $35 million decrease in certain operating expenses due to the sale of NMP2. Those increases were partially offset by decreases including $138 million of electricity purchased because CMP is no longer the standard-offer provider for the supply of electricity, $32 million due to lower market prices for electricity and
$9 million due to the elimination of goodwill amortization in 2002.
Operating expenses for 2001 increased $411 million. The increase in operating expenses for 2001 was $423 million, excluding $12 million for the effect of the sale of NYSEG's share of NMP2, primarily due to the first full year of CMP's operating costs of $490 million. That increase was partially offset by $31 million because of lower purchased power costs primarily due to lower deliveries, $17 million for lower electricity supply costs because CMP no longer supplies electricity unless directed to by the MPUC, and $18 million due to cost control efforts relating to retirement benefits and compensation.
Operating Results for the Natural Gas Delivery Business 2002 2001 over over 2001 2000 2002 2001 2000 Change Change (Thousands)
Deliveries - Dekatherms Retail 181,859 148,000 108,139 23% 37%
Wholesale 7,074 9,298 10,674 (24%) (13%)
Operating Revenues $1,032,539 $1,026,124 $772,131 1% 33%
Operating Expenses $882,883 $936,606 $699,402 (6%) 34%
Operating Income $149,656 $89,518 $72,729 67% 23%
Operating Revenues > Operating revenues increased $6 million for 2002. Operating revenues increased
$126 million due to the addition of RG&E's delivery revenues and $8 million due to increased deliveries primarily because of colder winter weather in the fourth quarter of 2002. Those increases were partially offset by a $98 million decrease because of lower market prices of natural gas that are passed on to customers and a $30 million decrease due to fewer wholesale customers.
For 2001, operating revenues increased $254 million primarily due to the first full year of revenues from SCG -
$69 million, CNG - $245 million and Berkshire Gas - $45 million. Recovery of natural gas costs primarily from nonresidential deliveries also added $27 million to revenues. Those increases were partially offset by
$116 million due to lower deliveries because of warmer weather and $11 million due to lower natural gas prices for wholesale sales.
Operating Expenses > Operating expenses decreased $54 million for 2002. The decrease in operating expenses for 2002 was $69 million excluding $15 million for restructuring expenses. That decrease was primarily due to a
$159 million decrease in purchased gas costs caused by lower market prices, a $33 million decrease in purchased gas due to fewer wholesale customers and a $15 million decrease due to the elimination of goodwill amortization in 2002. Those decreases were partially offset by $115 million for the addition of RG&E's operating expenses,
$9 million for increased purchases of natural gas due to higher deliveries because of colder winter weather in the fourth quarter of 2002, $9 million for higher uncollectible expenses and $6 million for merger integration efforts.
Operating expenses for 2001 increased $237 million primarily due to the first full year of natural gas purchases 35 and operating costs for SCG - $58 million, CNG - $218 million and Berkshire Gas - $41 million. Those increases were partially offset by $60 million of reduced purchased natural gas costs due to lower prices and deliveries and
$13 million for cost control efforts relating to retirement benefits and compensation.
Consol ;"'"'A BalancepSheets
- / i. i i.- "= L .'J: .,i . 't ' .>'
Consolidated Balance Sheets December 31 2002 2001 (Thousands)
Assets Current Assets Cash and cash equivalents $250,490 $437,014 Special deposits 47,643 1,555 Accounts receivable, net 737,876 564,671 Note receivable 380 12,126 Fuel, at average cost 117,678 92,234 Materials and supplies, at average cost 22,953 21,466 Accumulated deferred income tax benefits, net 8,697 4,170 Prepayments and other current assets 85,787 41,600 Total Current Assets 1,271,504 1,174,836 Utility Plant, at Original Cost Electric 5,787,762 3,874,972 Natural gas 2,347,011 1,771,636 Common 360,776 213,362 8,495,549 5,859,970 Less accumulated depreciation 3,873,267 2,270,516 Net Utility Plant in Service 4,622,282 3,589,454 Construction work in progress 179,557 36,978 Total Utility Plant 4,801,839 3,626,432 Other Property and Investments, Net 452,710 216,556 Regulatory and Other Assets Regulatory assets Nuclear plant obligations 524,679 199,797 Unfunded future income taxes 208,164 164,657 Unamortized loss on debt reacquisitions 45,353 53,965 Demand-side management program costs 8,394 18,137 Environmental remediation costs 106,262 85,835 Nonutility generator termination agreements 168,014 9,480 Other 361,960 239,258 Total regulatory assets 1,422,826 771,129 Other assets Goodwill, net 1,518,173 897,807 Prepaid pension benefits 540,426 435,901 Other 262,401 146,571 Total other assets 2,321,000 1,480,279 Total Regulatory and Other Assets 3,743,826 2,251,408 Total Assets $10,269,879 $7,269,232 The notes on pages 41 through 61 are an integral part of the financial statements.
36 I
Consolidated Balance Sheets December 31 2002 2001 (Thousands)
Liabilities Current Liabilities Current portion of long-term debt $545,404 $225,678 Notes payable 322,200 173,383 Accounts payable and accrued liabilities 361,499 224,150 Interest accrued 44,310 36,183 Taxes accrued 30,036 7,020 Other 200,927 142,926 Total Current Liabilities 1,504,376 809,340 Regulatory and Other Liabilities Regulatory liabilities Deferred income taxes 203,926 157,196 Gain on sale of generation assets 126,325 251,254 Pension benefits 67,205 52,642 Other 104,937 68,879 Total regulatory liabilities 502,393 529,971 Other liabilities Deferred income taxes 702,426 461,600 Nuclear plant obligations 314,013 199,797 Other postretirement benefits 391,049 282,791 Environmental remediation costs 133,933 102,930 Other 448,156 241,975 Total other liabilities 1,989,577 1,289,093 Total Regulatory and Other Liabilities 2,491,970 1,819,064 Long-term debt 3,351,959 2,471,278 Total Liabilities 7,348,305 5,099,682 Commitments - -
Preferred Stock of Subsidiaries Company-obligated mandatorily redeemable trust preferred securities of subsidiary holding solely parent debentures 345,000 345,000 Redeemable solely at the option of subsidiaries 90,962 43,373 Subject to mandatory redemption requirements 25,000 Common Stock Equity Common stock ($.01 par value, 300,000 shares authorized, 144,966 shares outstanding at December 31, 2002, and 116,718 shares outstanding at December 31, 2001) 1,455 1,182 Capital in excess of par value 1,447,664 842,989 Retained earnings 1,061,428 998,281 Accumulated other comprehensive income (loss) (34,167) (22,335)
Treasury stock, at cost (574 shares at December 31, 2002 and 1,418 shares at December 31, 2001) (15,768) (38,940)
Total Common Stock Equity 2,460,612 1,781,177 Total Liabilities and Stockholders' Equity $10,269,879 $7,269,232 The notes on pages 41 through 61 are an integral part of the financial statements.
37
.5 AL
Consolidated Statements of Income Year Ended December 31 2002 2001 2000 (Thousands, except per share amounts)
Operating Revenues Sales and services $4,008,918 $3,759,787 $2,959,520 Operating Expenses Electricity purchased and fuel used in generation 1,276,087 1,334,507 1,073,728 Natural gas purchased 603,258 694,038 496,509 Gasoline, propane and oil purchased 143,770 3,688 1,560 Other operating expenses 713,384 566,498 434,405 Maintenance 162,122 139,395 108,106 Depreciation and amortization 246,996 204,281 165,524 Other taxes 230,558 192,772 165,767 Restructuring expenses 40,567 - -
Gain on sale of generation assets - (84,083)
Deferral of asset sale gain - 71,803 Total Operating Expenses 3,416,742 3,122,899 2,445,599 Operating Income 592,176 636,888 513,921 Writedown of Investment 12,209 78,422 Other (Income) (26,883) (35,257) (49,671)
Other Deductions 29,847 20,216 19,514 Interest Charges, Net 257,747 217,066 152,520 Preferred Stock Dividends of Subsidiaries 32,129 14,455 963 Income Before Income Taxes 287,127 341,986 390,595 Income Taxes 98,524 154,379 155,561 Net Income $188,603 $187,607 $235,034 Earnings Per Share, basic and diluted $1.44 $1.61 $2.06 Average Common Shares Outstanding 131,117 116,708 114,213 The notes on pages 41 through 61 are an integral part of the financial statements.
38
Consolidated Statements of Cash Flows Year Ended December 31 2002 2001 2000 (Thousands)
Operating Activities Net income $188,603 $187,607 $235,034 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization 255,782 247,847 228,543 Income taxes and investment tax credits deferred, net 43,564 4,588 29,114 Restructuring expenses 40,567 Gain on sale of generation assets (84,083)
Deferral of asset sale gain 71,803 Pension income (70,189) (76,229) (67,849)
Writedown of investment 12,209 78,422 Changes in current operating assets and liabilities Accounts receivable, net (24,247) 125,121 (83,688)
Sale of accounts receivable program (152,000)
Inventory 6,111 (25,445) (13,623)
Prepayments and other current assets (3,998) 3,119 (1,341)
Accounts payable and accrued liabilities 5,551 (123,832) (10,289)
Interest accrued (3,118) 874 8,097 Taxes accrued 4,895 1,125 2,897 Other current liabilities 4,089 (53,372) (11,994)
Other assets (66,279) (44,163) (68,889)
Other liabilities 16,896 (6,848) 12,210 Net Cash Provided by Operating Activities 410,436 154,534 258,222 Investing Activities Acquisitions, net of cash acquired (681,397) _ (1,442,717)
Utility plant additions (224,450) (208,677) (154,009)
Sale of generation assets 59,442 59,441 -
Temporary investments - - 1,017,249 Other property and investments additions (29,177) (30,271) (48,143)
Other property and investments sold 12,138 18,967 32,946 Special deposits (5,166) 19,909 (21,954)
Other 1,490 (19,344) 11,002 Net Cash Used in Investing Activities (867,120) (159,975) (605,626)
Financing Activities Issuance of common stock 17,844 7,201 Repurchase of common stock (2,139) (24,116) (163,493)
Issuance of mandatorily redeemable trust preferred securities - 345,000 Repayments of first mortgage bonds and preferred stock of subsidiaries, including net premiums (435,720) (1,890) (134,947)
Long-term note issuances 767,807 355,553 601,095 Long-term note repayments (97,124) (29,965) (20,771)
Notes payable three months or less, net 166,702 (269,012) 183,866 Notes payable issuances 28,400 54,445 16,345 Notes payable repayments (50,154) (31,045) (8,265)
Dividends on common stock (125,456) (107,342) (99,606)
Net Cash Provided by Financing Activities 270,160 298,829 374,224 293,388 26,820 39 Net (Decrease) Increase in Cash and Cash Equivalents (186,524)
Cash and Cash Equivalents, Beginning of Year 437,014 143,626 116,806 Cash and Cash Equivalents, End of Year $250,490 $437,014 $143,626 The notes on pages 41 through 61 are an integral part of the financial statements.
- ,- e - - " --. - - r I Consolidated Statements of Changes in Common Stock Equity Common Stock Accumulated Outstanding Capital in Other
$.01 Par Value Excess of Retained Comprehensive Treasury (Thousands, except per share amounts) Shares Amount Par Value Earnings Income (Loss) Stock Total Balance, January 1, 2000 109,343 $1,108 $660,936 $782,588 $(1,681) $(38,997) $1,403,954 Net income 235,034 235,034 Other comprehensive income, net of tax (33,142) (33,142)
Comprehensive income 201,892 Common stock dividends declared ($.88 per share) (99,606) (99,606)
Common stock issued -
merger transactions 16,269 163 373,545 373,708 Common stock repurchased (7,958) (80) (163,413) (163,493)
Treasury stock transactions, net 2 (8) 57 49 Amortization of capital stock issue expense 18 18 Balance, December31, 2000 117,656 1,191 871,078 918,016 (34,823) (38,940) 1,716,522 Net income 187,607 187,607 Other comprehensive income, net of tax 12,488 12,488 Comprehensive income 200,095 Common stock dividends declared ($.92 per share) (107,342) (107,342)
Common stock issued -
dividend reinvestment and stock purchase plan 368 4 7,197 7,201 Common stock repurchased (1,306) (13) (24,103) (24,116)
Capital stock issue expense (11,498) (11,498)
Amortization of capital stock issue expense 315 315 Balance, December 31, 2001 116,718 1,182 842,989 998,281 (22,335) (38,940) 1,781,177 Net income 188,603 188,603 Other comprehensive income, net of tax (11,832) (11,832)
Comprehensive income 176,771 Common stock dividends declared ($.96 per share) (125,456) (125,456)
Common stock issued -
merger transaction 27,509 275 611,807 612,082 Common stock issued -
dividend reinvestment and stock purchase plan 853 17,844 17,844 Common stock repurchased (114) (1) (2,138) (2,139)
Capital stock issue expense (52) (52)
Treasury stock transactions, net (1) (23,171) 23,172 -
40 Amortization of capital stock Z
issue expense 385 385 Balance, December 31, 2002 144,966 $1,455 $1,447,664 $1,061,428 $(34,167) $(15,768) $2,460,612 The notes on pages 41 through 61 are an integral part of the financial statements.
Notes to Consolidated Financial Statements NOTE I Significant Accounting Policies Background > Energy East Corporation (Energy East or the company) is a registered public utility holding company under the Public Utility Holding Company Act of 1935. Energy East is a super-regional energy services and delivery company with operations in New York, Connecticut, Massachusetts, Maine and New Hampshire and corporate offices in New York and Maine. Its wholly-owned subsidiaries - and their principal operating utilities - are: Berkshire Energy Resources - The Berkshire Gas Company, CMP Group, Inc. - Central Maine Power Company (CMP); Connecticut Energy Corporation (CNE) - The Southern Connecticut Gas Company (SCG);
CTG Resources, Inc. - Connecticut Natural Gas Corporation (CNG); and RGS Energy Group, Inc. (RGS Energy) -
New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E).
Accounts receivable > Accounts receivable include unbilled revenues of $237 million at December 31, 2002, and $143 million at December 31, 2001, and are shown net of an allowance for doubtful accounts of $59 million at December 31, 2002, and $18 million at December 31, 2001. Bad debt expense was $46 million in 2002,
$34 million in 2001 and $24 million in 2000. Bad debt expense for 2002 includes RGS Energy beginning July 1, 2002, and for 2001 includes CNE, CMP Group, CTG Resources and Berkshire Energy for a full year for the first time.
In August 2001 NYSEG terminated its agreement to sell, with limited recourse, undivided percentage interests in certain of its accounts receivable from customers. The agreement allowed NYSEG to receive up to $152 million from the sale of such interests. All fees related to the agreement beginning April 1, 2001, are included in interest expense on the consolidated statements of income and were approximately $3 million. Fees related to the sale of accounts receivable through March 31, 2001, are included in other deductions on the consolidated statements of income and amounted to approximately $2 million in 2001 and $10 million in 2000. NYSEG's sale of accounts receivable before the agreement was terminated did not constitute a securitization transaction because the accounts receivable were not transferred to a special purpose entity, and therefore, were not transformed into securities.
Basic and diluted earnings per share > Basic earnings per share (EPS) is determined by dividing net income by the weighted-average number of shares of common stock outstanding during the period. The weighted-average common shares outstanding for diluted EPS include the incremental effect of stock options issued and exclude stock options issued in tandem with stock appreciation rights (SARs). All stock options are issued in tandem with SARs and, historically, substantially all stock option plan participants have exercised the SARs instead of the stock options. The numerator used in calculating both basic and diluted EPS for each period is the reported net income.
The reconciliation of basic and diluted EPS for each period follows:
Year Ended December 31 2002 2001 2000 (Thousands)
Numerator Net income $188,603 $187,607 $235,034 Denominator Basic average common shares outstanding 131,117 116,708 114,213 Potentially dilutive common shares 215 198 170 Options issued with SARs (215) (198) (170)
Dilutive average common shares 131,117 116,708 114,213 41 Earnings per Share, basic $1.44 $1.61 $2.06 @
Earnings per Share, diluted $1.44 $1.61 $2.06 z
- i
- aiM Ar' flalphy
';, Wa*,.AsMI,%bmAAS 7r.kUd.&th. ~~,aC" 1K~bata. PdW M ii.- ; .air N-P, II
- am,',1 I'I. I Options to purchase shares of common stock are excluded from the determination of EPS when the exercise price of the options is greater than the average market price of the common shares during the year. Shares excluded from the EPS calculation were: 4.7 million in 2002, 2.1 million in 2001 and 1.9 million in 2000.
Consolidated statements of cash flows > The company considers all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents. Those investments are included in cash and cash equivalents on the consolidated balance sheets.
Supplemental Disclosure of Cash Flows Information 2002 2001 2000 (Thousands)
Cash paid during the year ended December 31:
Interest, net of amounts capitalized $238,305 $208,431 $132,009 Income taxes, net of benefits received $54,418 $113,274 $154,108 Acquisitions:
Fair value of assets acquired $3,264,093 - $2,526,971 Liabilities assumed (1,826,528) - (651,589)
Preferred stock of subsidiaries (72,000) - (37,591)
Common stock issued (612,082) - (373,708)
Cash acquired (72,086) - (21,366)
Net cash paid for acquisitions $681,397 - $1,442,717 Depreciation and amortization > The company determines depreciation expense substantially using straight-line rates, based on the average service lives of groups of depreciable property, which includes estimated cost of removal, in service at each operating company. The weighted-average service lives of certain classifications of property are: transmission property - 51 years, distribution property - 42 years, generation property - 41 years, gas production property - 26 years, gas storage property - 24 years and other property - 28 years. The company's depreciation accruals were equivalent to 3.5% of average depreciable property for 2002, 3.1% for 2001 and 3.1%
for 2000, which was weighted for the effect of the mergers completed in June 2002 and September 2000.
Estimates > Preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Goodwill > The excess of the cost over fair value of net assets of purchased businesses is recorded as goodwill and goodwill was amortized on a straight-line basis over five to 40 years until December 31, 2001. Beginning in 2002, the company evaluates the carrying value of goodwill for impairment at least annually and on an interim basis if there are indications that goodwill might be impaired. Any impairments would be recognized when the fair value of goodwill is less than its carrying value. (See Note 4.)
Income taxes > The company files a consolidated federal income tax return. Income taxes are allocated among Energy East and its subsidiaries in proportion to their contribution to consolidated taxable income.
SEC regulations require that no Energy East subsidiary pay more income taxes than it would have paid if a separate income tax return had been filed. The determination and allocation of the income tax provision and its components are outlined and agreed to in the tax sharing agreements among Energy East and its subsidiaries.
Deferred income taxes reflect the effect of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and the amount recognized for tax purposes. Investment tax credits 42 (ITC) are amortized over the estimated lives of the related assets.
z
Other (Income) and Other Deductions >
Year Ended December 31 2002 2001 2000 (Thousands)
Dividends $(233) $(1,844) $(44)
Interest income (13,213) (13,125) (31,233)
Noncash returns (6,693) (2,404) (1,360)
Allowance for funds used during construction (1,401) (652) (713)
Gain from sale of nonutility property (231) (3,628)
Earnings from equity investments (4,631) (7,162) (2,232)
Miscellaneous (481) (6,442) (14,089)
Total other (income) $(26,883) $(35,257) $(49,671)
NYSEG early retirement of debt $16,145 - $2,766 Fees on sale of accounts receivable - $2,495 10,368 Miscellaneous 13,702 17,721 6,380 Total other deductions $29,847 $20,216 $19,514 Principles of consolidation > These financial statements consolidate the company's majority-owned subsidiaries after eliminating intercompany transactions.
Reclassifications > Certain amounts have been reclassified on the consolidated financial statements to conform with the 2002 presentation.
Regulatory assets and liabilities > Pursuant to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, the company capitalizes, as regulatory assets, incurred costs that are probable of recovery in future electric and natural gas rates. It also records, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs.
Unfunded future income taxes and deferred income taxes are amortized as the related temporary differences reverse. Unamortized loss on debt reacquisitions is amortized over the lives of the related debt issues. Nuclear plant obligations, demand-side management program costs, gain on sale of generation assets, other regulatory assets and other regulatory liabilities are amortized over various periods in accordance with the company's current rate plans. The company earns a return on substantially all regulatory assets for which funds have been spent.
Revenue recognition > The company recognizes revenues upon delivery of energy and energy-related products and services to its customers.
Pursuant to Maine Law, since March 1, 2000, CMP has been prohibited from selling power to its retail customers.
CMP does not enter into any purchase and sales arrangements for power with the ISO New England, the New England Power Pool, or any other independent system operator or similar entity. All of CMP's power entitlements under its NUG and other purchase power contracts are sold to unrelated third parties under bilateral contracts for March 1, 2002, through February 28, 2005.
NYSEG and RG&E enter into power purchase and sales transactions with the NYISO. When sales of owned generation are sold to the NYISO, and subsequently repurchased from the NYISO to serve their customers, the transactions are recorded on a net basis in the consolidated statements of income.
43 a
z
-~ . 0.; a *,! !tak&..% ,.I4dma i~,,,,,~:"~d~~,~~6~~~,Jhs yaialsflSCTUEA _1~ _, . .ti- ns& ci .4...s b .. s.I - -
-a',!TI72a:w~, . Il- I Risk management > All of Energy East's natural gas utilities have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. The company uses natural gas futures to manage fluctuations in natural gas commodity prices and provide price stability to customers. The cost or benefit of natural gas futures is included in the commodity cost when the related sales commitments are fulfilled.
The company uses electricity contracts, both physical and financial, to manage fluctuations in the cost of electricity. The cost or benefit of those contracts is included in the amount expensed for electricity purchased when the electricity is sold.
The company uses interest rate swap agreements to manage the risk of increases in variable interest rates and to maintain desired fixed-to-floating rate ratios. It records amounts paid and received under the agreements as adjustments to the interest expense of the specific debt issues.
The company also uses financial instruments to lock in the treasury rate component of future financings to mitigate risk resulting from interest rate changes.
The company does not hold or issue financial instruments for trading or speculative purposes.
The company recognizes the fair value of its natural gas futures, financial electricity contracts and interest rate agreements as assets or liabilities on the consolidated balance sheets. The company's derivative asset was $80 million at December 31, 2002, and its derivative liability was $9 million at December 31, 2002, and
$32 million at December 31, 2001. All of the arrangements are designated as cash flow hedging instruments except for the company's $250 million fixed-to-floating interest rate swap agreement, which is designated as a fair value hedge. Changes in the fair value of the cash flow hedging instruments are recognized in other comprehensive income until the underlying transaction occurs. When the underlying transaction occurs, the amounts in accumulated other comprehensive income are reported in the consolidated statements of income.
Changes in the fair value of the interest rate swap agreement are recorded in the same period as the offsetting change in the fair value of the underlying debt instrument.
The company uses quoted market prices to fair value derivatives and adjusts for volatility and inflation when the period of the derivative exceeds the period for which market prices are readily available.
As of December 31, 2002, the maximum length of time over which the company is hedging its exposure to the variability in future cash flows for forecasted transactions is 84 months. The company estimates that gains of
$16 million will be reclassified from accumulated other comprehensive income into earnings in 2003, as the underlying transactions occur.
The company has commodity purchase and sales contracts for both capacity and energy that have been designated and qualify for the normal purchases and normal sales exception in Statement 133, as amended.
Statement 143 > In June 2001 the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. Statement 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and to capitalize the cost by increasing the carrying amount of the related long-lived asset. The liability is adjusted to its present value periodically over time, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement the entity either settles the obligation at its recorded amount or incurs a gain or a loss. For rate-regulated entities, any timing differences between rate recovery and book expense would be deferred as either a regulatory asset or a regulatory liability. The company adopted Statement 143 as of January 1, 2003. The company recognized an asset retirement obligation of approximately $415 million, a regulatory asset of $141 million, a regulatory liability of $5 million, an increase in utility plant of $74 million and a decrease in accumulated depreciation of $205 million. There was no effect on net income. Previously the company had recognized $266 million of the obligation as accumulated depreciation.
Utility plant > The company charges repairs and minor replacements to operating expense accounts, and capitalizes renewals and betterments, including certain indirect costs. The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
NOTE 2 Restructuring In the fourth quarter of 2002 the company recorded $41 million of restructuring expenses, including
$5 million for CMP, $26 million for NYSEG and a total of $10 million for Berkshire Gas, CNG and SCG. The restructuring expenses would have been $36 million higher, however RG&E was required by an NYPSC order approving RGS Energy's merger with the company to defer its portion of the restructuring charge for future recovery in rates. The employee positions affected by the restructuring were identified in the fourth quarter of 2002. The restructuring expenses reduced the company's 2002 net income by $24 million or 19 cents per share.
Included in those amounts are $20 million for a voluntary early retirement program that will be paid from the companies' pension plans and $3 million for an involuntary severance program, primarily for salaried employees of the company's six operating utilities, and $1 million for other associated costs.
Those programs are expected to result in a decline in overall employee headcount of approximately 650, or 8%,
by April 30, 2003. That includes approximately 70 from CMP, 260 from NYSEG, 245 from RG&E and 75 from Berkshire Gas, CNG and SCG. The employees affected by the involuntary severance program were notified in January 2003.
NOTE 3 Acquisition of RGS Energy Group On June 28, 2002, the company acquired all of the outstanding common stock of RGS Energy for a combination of cash and Energy East common stock. The company's consolidated statements of income and cash flows include RGS Energy's results of operations beginning with July 2002. RGS Energy, through its regulated subsidiary RG&E, engages in generating, purchasing and delivering electricity and purchasing and delivering natural gas in an area centered around the city of Rochester, New York. Through its unregulated subsidiary, Energetix, Inc., RGS Energy engages in retail electric, natural gas and liquid fuel businesses throughout upstate New York. In connection with Energy East's merger with RGS Energy, NYSEG became a wholly-owned subsidiary of RGS Energy.
Under the merger agreement 45% of the RGS Energy common stock, 15.6 million shares, was converted into 27.5 million shares of Energy East common stock valued at $612 million. The value of the shares issued was determined based on the market price of Energy East's stock at the end of the day on June 27, 2002. The remaining 55% of the RGS Energy common stock was exchanged for $753 million in cash ($39.50 per RGS Energy share). The purchase price was about $1.4 billion, which includes $11 million of merger-related costs.
The following table summarizes the components of the purchase price and preliminary allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition. RGS Energy did not push goodwill down to its subsidiaries. As of December 31, 2002, $29 million was allocated to intangible assets based on a preliminary appraisal. The allocation of the purchase price will be adjusted when final appraisals are received, RG&E's electric and gas rate cases are finalized and actual amounts for estimated liabilities become known.
45 z
- ~,,, ~~,;~~
4
. i steWS M. I.t~EIjg. ~itiit_`,a.
da a tt sY. adMeIf cU h'lddu-te1 ,St. -,C "_
- 1,,:
% ~ a Calculation of the purchase price for assets acquired (Thousands)
Cash paid for stock purchased $753,483 Common stock issued 612,082 Merger-related fees and expenses 11,000 Total purchase price for common equity 1,376,565 Plus fair market value of liabilities and preferred stock assumed Current and other liabilities 883,502 Long-term debt 932,026 Preferred stock 72,000 Total liabilities and preferred stock 1,887,528 Total purchase price for assets acquired $3,264,093 Allocation of purchase price for assets acquired Property, plant and equipment $1,203,282 Goodwill 622,342 Intangible assets subject to amortization 22,019 Intangible assets not amortized 6,600 All other assets, including working capital 1,409,850 Total $3,264,093 The following pro forma information for the company for the years ended December 31, 2002 and 2001, which is based on unaudited data, gives effect to the company's merger with RGS Energy as if it had been completed at the beginning of each period presented. This information does not reflect future revenues or cost savings that may result from the merger and is not indicative of actual results of operations had the merger occurred at the beginning of the periods presented or of results that may occur in the future.
Year Ended December 31 2002 2001 (Thousands, except per share amounts)
Operating Revenues $4,690,489 $5,290,279 Net Income $201,521 $262,741 Earnings Per Share of Common Stock $1.39 $1.82 Pro forma adjustments reflected in the amounts presented include: (1) adjusting RGS Energy's nonutility assets to fair value based on an independent appraisal, (2) adjusting depreciation and amortization of assets to the accounting base recognized in recording the combination, (3) elimination of amortization of goodwill, (4) amortization of other intangible assets with finite lives, (5) elimination of merger costs, (6) additional interest expense and preferred stock dividends due to the issuance of merger-related debt and securities, (7) adjustments for estimated tax effects of the above adjustments and (8) additional common shares issued in connection with the merger. The pro forma results include a loss of 19 cents per share for restructuring expenses and the writedown of CMP Group's investment in NEON Communications of 6 cents per share in 2002 and 39 cents per share in 2001. The pro forma results of operations for 2002 include the results of operations of RGS Energy for the six months ended June 30, 2002, as follows: Operating revenues - $681,571; Operating expenses - $615,851; Operating income - $65,720; Income before income taxes - $36,850; and Net income - $15,550.
NOTE 4 Goodwill and Other Intangible Assets 46 Effective January 1, 2002, the company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As required by Statement 142 the company no longer amortizes goodwill and does not amortize intangible assets with indefinite lives (unamortized intangible assets). Both goodwill and unamortized intangible assets are tested at least annually for impairment. Intangible assets with finite lives are amortized (amortized intangible assets) and are reviewed for impairment.
The company determined that there was no impairment of goodwill as of January 1, 2002. There was no reclassification of goodwill to intangible assets and no reclassification of intangible assets to goodwill as of January 1, 2002. Annual impairment testing was also completed and it was determined that there was no impairment of goodwill or unamortized intangible assets for the companies at September 30, 2002.
The changes in the carrying amount of goodwill on the company's balance sheets, by operating segment, for the year ended December 31, 2002, are:
Electric Natural Gas Delivery Delivery Other Total (Thousands)
Balance, January 1, 2002 $325,174 $554,787 $17,846 $897,807 Goodwill acquired during the year 494,063 123,516 4,763 622,342 Goodwill written off related to sale of business - - (1,709) (1,709)
Other adjustments 406 (653) (20) (267)
Balance, December 31, 2002 $819,643 $677,650 $20,880 $1,518,173 Other Intangible Assets > At December 31, 2002, the company's unamortized intangible assets had a carrying amount of $14 million and primarily consisted of trade names and pension assets. At December 31, 2001, the company's unamortized intangible assets had a carrying amount of $4 million and primarily consisted of pension assets. At December 31, 2002, the company's amortized intangible assets had a gross carrying amount of
$47 million and primarily consisted of customer lists and investments in pipelines. Customer lists acquired in 2002 with a carrying amount of $14 million will be amortized over three to 10 years. At December 31, 2001, the company's amortized intangible assets had a gross carrying amount of $26 million and primarily consisted of investments in pipelines. Accumulated amortization was $15 million at December 31, 2002, and $5 million at December 31, 2001.
Estimated amortization expense for intangible assets for the next five years (in thousands) is:
2003 2004 2005 2006 2007
$4,362 $4,285 $3,512 $2,723 $2,667 Transitional Information > Results of operations information for the company as though goodwill had been accounted for under Statement 142 for all years presented is:
Year Ended December 31 2002 2001 2000 (Thousands, except per share data)
Reported net income $188,603 $187,607 $235,034 Add back: goodwill amortization - 25,379 18,486 Adjusted net income $188,603 $212,986 $253,520 Reported basic and diluted earnings per share $1.44 $1.61 $2.06 Add back: goodwill amortization - .22 .16 Adjusted basic and diluted earnings per share $1.44 $1.83 $2.22 47 In 0
-s dt *NOTE 5 Inco-m SS. Taxes-b'. a . . .
NOTE 5 Income Taxes Year Ended December 31 2002 2001 2000 (Thousands)
Current $50,663 $147,497 $129,220 Deferred, net Accelerated depreciation 19,258 12,312 628 Pension benefits 36,932 30,430 24,051 Statement 106 postretirement benefits (4,627) (4,079) (11,417)
Demand-side management (2,189) (9,295) (8,335)
Asset sale gain account amortization 29,367 Restructuring expenses (15,816)
Miscellaneous (12,540) (20,371) 23,676 ITC (2,524) (2,115) (2,262)
Total $98,524 $154,379 $155,561 The company's effective tax rate differed from the statutory rate of 35% due to the following:
Year Ended December31 2002 2001 2000 (Thousands)
Tax expense at statutory rate $111,740 $124,754 $137,045 Depreciation and amortization not normalized 5,125 26,373 8,032 ITC amortization (2,524) (2,115) (2,262)
Trust preferred securities (9,932) (4,389) -
State taxes, net of federal benefit 9,724 14,692 21,386 Other, net (15,609) (4,936) (8,640)
Total $98,524 $154,379 $155,561 The effective tax rate was 31% in 2002 and 43% in 2001. The decrease is the result of various items including the elimination of goodwill amortization in 2002, the flow-through effect (in 2001 only) of the sale of NMP2, a lower state income tax rate in 2002 due to combined filing benefits, and an increase in distributions on trust preferred securities that were outstanding for a full year in 2002.
The company's deferred tax assets and liabilities consisted of the following:
December 31 2002 2001 (Thousands)
Current Deferred Tax Assets $8,697 $4,170 Noncurrent Deferred Tax Liabilities Depreciation $750,739 $573,071 Unfunded future income taxes 129,481 80,125 Accumulated deferred ITC 45,039 29,370 Deferred gain on sale of generation assets 63,969 (109,246)
Pension benefits 87,717 102,109 Statement 106 postretirement benefits (92,182) (64,013)
Nuclear decommissioning (44,093) -
Other (34,318) 7,380 Total Noncurrent Deferred Tax Liabilities $906,352 618,796 Less amounts classified as regulatory liabilities 48 Deferred income taxes 203,926 157,196 Noncurrent Deferred Income Taxes $702,426 $461,600 z
Energy East and its subsidiaries have no federal tax credit or loss carryforwards, nor do they have any valuation allowances.
NOTE 6 Long-term Debt At December 31, 2002 and 2001, the company's consolidated long-term debt was:
Maturity Interest Amount Dates Rates 2002 2001 (Thousands)
First mortgage bonds(" 2003 to 2032 5.84% to 10.06% $890,500 $609,840 Pollution control notes - fixed 2006 to 2034 53/8% to 6.15% 351,000 325,500 Pollution control notes - variable 2015 to 2032 0.75% to 4.43% 408,900 307,000 Various long-term debts2 2003 to 2030 0.95% to 10.48% 1,924,130 1,137,809 Putable asset term securities(3 ) 2033 7.75% 300,000 300,000 Obligations under capital leases 34,447 36,960 Unamortized premium and discount on debt, net (11,614) (20,153) 3,897,363 2,696,956 Less debt due within one year - included in current liabilities 545,404 225,678 Total $3,351,959 $2,471,278 At December 31, 2002, long-term debt, including sinking fund obligations, and capital lease payments (in thousands) that will become due during the next five years are:
2003 2004 2005 2006 2007
$545,404 $43,839 $61,611 $341,157 $232,750 As a registered holding company under the Public Utility Holding Company Act of 1935, Energy East is prohibited from obtaining upstream guarantees and credit support from its subsidiaries. Energy East has no secured indebtedness and none of its assets are mortgaged, pledged or otherwise subject to lien. None of Energy East's debt obligations are guaranteed or secured by its subsidiaries.
(1) For Energy East, in addition to the information provided for CMP, NYSEG and RG&E below, Berkshire Gas and SCG have first mortgage bonds that are secured by liens on substantially all of their respective utility properties.
Berkshire Gas has other long-term debt that is secured by its properties, and CTG Resources and CNE have subsidiaries with long-term debt that is secured by properties of those subsidiaries.
CMP has no long-term debt obligations that are secured. CMP has no intercompany collateralizations and has no guarantees to affiliates or subsidiaries. CMP's debt has no guarantees from parent or affiliates or any additional credit supports.
NYSEG's first mortgage bonds, totaling $150 million at December 31, 2002, are secured by a first mortgage lien on substantially all of its properties. NYSEG has no other secured indebtedness. None of NYSEG's other debt obligations are guaranteed or secured by any of its affiliates.
RG&E's first mortgage bonds, totaling $705.5 million at December 31, 2002, are secured by a first mortgage lien on substantially all of its properties. Other than the promissory note described below, RG&E has no other secured indebtedness. None of RG&E's other debt obligations are guaranteed or secured by any of its affiliates.
(2) Includes RG&E's promissory note in connection with the Kamine Global Settlement Agreement, collateralized by a mortgage, the lien for which is subordinate to the first mortgage lien. On January 9, 2003, RG&E paid off the remaining $80 million balance of this note that was due to mature in 2014.
49 (3) The Putable Asset Term Securities bear interest at 7.75% until November 15, 2003, and then, as provided en 0
by an agreement, will either be redeemed by the company or will bear interest at a fixed or floating rate until November 15, 2033, unless extended to November 15, 2034. At December 31, 2002, $300 million of Putable Asset Term Securities were classified as current portion of long-term debt as a result of this provision.
Cross-default Provisions > Energy East has a provision in its senior unsecured indenture, which provides that default by the company with respect to any other debt in excess of $40 million will be considered a default under the company's senior unsecured indenture.
In the event of a cross-default of other long-term debt obligations of CMP, The Finance Authority of Maine, under a Loan Agreement, may declare an amount equal to the unpaid principal amount, currently less than $10 million, and interest accrued immediately due and payable.
NYSEG has provisions in its unsecured indenture and the reimbursement agreements relating to certain series of pollution control bonds, which provide that default by NYSEG with respect to any other debt in excess of
$40 million in the case of the unsecured indenture and $5 million in the case of the reimbursement agreements will be considered a default under those respective documents.
RG&E has a provision in a participation agreement relating to certain series of pollution control bonds, which provides that default by RG&E with respect to bonds issued under its first mortgage indenture will be considered a default under the participation agreement.
NOTE 7 Bank Loans and Other Borrowings The company and its subsidiaries have credit agreements with various expiration dates in 2003 and 2005 and pay fees in lieu of compensating balances in connection with the credit agreements. The agreements provided for maximum borrowings of $755 million at December 31, 2002 and 2001.
The company and its subsidiaries use short-term, unsecured notes and drawings on their credit agreements (see above) to finance certain refundings and for other corporate purposes. There was $322 million of such short-term debt outstanding at December 31, 2002, and $173 million outstanding at December 31, 2001. The weighted-average interest rate on short-term debt was 2.1% at December 31, 2002, and 2.6% at December 31, 2001.
In its revolving credit agreements Energy East covenants not to permit, without the consent of the lenders, its ratio of consolidated indebtedness to consolidated total capitalization at the last day of any fiscal quarter to exceed 0.65 to 1.00. Continued unremedied failure to comply with this covenant for 15 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. Energy East's ratio of consolidated indebtedness to consolidated total capitalization was 0.59 to 1.00 at December 31, 2002.
In its revolving credit facility, which is secured by its accounts receivable, CMP covenants that (i) its consolidated total debt shall at all times be no more than 65% of the sum of its consolidated total debt and its total stockholders equity, and (ii) as of the end of any fiscal quarter CMP's ratio of earnings before interest expense, income taxes and preferred stock dividends to interest expense shall have been at least 1.75 to 1.00. Continued unremedied failure to comply with either covenant for 30 days after such event has occurred constitutes an event of default and would result in acceleration of maturity. At December 31, 2002, CMP's consolidated total debt ratio was 33.6% and its interest coverage ratio was 3.73 to 1.00.
In their joint revolving credit agreement NYSEG and RG&E each covenant not to permit, without the consent of the lenders, (i) their respective ratio of earnings before interest expense and income tax to interest expense to be less than 1.5 to 1.0 at any time, and (ii) their respective ratio of total indebtedness to total capitalization to exceed 0.70 to 1.00 at any time. Continued unremedied failure to observe these covenants for five business days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of 50 maturity for the party in default. At December 31, 2002, the ratio of earnings before interest expense and income tax to interest expense was 3.4 to 1.0 for NYSEG and 2.3 to 1.0 for RG&E. At December 31, 2002, the ratio of total indebtedness to total capitalization was 0.53 to 1.00 for NYSEG and 0.52 to 1.00 for RG&E.
NYSEG has two letters of credit and reimbursement agreements in which it covenants not to permit, without the consent of the bank issuing the letter of credit, its ratio of total indebtedness to total capitalization to exceed
0.65 to 1.00 as of the last day of any fiscal quarter. Continued unremedied failure to comply with this covenant for 30 days after written notice of such failure from any lender constitutes an event of default and would result in acceleration of maturity. NYSEG's ratio of total indebtedness to total capitalization was 0.53 to 1.00 at December 31, 2002.
NOTE 8 Preferred Stock of Subsidiaries Trust preferred securities > The company-obligated mandatorily redeemable trust preferred securities are 8 1/4%
Capital Securities issued by Energy East Capital Trust 1, a Delaware business trust that is a wholly-owned finance subsidiary of the company. The assets of the trust consist solely of the company's 8 1/4% junior subordinated debt securities maturing on July 31, 2031. The company has fully and unconditionally guaranteed the trust's payment obligations with respect to the Capital Securities.
At December 31, 2002 and 2001, the consolidated preferred stock was:
Shares Par Value Redemption Authorized Amount Per Price and (Thousands)
Series Share Per Share Outstanding("' 2002 2001 Redeemable solely at the option of subsidiaries:
3.50% $100 $101.00 220,000 $22,000 $22,000 3.75% 100 104.00 78,379 7,838 7,838 4% F 100 105.00 120,000 12,000 -
4.10% H 100 101.00 80,000 8,000 -
4.10% J 100 102.50 50,000 5,000 -
4.15% (1954) 100 102.00 4,317 432 432 4.40% 100 102.00 7,093 709 709 41/2% (1949) 100 103.75 11,800 1,180 1,180 4.55% M 100 101.00 100,000 10,000 -
4.60% 100 101.00 30,000 3,000 3,000 4.75% 100 101.00 50,000 5,000 5,000 4.75% 1 100 101.00 60,000 6,000 -
4.80% 100 100.00 2,574 257 259 4.95% K 100 102.00 60,000 6,000 -
5.25% 100 102.00 50,000 5,000 5,000 6% Noncallable 100 - 5,180 518 518 6.00% 100 110.00 4,104 411 413 8.00% Noncallable 3.125 - 108,843 340 340 Preferred stock issuance costs (2,723) (3,316)
Total $90,962 $43,373 Subject to mandatory redemption requirements:
6.60% V2 $100 $100.00 250,000 $25,000 -
(1) At December 31, 2002, the company and its subsidiaries had 15,790,801 shares of $100 par value preferred stock, 16,800,000 shares of $25 par value preferred stock, 775,472 shares of $3.125 par value preferred stock, 600,000 shares of $1 par value preferred stock, 10,000,000 shares of $.01 par value preferred stock, 1,000,000 shares of $100 par value preference stock and 6,000,000 shares of $1 par value preference stock authorized but unissued.
(2) This RG&E series is subject to a mandatory sinking fund sufficient to redeem, at par, on March 1 of each year 51 from 2004 through 2008, 12,500 shares, and on March 1, 2009, the balance of the shares. RG&E has the option ,,
to redeem up to an additional 12,500 shares on the same terms and dates as applicable to the mandatory sinking Z fund. In the event RG&E should be in arrears in the sinking fund requirement, RG&E may not redeem or pay dividends on any stock subordinate to the preferred stock.
8;p - Ia.'t @jii. s.'. I. -. ... . .* ..
The company's subsidiaries redeemed or purchased the following amounts of preferred stock during the three years 2000 through 2002:
Subsidiary Company Date Series Amount CMP October 1, 2000 7.999% $9.9 million*
CNG September 26, 2000 8.00 % $3,250
- CNG Various 2001 6.00 % $45,900
- CNG Various 2001 8.00 % $41,222 **
CNG June 7, 2002 6.00 % $2,500*
Berkshire September 30, 2001 4.80 % $41,000*
Berkshire September 30, 2002 4.80 % $1,500
- Redeemed -Substantially all purchased at a premium Voting rights of preferred shares issued by subsidiaries >
Trust preferred securities - Holders of trust preferred securities have no voting rights, except that they may vote on certain transactions if such transaction would cause Energy East Capital Trust I or a successor entity to be classified other than as a grantor trust for U.S. federal income tax purposes, and they may vote on certain matters affecting the powers, preferences or special rights of the trust preferred securities.
Preferred stock redeemable solely at the option of subsidiaries - If preferred stock dividends on any series of preferred stock of a subsidiary, other than the 6% Noncallable series and the 8.00% series, are in default in an amount equivalent to four full quarterly dividends, the holders of the preferred stock of such subsidiary are entitled to elect a majority of the directors of such subsidiary (and, in the case of the 6.00% series, the largest number of directors constituting a minority of the board) and their privilege continues until all dividends in default have been paid. The holders of preferred stock, other than the 6% Noncallable series and the 8.00% series, are not entitled to vote in respect of any other matters except those, if any, in respect of which voting rights cannot be denied or waived under some mandatory provision of law, and except that the charters of the respective subsidiaries contain provisions to the effect that such holders shall be entitled to vote on certain matters affecting the rights and preferences of the preferred stock.
Holders of the 6% Noncallable series and the 8.00% series are entitled to one vote per share and have full voting rights on all matters.
Whenever holders of preferred stock shall be entitled to vote, they shall be entitled to cast one vote for each share of preferred stock held by them. Holders of NYSEG common stock are entitled to one vote per share on all matters, except in the election of directors with respect to which NYSEG common stock has cumulative voting rights. Holders of CMP common stock are entitled to one-tenth of one vote per share on all matters. Holders of the common stock of the other subsidiaries are entitled to one vote per share on all matters.
NOTE 9 Commitments Capital spending > The company has commitments in connection with its capital spending program. Capital spending is projected to be $338 million in 2003, which includes RGS Energy and nuclear fuel, and is expected to be paid for with internally generated funds. The program is subject to periodic review and revision. The company's capital spending will be primarily for the extension of energy delivery service, necessary improvements to existing facilities, compliance with environmental requirements and governmental mandates and merger integration.
52 Nonutility generator power purchase contracts > CMP and NYSEG together expensed approximately $611 million 0
z for NUG power in 2002, $593 million in 2001 and $439 million in 2000 (CMP beginning on September 1, 2000, the date it was acquired). CMP and NYSEG estimate that their combined NUG power purchases will total $613 million in 2003, $632 million in 2004, $642 million in 2005, $578 million in 2006 and $544 million in 2007.
NOTE 10 Jointly-Owned Generation Assets and Nuclear Generation Insurance and Decommissioning Cayuga Energy, Inc. > Cayuga Energy, Inc. owns an 85% interest in South Glens Falls Energy, L.L.C., the owner of a 67-megawatt natural gas-fired combined cycle generating station operating as an exempt wholesale generator.
As part of a joint venture with PEI Power Corporation, Cayuga Energy owns 50.1% of a 44-megawatt natural gas-fired peaking-power plant. The joint venture company, PEI Power II, L.L.C., operates the plant as an exempt wholesale generator.
CMP > CMP has ownership interests in three nuclear generating facilities in New England. The largest is a 38% interest in Maine Yankee Atomic Power Company. CMP also owns a 9.5% interest in Yankee Atomic Electric Company and a 6% interest in Connecticut Yankee Atomic Power Company. Maine Yankee, Yankee Atomic and Connecticut Yankee have been permanently shut down and are in the process of being decommissioned.
On July 31, 2002, Vermont Yankee Nuclear Power Corporation sold the Vermont Yankee nuclear power plant, including CMP's 4% ownership interest, to Entergy Corporation. Any benefits realized from the sale, which are expected to be less than $1 million, will be used to reduce CMP customers' future obligations for stranded costs.
The transaction included a power purchase agreement that calls for Entergy to provide all of the plant's electricity to the sellers through 2012, the year the operating license for the plant expires.
Sale of Nine Mile Point 2 > In November 2001 NYSEG and RG&E sold their interests in NMP2 to Constellation Nuclear. In October 2001 the NYPSC issued an order approving the sale.
NYSEG - For its 18% share of NMP2, NYSEG received at closing $59 million in cash and a $59 million 11%
promissory note. On April 12, 2002, Constellation Nuclear paid the remaining balance plus accrued interest on the promissory note. NYSEG's 18% share of NMP2's operating expenses until it was sold is included in various categories on the statements of income.
Upon completion of the sale of NMP2, NYSEG recorded an asset sale gain of approximately $110 million, in accordance with the NYPSC's order approving the sale, as a regulatory liability under Statement 71. The gain includes a gross up for unfunded future income taxes and is being returned to customers in accordance with NYSEG's current electric rate plan, which was approved by the NYPSC in February 2002.
RG&E - For its 14% share of NMP2, the October 2001 NYPSC order provided for RG&E to establish a regulatory asset of approximately $326 million at the time of closing. RG&E agreed to a one-time $20 million pretax accelerated amortization of the regulatory asset that was recorded in the third quarter of 2001. In addition, RG&E accelerated its recognition of approximately $13 million of previously deferred investment tax credits. RG&E also agreed to amortize the regulatory asset by an additional $30 million per year during the period from the closing of the sale of NMP2 until RG&E's base electric rates are reset. The $30 million annual amortization reflects RG&E's projected savings for its share of NMP2 operating expenses compared to the estimated cost of electricity purchases to replace RG&E's presale share of the output. The terms associated with the recovery of the remaining regulatory asset will be established in future RG&E rate proceedings. The settlement further provides that it constitutes a final and irrevocable resolution of all RG&E ratemaking issues associated with the sale of NMP2 and RG&E's ability to recover through rates the costs associated with its investment in NMP2.
NYSEG and RG&E's pre-existing decommissioning funds for NMP2 were transferred to Constellation, which has taken responsibility for all future decommissioning funding.
The transaction included a power purchase agreement that calls for Constellation to provide electricity to NYSEG and RG&E, at fixed prices, for 10 years. The power purchase agreement is a contract for physical delivery of NYSEG's 18% share and RG&E's 14% share of 90% of the output from NMP2. NYSEG and RG&E recorded expenses 53 for electricity purchased in 2001 and 2002 in accordance with the agreement at the time the power was physically Z delivered, at prices pursuant to the agreement. The contract is not required to be marked-to-market and is not considered a derivative instrument because it qualifies for the normal purchases and normal sales exception in Statement 133, as amended.
- qIIj-a 73::, ck b- -. t dat- ; a- - ' > _.I 'eb b ;- -
After the power purchase agreement is completed a revenue sharing agreement will begin. The revenue sharing agreement could provide NYSEG and RG&E additional revenue through 2021, which would mitigate increases in electricity prices. Both agreements are based on plant output. No amounts were recorded under the revenue sharing agreement in 2002 because any benefit that may occur between 2011 and 2021 cannot be estimated.
Any benefits from the revenue sharing agreement will be deferred for customers.
Nuclear insurance > The Price-Anderson Act is a federal statute providing, among other things, a limit on the maximum liability of nuclear reactor owners for damages resulting from a single nuclear incident. The public liability limit for a nuclear incident is approximately $9.5 billion and is subject to inflation and changes in the number of licensed reactors. RG&E carries the maximum available commercial insurance of $300 million and participates in the mandatory financial protection pool for the remaining $9.2 billion. Under the Price-Anderson Act, RG&E would be liable for up to $88 million per incident payable at a rate not to exceed $10 million per incident per year.
In addition to the insurance required by the Price-Anderson Act, RG&E also carries nuclear property damage insurance and accidental outage insurance through Nuclear Electric Insurance Limited. Under those insurance policies, RG&E could be subject to assessments if losses exceed the accumulated funds available to the insurers.
The maximum amounts of the assessments for the current policy year are $13 million for nuclear property damage insurance and $3 million for accidental outage insurance.
Nuclear plant decommissioning costs > The estimated liability, in 2003 dollars, for decommissioning the various interests in nuclear plants, including spent fuel storage, is $387 million for CMP, which was updated in 2002 to include spent fuel storage and increases in projected costs, and $434 million for RG&E. The amount currently billed or accrued for those costs is recovered by CMP and RG&E through their electric rates.
NOTE 11 Environmental Liability From time to time environmental laws, regulations and compliance programs may require changes in the company's operations and facilities and may increase the cost of electric and natural gas service.
The U.S. Environmental Protection Agency and various state environmental agencies, as appropriate, notified the company that it is among the potentially responsible parties who may be liable for costs incurred to remediate certain hazardous substances at 19 waste sites. The 19 sites do not include sites where gas was manufactured in the past, which are discussed below. With respect to the 19 sites, nine sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites, four are included in Maine's Uncontrolled Sites Program, one is included on the Massachusetts Non-Priority Confirmed Disposal Site list and seven of the sites are also included on the National Priorities list.
Any liability may be joint and several for certain of those sites. The company has recorded an estimated liability of $2 million related to 17 of the 19 sites. Remediation costs have been paid at the remaining two sites, and the company expects no additional liability to be incurred. An estimated liability of $5 million has been recorded related to 12 sites where the company believes it is probable that it will incur remediation costs, although it has not been notified that it is among the potentially responsible parties. The ultimate cost to remediate the sites may be significantly more than the estimated amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the portion attributed to the company.
The company has a program to investigate and perform necessary remediation at its 59 sites where gas was manufactured in the past. Eight sites are included in the New York State Registry, eight sites are included in 54 the New York Voluntary Cleanup Program, four sites are part of Maine's Voluntary Response Action Program and three of those four sites are part of Maine's Uncontrolled Sites Program, three sites are included in the Connecticut Inventory of Hazardous Waste Sites, and three sites are on the Massachusetts Department of Environmental Protection's list of confirmed disposal sites. The company has entered into consent orders with various environmental agencies to investigate and, where necessary, remediate 39 of its 59 sites.
The company's estimate for all costs related to investigation and remediation of its 59 sites ranges from
$126 million to $220 million at December 31, 2002. The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action, changes in technology relating to remedial alternatives and changes to current laws and regulations.
The liability to investigate and perform remediation, as necessary, at the known inactive gas manufacturing sites, reflected on the company's consolidated balance sheets was $126 million at December 31, 2002, and $101 million at December 31, 2001. The company recorded a corresponding regulatory asset, net of insurance recoveries, since it expects to recover the net costs in rates.
The company has reported petroleum spill incidents to the New York State Spill Incidents Report database and has recorded an estimated liability of $2 million to remediate these spill incidents.
Energy East's environmental liabilities are recorded on an undiscounted basis unless payments are fixed and determinable. Nearly all of Energy East's environmental liability accruals, which are expected to be paid through the year 2017, have been established on an undiscounted basis. Insurance settlements have been received by Energy East subsidiaries during the last three years, which they accounted for as reductions in their related regulatory assets.
NOTE 12 Fair Value of Financial Instruments The carrying amounts and estimated fair values of the company's financial instruments included on its consolidated balance sheets are shown in the following table. The fair values are based on the quoted market prices for the same or similar issues of the same remaining maturities.
December 31 2002 2002 2001 2001 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value (Thousands)
Investments - classified as available-for-sale $296,425 $296,392 $38,508 $38,550 First mortgage bonds $888,870 $973,232 $606,112 $623,055 Pollution control notes - fixed $351,000 $364,865 $325,500 $333,056 Pollution control notes - variable $408,900 $408,900 $307,000 $307,000 Various long-term debt $1,915,160 $2,088,303 $1,123,557 $1,124,911 Putable asset term securities $298,986 $335,288 $297,827 $310,017 The carrying amounts for cash and cash equivalents, notes payable and interest accrued approximate their estimated fair values. Special deposits may include restricted funds set aside as collateral for first mortgage bonds and collateral received from counterparties. The carrying amount approximates fair value because the special deposits have been invested in securities that mature within one year.
The company evaluated the carrying value of CMP Group's investment in NEON Communications, Inc. because there had been a significant decline in the market value of NEON common shares. That decline was consistent with the market performance of telecommunications businesses as a whole. A decline was determined to be other than temporary during the third quarter of 2001 and the investment was written down to its fair market value of $12 million at September 30, 2001. That writedown totaled $46 million after taxes, or 39 cents per share.
During the first half of 2002 the company determined that additional declines in NEON's market value were other than temporary and further wrote down the cost basis of its investment in NEON. The investment was written 55 down to $2 million based on the closing market price of NEON common shares on March 31, 2002. That writedown totaled $6 million after taxes, or five cents per share. In the second quarter of 2002 the NEON common shares were delisted from NASDAQ and NEON filed a reorganization plan under the U.S. Bankruptcy Code. The company wrote off its remaining $2 million investment during the second quarter of 2002, which was
$1 million after taxes, or one cent per share.
. - ti - . . E . <.;t m i I -.; ; * -
.g.i... me .m I . .
The investment in NEON was classified as available-for-sale, accounted for by the cost method and carried at its fair value, with changes in fair value recognized in other comprehensive income. No income or loss related to the investment in NEON was included in the company's operating income in earlier periods.
NOTE 13 Stock-Based Compensation The company applies Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, to account for its stock-based compensation plans. Compensation expense would have been the same in 2002, 2001 and 2000 had it been determined consistent with Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, because stock appreciation rights (SARs) were granted along with any options granted. SARs will continue to be issued along with any options granted.
The company may grant options and SARs to senior management and certain other key employees under its stock option plan. Options granted in 2000, 2001 and 2002 vest over either one-year or two-year periods, subject to, with certain exceptions, continuous employment. All options expire 10 years after the grant date.
Of the 10 million shares authorized at December 31, 2002 and 2001, unoptioned shares totaled 1.9 million at December 31, 2002, and 4.5 million at December 31, 2001.
The company recorded compensation expense (benefit) for options/SARs of $12 million in 2002, less than
$(1) million in 2001 and $(1) million in 2000.
During 2002, 2,810,500 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $20.34. 347,863 SARs with a weighted-average exercise price of $16.26 were exercised in 2002. 74,337 options/SARs with an exercise price of $19.43 were forfeited in 2002. The 7,024,347 options/SARs outstanding at December 31, 2002, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of four years had a weighted-average exercise price of $10.88 and 6,933,038 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.08. Of those exercisable at December 31, 2002, 91,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 4,611,209 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $21.66.
During 2001, 1,799,000 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $18.88. 54,332 SARs with a weighted-average exercise price of $17.51 were exercised in 2001. 34,000 options/SARs with an exercise price of $21.03 were forfeited in 2001. The 4,636,047 options/SARs outstanding at December 31, 2001, had a weighted-average exercise price of $20.95. Of those outstanding at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of five years had a weighted-average exercise price of $10.88 and 4,444,738 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $21.38. Of those exercisable at December 31, 2001, 191,309 options/SARs with exercise prices ranging from $10.88 to $14.69 had a weighted-average price of $10.88 and 2,939,545 options/SARs with exercise prices ranging from $17.94 to $28.72 had a weighted-average exercise price of $22.17.
During 2000, 1,070,597 options/SARs were granted with a weighted-average exercise price equal to the weighted-average fair value of $23.06. 2,797 options with a weighted-average exercise price of $16.43 and 107,731 SARs with a weighted-average exercise price of $17.56 were exercised in 2000. 312,548 options/SARs with an exercise price of $23.99 were forfeited in 2000. The 2,925,379 options/SARs outstanding at December 31, 2000, had a weighted-average exercise price of $22.15. Of those outstanding at December 31, 2000, 197,309 options/SARs 56 with exercise prices ranging from $10.88 to $14.69 and a weighted-average remaining life of six years had a weighted-average exercise price of $10.88 and 2,728,070 options/SARs with exercise prices ranging from $17.94 to $28.72 and a weighted-average remaining life of eight years had a weighted-average exercise price of $22.97.
Of those exercisable at December 31, 2000, 197,309 options/SARs with exercise prices ranging from $10.88 to
$14.69 had a weighted-average price of $10.88 and 1,470,287 options/SARs with exercise prices ranging from
$17.94 to $28.72 had a weighted-average exercise price of $22.98.
The company's Long-term Executive Incentive Share Plan provides participants cash awards if certain shareholder return criteria are achieved. There were 59,130 performance shares outstanding at December 31, 2002, and 95,418 performance shares outstanding at December 31, 2001. Compensation expense for 2002 was $0.4 million, there was no compensation expense for 2001 and compensation expense was $1 million for 2000. Beginning January 1, 2001, no new performance shares were granted under this plan (other than dividend performance shares). The plan will be eliminated in 2003.
NOTE 14 Accumulated Other Comprehensive Income Balance Balance Balance Balance January 1 2000 December 31 2001 December 31 2002 December31 (Thousands) 2000 Change 2000 Change 2001 Change 2002 Foreign currency translation adjustment, net of income tax benefit of $-
for 2000, 2001 and 2002 $(93) $7 $(86) $86 - -
Unrealized gains (losses) on investments:
Unrealized holding (losses) during period, net of income tax benefit of $23,804 for 2000,
$7,980 for 2001 and
$6,803 for 2002 (1,588) (32,519) (34,107) (10,400) $(44,507) $(9,654) $(54,161)
Reclassification adjustment for losses included in net income, net of income tax benefit of $32,674 for 2001 and
$5,087 for 2002 - - - 45,748 45,748 7,122 52,870 Net unrealized gains (losses) on investments (1,588) (32,519) (34,107) 35,348 1,241 (2,532) (1,291)
Minimum pension liability adjustment, net of income tax benefit of $339 for 2000, $1,828 for 2001 and
$39,378 for 2002 - (630) (630) (2,546) (3,176) (58,485) (61,661)
Unrealized gains (losses) on derivatives qualified as hedges:
Unrealized gains on derivatives qualified as hedges arising during the period due to cumulative effect of a change in accounting principle, net of income tax expense of $(38,671) for 2001 - - - 58,250 58,250 - 58,250 Unrealized (losses) gains during period on derivatives qualified as hedges, net of tax benefit (expense) of $59,510 for 2001 and $(26,984) for 2002 - - - (89,955) (89,955) 37,692 (52,263)
Reclassification adjustment for losses included in net income, net of income tax benefit of $(7,416) for 2001 and $(7,351) for 2002 - - - 11,305 11,305 11,493 22,798 Net unrealized gains (losses) on derivatives qualified as hedges - - - (20,400) (20,400) 49,185 28,785 Accumulated Other Comprehensive Income (Loss) $(1,681) $(33,142) $(34,823) $12,488 $(22,335) $(11,832) $(34,167) 57 z
(See Risk management in Note 1.)
NOTE 15 Retirement Benefits Pension Benefits Postretirement Benefits 2002 2001 2002 2001 (Thousands)
Change in projected benefit obligation Benefit obligation at January 1 $1,369,448 $1,242,769 $408,427 $395,857 Service cost 29,318 23,967 6,040 5,091 Interest cost 111,943 90,949 32,215 25,024 Plan participants' contributions 212 255 Plan amendments 465 39,614 (11,922) (26,967)
Actuarial loss 114,742 37,949 55,240 31,895 Business combination 501,454 92,198 Curtailment (670) (394)
Special termination benefits 64,909 2,551 Benefits paid (98,415) (67,681) (25,140) (22,334)
Projected benefit obligation at December 31 $2,093,864 $1,369,448 $557,270 $408,427 Change in plan assets Fair value of plan assets at January 1 $1,822,052 $1,925,905 $38,634 $40,226 Actual return on plan assets (244,955) (37,564) (3,248) (1,804)
Employer contributions 329 433 23,215 22,291 Plan participants' contributions - - 212 255 Business combination 585,390 -- -
Adjustment - 959 415 Benefits paid (98,415) (67,681) (25,140) (22,334)
Fair value of plan assets at December 31 $2,064,401 $1,822,052 $34,088 $38,634 Funded status $(29,463) $452,604 $(523,182) $(369,793)
Unrecognized net actuarial loss (gain) 527,617 (59,273) 106,401 46,983 Unrecognized prior service cost (benefit) 50,741 58,277 (54,929) (60,365)
Unrecognized net transition (asset) obligation (8,469) (15,707) 80,661 100,384 Prepaid (accrued) benefit cost $540,426 $435,901 $(391,049) $(282,791)
Amounts recognized in the balance sheet Prepaid benefit cost $540,426 $435,901 $99 $516 Accrued benefit cost - - (391,148) (283,307)
Additional minimum liability (185,321) (43,872) -
Intangible asset 6,226 2,517 -
Regulatory liability 76,913 37,022 -
Accumulated other comprehensive income 102,182 4,333 -
Net amount recognized $540,426 $435,901 $(391,049) $(282,791)
CMP Group's, CNE's and CTG Resources' postretirement benefits were partially funded as of December 31, 2002 and 2001.
The company recorded a minimum pension liability of $185 million at December 31, 2002, as required by Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions. The effect of the minimum pension liability is recognized in other long-term liabilities, intangible assets, regulatory liability and other comprehensive income, as appropriate, and is prescribed when the accumulated benefit obligation in the plan exceeds the fair value of the underlying pension plan assets and accrued pension liabilities. The increase in the unfunded accumulated benefit obligation is primarily due to a reduction in the assumed discount rate, 58 investment market conditions and a voluntary early retirement program offered by the company as part of its en restructuring. (See Note 2.)
0'I
Pension Benefits Postretirement Benefits 2002 2001 2000 2002 2001 2000 Weighted-average assumptions as of December 31 Discount rate 6.5% 7.0% 7.25% 6.5% 7.0% 7.25%
Expected return on plan assets 9.0% 9.0% 9.0% 9.0% 9.0% 9.0%
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
As of December 31, 2002, the company decreased its discount rate from 7.0% to 6.5% and its expected return on plan assets from 9.0% to 8.75% effective January 1, 2003.
The company assumed a 10% annual rate of increase in the costs of covered health care benefits for 2003 that gradually decreases to 5% by the year 2006.
Pension Benefits Postretirement Benefits 2002 2001 2000 2002 2001 2000 (Thousands)
Components of net periodic benefit cost Service cost $29,318 $23,967 $20,979 $6,040 $5,091 $7,031 Interest cost 111,943 90,949 70,486 32,215 25,024 24,213 Expected return on plan assets (190,541) (161,731) (123,772) (2,993) (3,378) (1,559)
Amortization of prior service cost 8,035 7,822 1,706 (6,761) (6,753)
Recognized net actuarial gain (36,686) (41,750) (40,103) 1,647 (4,122) (2,630)
Amortization of transition (asset) obligation (7,238) (7,238) (7,238) 9,126 9,126 9,126 Special termination benefits 64,909 2,551 rinse "a2n Ofc%
Deferral for future recovery /<
Net periodic benefit cost $(52,346) $(85,430) $(77,942) $39,274 $24,988 $30,786 Net periodic benefit cost is included in other operating expenses on the consolidated statements of income.
The net periodic benefit cost for postretirement benefits represents the cost the company charged to expense for providing health care benefits to retirees and their eligible dependents. The amount of postretirement benefit cost deferred was $88 million as of December 31, 2002, and $68 million as of December 31, 2001. The company expects to recover any deferred postretirement costs by 2012. The transition obligation for postretirement benefits is being amortized over a period of 20 years.
A 1% increase or decrease in the health care cost inflation rate from assumed rates would have the following effects:
1% Increase 1% Decrease Effect on total of service and interest cost components $2 million $(2 million)
Effect on postretirement benefit obligation $33 million $(28 million) 59 z
NOTE 16 Segment Information Selected financial information for the company's business segments is presented in the table below. The company's electric delivery segment consists of its regulated transmission, distribution and generation operations in New York and Maine and its natural gas delivery segment consists of its regulated transportation, storage and distribution operations in New York, Connecticut, Maine and Massachusetts. Other includes: the company's corporate assets, interest income, interest expense and operating expenses; intersegment eliminations; and nonutility businesses.
Electric Natural Gas Delivery Delivery Other Total (Thousands) 2002 Operating Revenues $2,568,247 $1,032,539 $408,132 $4,008,918 Depreciation and Amortization $162,515 $71,329 $13,152 $246,996 Operating Income $449,029 $149,656 $(6,509) $592,176 Interest Charges, Net $183,716 $73,177 $854 $257,747 Income Taxes $94,238 $26,557 $(22,271) $98,524 Net Income $170,337 $51,128 $(32,862) $188,603 Total Assets $6,035,461 $3,058,885 $1,175,533 $10,269,879 Capital Spending $137,414 $86,301 $5,672 $229,387 2001 Operating Revenues $2,504,896 $1,026,124 $228,767 $3,759,787 Depreciation and Amortization $118,882 $75,432 $9,967 $204,281 Operating Income $553,421 $89,518 $(6,051) $636,888 Interest Charges, Net $154,011 $55,785 $7,232 $217,028 Income Taxes $178,125 $18,144 $(41,890) $154,379 Net Income $228,782 $17,938 $(59,113) $187,607 Total Assets $4,175,280 $2,467,647 $626,305 $7,269,232 Capital Spending $95,627 $106,116 $21,132 $222,875 2000 Operating Revenues $2,023,610 $772,131 $163,779 $2,959,520 Depreciation and Amortization $105,067 $49,769 $10,688 $165,524 Operating Income $482,657 $72,729 $(41,465) $513,921 Interest Charges, Net $105,826 $41,229 $5,448 $152,503 Income Taxes $146,529 $12,182 $(3,150) $155,561 Net Income $228,971 $15,632 $(9,569) $235,034 Total Assets $4,212,623 $2,406,848 $394,257 $7,013,728 Capital Spending $70,651 $68,170 $29,499 $168,320 60 2
NOTE 17 Quarterly Financial Information (Unaudited)
Quarter Ended March 31 June 30 September 30 December 31 (Thousands, except per share amounts) 2002 Operating Revenues $1,028,578 $714,874 $1,016,189 $1,249,277 Operating Income $238,869 $81,476 $113,500 $158,331 Net Income $105,57001l $5,323(1 $23,742 $53,96812)
Earnings Per Share, basic and diluted' $.90(1l $.051) $.16 $.372 Dividends Per Share $.24 $.24 $.24 $.24 Average Common Shares Outstanding 116,720 117,820 144,621 144,849 Common Stock Price'3 )
High $21.92 $23.13 $22.53 $22.70 Low $18.50 $20.92 $15.75 $18.25 2001 Operating Revenues $1,271,139 $849,010 $798,848 $840,790 Operating Income $262,528 $90,161 $94,567 $189,632 Net Income (Loss) $115,601 $26,574 $(21,057)(1) $66,489 Earnings (Loss) Per Share, basic and diluted $.98 $.23 $(.18)(1) $.57 Dividends Per Share $.23 $.23 $.23 $.23 Average Common Shares Outstanding $117,386 116,399 116,436 116,623 3
Common Stock Price )
High $20.31 $21.20 $22.14 $21.49 Low $16.96 $17.41 $18.99 $17.65 (1) Includes the effect of writedowns of CMP Group's investment in NEON Communications, Inc. that decreased net income and earnings per share as follows: $6 million and five cents in the first quarter of 2002, $1 million and one cent in the second quarter of 2002 and $46 million and 39 cents in the third quarter of 2001.
(2) Includes the effect of restructuring expenses recorded in the fourth quarter of 2002 that decreased net income $24 million and earnings per share 17 cents.
(3) The company's common stock is listed on the New York Stock Exchange. The number of shareholders of record was 39,620 at December 31, 2002.
61 05 z
- . t fl li n W- i au sum. a ..- ma :.-
Report of Management The company's management is responsible for the preparation, integrity and reliability of the consolidated financial statements, notes and other information in this annual report. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles and include estimates that are based upon management's judgment and the best available information. Other financial information contained in this report was prepared on a basis consistent with that of the consolidated financial statements.
The company maintains a system of internal controls designed to provide reasonable assurance to its management and board of directors regarding the preparation of reliable published financial statements and the safeguarding of assets against loss or unauthorized use. The system contains self-monitoring mechanisms and actions are taken to correct deficiencies as they are identified. Even an effective internal control system, no matter how well designed, has inherent limitations, including the possibility of the circumvention or overriding of controls, and therefore can provide only reasonable assurance with respect to financial statement preparation and the safeguarding of assets. Further, because of changes in conditions, internal control system effectiveness may vary over time.
The company maintains an internal audit department that independently assesses the effectiveness of the internal controls. In addition, the company's independent accountants, PricewaterhouseCoopers LLP, have considered the company's internal control structure to the extent they considered necessary in expressing an opinion on the consolidated financial statements. Management is responsive to the recommendations of its internal audit department and the independent accountants concerning internal controls and corrective measures are taken when considered appropriate. In addition, a Code of Conduct addresses areas of compliance and provides employees with guidance that promotes sound ethical business practices. It also requires all management employees to formally affirm their compliance with the Code of Conduct. The board of directors oversees the company's financial reporting through its audit committee. The committee, which consists entirely of outside directors, meets regularly with management, the internal auditor and the independent accountants to discuss auditing, internal control and financial reporting matters, and assists the board of directors in overseeing the company's Corporate Compliance Program. Both the internal auditor and independent accountants have direct access to the audit committee, independent of management.
The company assessed its internal control system as of December 31, 2002, in relation to criteria for effective internal control over financial reporting and the safeguarding of assets described in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, the company believes that, as of December 31, 2002, its system of internal control over financial reporting and over the safeguarding of assets against loss or unauthorized use met those criteria.
Robert E. Rude Vice President and Controller A A Kenneth M. Jasinski Executive Vice President and Chief Financial Officer 62 to 4,c2_
Wesley W. von Schack Chairman, President & Chief Executive Officer
1-1-11 Report of Independent Accountants I'RCEWATERHOUS<cDPERSU To the Shareholders and Board of Directors, Energy East Corporation and Subsidiaries In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of cash flows and of changes in common stock equity present fairly, in all material respects, the financial position of Energy East Corporation and its subsidiaries ("the Company") at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Notes 1 and 14 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative and hedging activities pursuant to Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities (an amendment of FASB Statement No. 133). In addition, as discussed in Notes 1 and 4 to the consolidated financial statements, effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.
New York, New York January 31, 2003 63 C-
- a. soigoa. ss.w ' xjwa .Aeasau6 - - ,1.11.1,-I-4,-I.",,;.,,i,,,-,- 41 "Ij-- --- ,, -_ I 1. - - - , .I -
Selected Financial Data 20021') 2001 2000(4) 1999 1998 1997 (Thousands, except per share amounts)
Operating Revenues Sales and services $4,008,918 $3,759,787 $2,959,520 $2,278,608 $2,499,568 $2,170,102 Operating Expenses Electricity purchased and fuel used in generation 1,276,087 1,334,507 1,073,728 905,367 992,236 643,063 Natural gas purchased 603,258 694,038 496,509 186,722 158,757 164,661 Gasoline, propane and oil purchased 143,770 3,688 1,560 - - -
Other operating expenses 713,384 566,498 434,405 312,129 367,897 406,830 Maintenance 162,122 139,395 108,106 85,849 111,503 110,373 Depreciation and amortization 246,996 204,281 165,524 648,970 (5) 191,462 202,151 Other taxes 230,558 192,772 165,767 179,028 204,483 205,974 Restructuring expenses 40,567 - - - -
Gain on sale of generation assets - (84,083) - (674,572)
Deferral of asset sale gain - 71,803 - -
Writeoff of Nine Mile Point 2 - - - 72,532 -
Total Operating Expenses 3,416,742 3,122,899 2,445,599 1,716,025 2,026,338 1,733,052 Operating Income 592,176 636,888 513,921 562,583 473,230 437,050 Writedown of Investment 12,209 78,422 1i - - -
Other (Income) and Deductions 2,964 (15,041) (30,157) (12,573) 7,474 11,113 Interest Charges, Net 257,747 217,066 152,520 132,908 125,557 123,199 Preferred Stock Dividends of Subsidiaries 32,129 14,455 963 2,706 8,583 9,342 Income Before Income Taxes 287,127 341,986 390,595 439,542 331,616 293,396 Income Taxes 98,524 154,379 155,561 220,791 137,411 118,185 Net Income 188,60302 187,607(3) 235,034 218,751 194,205 175,211 16 Common Stock Dividends 125,456 107,342 99,606 98,725 100,487 95,496 Retained Earnings Increase $63,147 $80,265 $135,428 $120,026 $93,718 $79,715 Average Common Shares Outstanding 131,117 116,708 114,213 116,316 128,742 136,306 Earnings Per Share, basic and diluted $1.44(2) $1.61 (3) $2.06 $1.88 $1.51 $1.29A6 Dividends Paid Per Share $.96 $.92 $.88 $.84 $.78 $.70 Book Value Per Share of Common Stock at Year End $16.97 $15.26 $14.59 $12.84 $13.61 $13.36 Capital Spending $229,387 $222,875 $168,320 $82,674 $137,350 $129,551 Total Assets $10,269,879 $7,269,232 $7,013,728 $3,773,171 $4,902,085 $5,044,914 Long-term Obligations, Capital Leases and Redeemable Preferred Stock $3,721,959 $2,816,278 $2,346,814 $1,235,089 $1,460,120 $1,475,224 All per share amounts and shares outstanding have been restated to reflect the two-for-one common stock split effective April 1, 1999.
Reclassifications: Certain amounts included in Selected Financial Data have been reclassified to conform with the 2002 presentation.
(1) Due to the completion of the company's merger transaction during 2002 the consolidated financial statements include RGS Energy's results beginning with July 2002.
(2) Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $7 million and earnings per share six cents and the 64 effect of restructuring expenses that decreased net income $24 million and earnings per share 19 cents.
(3)Includes the writedown of CMP Group's investment in NEON Communications, Inc. that decreased net income $46 million and earnings per share 39 cents.
(4) Due to the completion of the company's merger transactions during 2000 the consolidated financial statements include CNE's results beginning with February 2000 and include CMP Group's, CTG Resources' and Berkshire Energy's results beginning with September 2000.
(5) Depreciation and amortization includes accelerated amortization of NMP2 related to the sale of the company's coal-fired generation assets, authorized by the NYPSC.
(6) Includes the effect of fees related to an unsolicited tender offer that decreased net income $17 million and earnings per share 12 cents.
Energy Distribution Statistics 2002 2001 2000 1999 1998 1997 (Thousands)
Electric Deliveries (Megawatt-hours)
Residential 10,226 8,594 6,473 5,447 5,199 5,267 Commercial 8,019 6,527 4,504 3,517 3,428 3,495 Industrial 6,694 6,525 4,613 3,383 3,222 3,065 Other 1,930 1,592 1,543 1,496 1,428 1,411 Total Retail 26,869 23,238 17,133 13,843 13,277 13,238 Wholesale 5,330 6,048 6,214 10,978 22,711 10,406 Total Electric Deliveries 32,199 29,286 23,347 24,821 35,988 23,644 Electric Revenues Residential $1,073,586 $998,846 $820,093 $747,964 $720,546 $728,777 Commercial 609,165 622,996 460,453 393,623 393,857 403,481 Industrial 313,622 314,527 263,633 237,637 246,589 243,868 Other 175,130 162,987 153,283 159,730 158,215 157,517 Total Retail 2,171,503 2,099,356 1,697,462 1,538,954 1,519,207 1,533,643 Wholesale 190,090 238,094 212,630 312,727 611,852 232,138 Other 206,654 167,446 113,518 37,637 28,810 26,383 Total Electric Revenues $2,568,247 $2,504,896 $2,023,610 $1,889,318 $2,159,869 $1,792,164 Natural Gas Deliveries (Dekatherms)
Residential 62,748 52,846 42,238 23,327 20,960 24,357 Commercial 21,190 20,699 15,823 8,247 7,909 10,178 Industrial 2,934 2,847 2,690 1,669 1,779 2,409 Other 14,507 12,726 10,074 2,677 2,568 2,735 Transportation of customer-owned natural gas 80,480 58,882 37,314 23,426 20,962 19,645 Total Retail 181,859 148,000 108,139 59,346 54,178 59,324 Wholesale 7,074 9,298 10,674 8,617 7,527 3,027 Total Natural Gas Deliveries 188,933 157,298 118,813 67,963 61,705 62,351 Natural Gas Revenues Residential $594,279 $576,115 $390,794 $181,579 $171,437 $190,564 Commercial 192,023 226,215 145,318 63,112 61,059 83,091 Industrial 20,883 26,220 19,339 8,123 8,155 13,044 Other 83,735 89,524 68,652 14,745 14,257 17,839 Transportation of customer-owned natural gas 84,927 73,213 59,901 33,572 29,589 21,949 Total Retail 975,847 991,287 684,004 301,131 284,497 326,487 Wholesale 17,260 37,748 55,184 21,831 17,791 9,114 Other 39,432 (2,911) 32,943 8,783 3,743 2,224 Total Natural Gas Revenues $1,032,539 $1,026,124 $772,131 $331,745 $306,031 $337,825 65 co
I *_n
- 73k-i'..
- s .
Board of Directors Richard Aurelio, a director since 1997, formerly Committees (Chairperson listed first)
President of Time Warner Cable Group New York Audit: Lynch, Castiglia, DeFleur, Jagger and NY One News, is now a director of the Javits Foundation and City University Television, all in Corporate Responsibility: Carrigg, Keeler, New York, New York. Moynihan, Rich Compensation and Management Succession:
James A. Carrigg, a director since 1983, is a director Castiglia, Aurelio, Lynch of Security Mutual Life Insurance Company of New York and National Security Life and Annuity Company, Nominating and Corporate Governance:
both in Binghamton, New York. Aurelio, DeFleur, Keeler, Rich Joseph J. Castiglia, a director since 1995, is Chairman of the Catholic Health System of Western Energy East Officers New York and of HealthNow New York, Inc., DBA Blue Cross & Blue Shield of Western New York, both in Robert M. Allessio Buffalo, New York, and Blue Shield of Northeastern President - The Berkshire Gas Company New York, in Albany, New York. Richard R. Benson Lois B. DeFleur, a director since 1995, is President Vice President - Human Resources of the State University of New York at Binghamton Sara J. Burns in Binghamton, New York. President - Central Maine Power Company Michael 1. German G. Jean Howard, a director since June 2002, is President - The Energy Network, Inc.
Executive Director of Wilson Commencement Park Kenneth M. Jasinski in Rochester, New York.
Executive Vice President and ChiefFinancialOfficer David M. Jagger, a director since 2000, is Robert D. Kump President and Treasurer of Jagger Brothers, Inc. Vice President, Treasurer& Secretary in Springvale, Maine.
James P. Laurito John M. Keeler, a director since 1989, is counsel President - ConnecticutNatural Gas Corporation and The Southern Connecticut Gas Company at Hinman, Howard & Kattell, LLP, attorneys-at-law in Binghamton, New York. F. Michael McClain Vice President - Finance and ChiefIntegration Officer Ben E. Lynch, a director since 1987, is President of Patrick Neville Winchester Optical Company in Elmira, New York. Vice President- Information Technology Peter J. Moynihan, a director since 2000, is a former Clifton B. Olson Senior Vice President and Chief Investment Officer of Vice President - Energy Supply UNUM Corporation in Portland, Maine. Jessica Raines Vice President - Supply Chain Walter G. Rich, a director since 1997, is Chairman, President, Chief Executive Officer and a director of Robert E. Rude Delaware Otsego Corporation in Cooperstown, New Vice Presidentand Controller York, and its subsidiary, The New York, Susquehanna Angela M. Sparks-Beddoe
& Western Railway Corporation. Vice President - Public Affairs Ralph R. Tedesco Wesley W. von Schack, a director since 1996, President - New York State Electric & Gas Corporation 66 is Chairman, President & Chief Executive Officer Denis E. Wickham SI of the corporation.
6 Senior Vice President - Transmission and Energy Supply E
Paul C. Wilkens President - Rochester Gas and Electric Corporation E-E
Shareholder Information Shareholder Services Transfer Agent and Registrar:
Mellon Investor Services Shareholder Services representatives are available between 8 a.m. and 4:30 p.m. (Eastern Time) on To present certificates for transfer (certified regular business days at 1-800-225-5643. Or you may or registered mail is recommended) write to:
write to: Mellon Investor Services Energy East Corporation P0. Box 3312 Attention: ShareholderServices South Hackensack, NJ 07606-1912 P.0. Box 3200 To request transfer instructions, write to:
Ithaca, NY 14852-3200 Mellon Investor Services Please contact Shareholder Services with P0. Box 3315 questions regarding: South Hackensack, NJ 07606-1915
- our dividend reinvestment and stock purchase plan
- dividend payments or lost dividend checks Investor Relations
- direct deposit of dividends Members of the financial community may contact our
- replacement of lost certificates Manager, Investor Relations by phone at 607-347-2561
- a change of address or by fax at 607-347-2560.
- annual report requests
- our annual meeting of shareholders Principal Offices Shareholders may also obtain a free copy of PO. Box 12904, Albany New York 12212-2904 Form 10-K, which is filed each year with the 217 Commercial Street, Portland, Maine 04101 Securities and Exchange Commission, by contacting Shareholder Services.
Trading Symbol: EAS The Shareholder Connection: EAS is the trading symbol for Energy East Corporation 1-800-225-5643 common stock listed on the New York Stock Exchange.
Investor information is available at your fingertips.
This service provides quick access to Energy East's Annual Meeting common stock closing price as well as timely dividend Formal notice of the meeting, a proxy statement and and news release information 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, seven form of proxy will be mailed to shareholders.
days a week.
Internet Address: www.energyeast.com Information of interest to shareholders, including financial documents and news releases, is available at our Web site.
67 0
E c
-S 0:2 T
I iJ.._ --. Z gil Subsidiary Companies Central Maine Power Company (CMP) 83 Edison Drive, Augusta, ME 04336 www.cmpco.com Connecticut Natural Gas Corporation (CNG) 10 State House Square, 6th Floor, P.O. Box 1500, Hartford, CT 06144-1500 www.cngcorp.com New York State Electric & Gas Corporation (NYSEG)
Carrigg Center - Corporate Drive, P.O. Box 5224, Binghamton, NY 13902-5224 Ithaca-Dryden Road, P.O. Box 3287, Ithaca, NY 14852-3287 www.nyseg.com Rochester Gas and Electric Corporation (RG&E) 89 East Avenue, Rochester, NY 14649 www.rge.com The Berkshire Gas Company (Berkshire Gas) 115 Cheshire Road, Pittsfield, MA 01201 www.berkshiregas.com The Southern Connecticut Gas Company (SCG) 855 Main Street, Bridgeport, CT 06604 www.soconngas.com Energetix, Inc.
755 Brooks Avenue, Rochester, NY 14619 Energy East Enterprises, Inc.
81 State Street, Stephens Square, 5th Floor, Binghamton, NY 13901 The Energy Network, Inc.
81 State Street, Stephens Square, 5th Floor, Binghamton, NY 13901 68 E
C)
CD CC