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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
| | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
405-553-3000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes x No
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There were 40,378,745 Shares of Common Stock, par value $2.50 per share,
outstanding as of July 31, 1999.
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OKLAHOMA GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
STATEMENTS OF INCOME
(Unaudited)
3 Months Ended 6 Months Ended
June 30 June 30
------------------------------- ----------------------------------
1999 1998 1999 1998
------------- -------------- ---------------- ---------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
OPERATING REVENUES......................................... $ 314,102 $ 336,017 $ 564,246 $ 572,662
------------- ------------- ---------------- ---------------
OPERATING EXPENSES:
Fuel..................................................... 85,698 88,922 153,656 158,790
Purchased power.......................................... 62,267 57,757 121,390 114,082
Other operation and maintenance.......................... 65,012 63,206 120,121 125,371
Depreciation............................................. 29,553 29,321 58,856 58,928
Taxes other than income.................................. 10,875 10,925 22,227 22,725
------------- ------------- ---------------- ---------------
Total operating expenses............................... 253,405 250,131 476,250 479,896
------------- ------------- ---------------- ---------------
OPERATING INCOME........................................... 60,697 85,886 87,996 92,766
------------- ------------- ---------------- ---------------
OTHER INCOME (EXPENSES):
Interest charges......................................... (11,799) (12,032) (23,095) (24,010)
Other, net............................................... 770 703 466 886
------------- ------------- ---------------- ---------------
Net other income (expenses)............................ (11,029) (11,329) (22,629) (23,124)
------------- ------------- ---------------- ---------------
EARNINGS BEFORE INCOME TAXES............................... 49,668 74,557 65,367 69,642
PROVISION FOR INCOME TAXES................................. 15,939 28,678 21,449 25,842
------------- ------------- ---------------- ---------------
NET INCOME ................................................ 33,729 45,879 43,918 43,800
PREFERRED DIVIDEND REQUIREMENTS............................ - - - 733
------------- ------------- ---------------- ---------------
EARNINGS AVAILABLE FOR COMMON.............................. $ 33,729 $ 45,879 $ 43,918 $ 43,067
============= ============= ================ ===============
AVERAGE COMMON SHARES OUTSTANDING.......................... 40,379 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.84 $ 1.14 $ 1.09 $ 1.07
============= ============= ================ ================
DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 0.665 $ 1.28 $ 1.31
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
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<CAPTION>
BALANCE SHEETS
(Unaudited)
JUNE 30 DECEMBER 31
1999 1998
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 177 $ 312
Accounts receivable - customers, less reserve of $2,200 and
$2,441, respectively........................................ 88,935 91,434
Accrued unbilled revenues..................................... 59,000 22,500
Accounts receivable - other................................... 11,360 7,723
Fuel inventories, at LIFO cost................................ 62,571 47,081
Materials and supplies, at average cost....................... 31,885 25,894
Prepayments and other......................................... 10,679 28,641
Accumulated deferred tax assets............................... 7,525 6,889
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Total current assets........................................ 272,132 230,474
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OTHER PROPERTY AND INVESTMENTS, at cost......................... 19,637 17,454
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PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 3,730,450 3,674,732
Construction work in progress................................. 20,383 28,439
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Total property, plant and equipment......................... 3,750,833 3,703,171
Less accumulated depreciation............................. 1,776,433 1,727,472
------------- --------------
Net property, plant and equipment............................. 1,974,400 1,975,699
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 14,900 15,000
Income taxes recoverable - future rates....................... 40,211 40,731
Other......................................................... 37,823 40,739
------------- --------------
Total deferred charges...................................... 92,934 96,470
------------- --------------
TOTAL ASSETS.................................................... $ 2,359,103 $ 2,320,097
============= ==============
CAPITALIZATION AND LIABILITIES
CURRENT LIABILITIES:
Accounts payable - affiliates................................. $ 138,387 $ 67,045
Accounts payable.............................................. 33,294 45,536
Customers' deposits........................................... 23,879 23,984
Accrued taxes................................................. 19,264 18,932
Accrued interest.............................................. 15,446 15,931
Other......................................................... 23,252 38,642
------------- --------------
Total current liabilities................................... 253,522 210,070
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LONG-TERM DEBT.................................................. 702,979 702,912
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 20,537 18,162
Accumulated deferred income taxes............................. 452,436 462,886
Accumulated deferred investment tax credits................... 65,153 67,728
Other......................................................... 18,724 4,768
------------- --------------
Total deferred credits and other liabilities................ 556,850 553,544
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STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 333,306 341,125
------------- --------------
Total stockholders' equity.................................. 845,752 853,571
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,359,103 $ 2,320,097
============= ==============
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
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<CAPTION>
STATEMENTS OF
CASH FLOWS
(Unaudited)
6 MONTHS ENDED
JUNE 30
1999 1998
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 43,918 $ 43,800
Adjustments to Reconcile Net Income to Net
Cash Provided From Operating Activities:
Depreciation..................................................... 58,856 58,928
Deferred income taxes and investment tax credits, net............ (12,734) (3,597)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 2,499 (29,434)
Accrued unbilled revenues...................................... (36,500) (24,200)
Fuel, materials and supplies inventories....................... (21,481) (604)
Accumulated deferred tax assets................................ (636) (135)
Other current assets........................................... 14,325 6,261
Accounts payable............................................... (3,710) 39,597
Accrued taxes.................................................. 332 417
Accrued interest............................................... (485) (2,411)
Other current liabilities...................................... (15,495) 7,053
Other operating activities..................................... 19,587 (2,711)
-------------- --------------
Net cash provided from operating activities.................. 48,476 92,964
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (59,683) (48,449)
-------------- --------------
Net cash used in investing activities........................ (59,683) (48,449)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... --- (112,500)
Proceeds from long-term debt....................................... --- 100,000
Short-term debt, net............................................... 62,810 71,964
Redemption of preferred stock...................................... --- (49,266)
Cash dividends declared on preferred stock......................... --- (733)
Cash dividends declared on common stock............................ (51,738) (52,713)
-------------- --------------
Net cash provided by (used in) financing activities.......... 11,072 (43,248)
-------------- --------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS................. (135) 1,267
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 312 228
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 177 $ 1,495
============== ==============
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid During The Period For:
Interest (net of amount capitalized)............................. $ 21,210 $ 23,460
Income taxes..................................................... $ 16,579 $ 12,183
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<FN>
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid debt
instruments purchased with a maturity of three months or less to be cash
equivalents. These investments are carried at cost which approximates market.
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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NOTES TO FINANCIAL STATEMENTS
1. (Unaudited) The condensed financial statements included herein have been
prepared by Oklahoma Gas and Electric Company (the "Company"), without
audit, pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures normally included
in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules
and regulations; however, the Company believes that the disclosures are
adequate to make the information presented not misleading.
In the opinion of management, all adjustments necessary to present fairly
the financial position of the Company as of June 30, 1999, and December 31,
1998, and the results of operations and the changes in cash flows for the
periods ended June 30, 1999, and June 30, 1998, have been included and are
of a normal recurring nature.
The results of operations for such interim periods are not necessarily
indicative of the results for the full year. It is suggested that these
condensed financial statements be read in conjunction with the financial
statements and the notes thereto included in the Company's Form 10-K for
the year ended December 31, 1998.
2. In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting
for Derivative Instruments and for Hedging Activities", with an effective
date for periods beginning after June 15, 1999. In July 1999, the FASB
issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities Deferral of the Effective Date of FASB Statement No. 133".
Adoption of SFAS No. 133 is now required for financial statements for
periods beginning after June 15, 2000. The Company will adopt this new
standard effective January 1, 2001, and management believes the adoption of
this new standard will not have a material impact on its financial position
or results of operation.
ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OVERVIEW
The following discussion and analysis presents factors which affected the
results of operations for the three and six months ended June 30, 1999
(respectively, the "current periods"), and the financial position as of June 30,
1999, of the Company. Unless indicated otherwise, all comparisons are with the
corresponding periods of the prior year. Revenues from sales of electricity are
somewhat seasonal, with a large portion of the Company's annual electric
revenues
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occurring during the summer months when the electricity needs of its customers
increase. Because of seasonal fluctuations and other factors, the results of one
interim period are not necessarily indicative of results to be expected for the
year. Actions of the regulatory commissions that set the Company's electric
rates will continue to affect financial results.
Some of the matters discussed in this Form 10-Q may contain forward-looking
statements that are subject to certain risks, uncertainties and assumptions.
Actual results may vary materially. Factors that could cause actual results to
differ materially include, but are not limited to: general economic conditions,
including their impact on capital expenditures; business conditions in the
energy industry; competitive factors; unusual weather; failure of companies that
the Company does business with to be Year 2000 ready; regulatory decisions and
other risk factors listed in the Company's Form 10-K for the year ended December
31, 1998, including Exhibit 99.01 thereto, and other factors described from time
to time in the Company's reports to the Securities and Exchange Commission.
EARNINGS
Net income decreased $12.2 million or 26.5 percent in the three months
ended June 30, 1999. For the six months ended June 30, 1999, net income
increased $0.1 million or 0.3 percent. As explained below, the Company's
decrease in earnings for the three months ending June 30, 1999, was primarily
attributable to lower revenues due to decreased sales to Company customers
("system sales") due to cooler weather in the Company electric service area and
lower revenues from sales to other utilities and power marketers ("off-system
sales"). For the six months ending June 30, 1999, the Company's increase in
earnings reflects lower operating expenses and taxes that offset lower revenues
from system sales and off-system sales. Earnings per average common share
decreased from $1.14 to $0.84 and increased from $1.07 to $1.09 in the current
periods.
REVENUES
Operating revenues decreased $21.9 million or 6.5 percent and $8.4 million
or 1.5 percent in the current periods. The decrease in electric sales were
primarily attributable to cooler weather in the Company's electric service area
and a significant reduction in off-system sales. Kilowatt-hour system sales
decreased 5.1 percent in the three months ended June 30, 1999, due to cooler
weather. In the six months ended June 30, 1999, continued growth in the
Company's electric service area offset the effects of the unfavorable weather,
resulting in an increase in kilowatt-hour system sales of 0.7 percent.
Kilowatt-hour off-system sales decreased 50.0 percent and 73.1 percent in the
current periods. However, off-system sales are generally priced at much lower
prices per kilowatt-hour and have less impact on operating revenues and earnings
than system sales.
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EXPENSES
Total operating expenses increased $3.3 million or 1.3 percent in the three
months ended June 30, 1999. This increase was primarily due to purchased power
and other operation and maintenance. The increase was partially offset by lower
fuel expense.
In the six months ended June 30, 1999, total operating expenses decreased
$3.6 million or 0.8 percent due to lower other operation and maintenance and
fuel expenses. This decrease was partially offset by an increase in purchased
power.
Purchased power costs increased $4.5 million or 7.8 percent and $7.3
million or 6.4 percent primarily due to the availability of electricity at
favorable prices.
Other operation and maintenance increased $1.8 million or 2.9 percent and
decreased $5.3 million or 4.2 percent. The $5.3 million decrease in the six
months ended June 30, 1999, was due to miscellaneous corporate expenses. This
decrease was partially offset by expenses associated with tornadoes and severe
thunderstorms that inflicted heavy damage to the Company's power supply,
transmission and delivery systems on May 3, 1999. As previously reported, the
Company has estimated a total storm cost of approximately $15 million of which
approximately 25 percent will be expensed and the remainder capitalized.
Fuel expense decreased $3.2 million or 3.6 percent and $5.1 million or 3.2
percent in the current periods primarily due to decreased generation levels,
resulting from unfavorable weather in the Company's electric service area and
the significant reduction in off-system sales. Variances in the actual cost of
fuel used in electric generation and certain purchased power costs, as compared
to that component in cost-of-service for ratemaking, are passed through to
Company's electric customers through automatic fuel adjustment clauses. The
automatic fuel adjustment clauses are subject to periodic review by the Oklahoma
Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC")
and the Federal Energy Regulatory Commission ("FERC"). Enogex Inc. ("Enogex"),
an affiliate of the Company, owns and operates a pipeline business that delivers
natural gas to the generating stations of the Company. The OCC, the APSC and the
FERC have authority to examine the appropriateness of any gas transportation
charges or other fees the Company pays Enogex, which the Company seeks to
recover through the fuel adjustment clause or other tariffs.
LIQUIDITY AND CAPITAL REQUIREMENTS
The Company meets its cash needs through internally generated funds,
permanent financing and short-term borrowings. Internally generated funds and
short-term borrowings are expected to meet virtually all of the Company's
capital requirements through the remainder of 1999. Short-term borrowings will
continue to be used to meet temporary cash requirements.
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for utility service, to replace or expand
existing facilities and to some extent, for satisfying maturing debt and sinking
fund obligations. Capital expenditures of $59.7
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million for the six months ended June 30, 1999 were financed with internally
generated funds and short-term borrowings.
The Company's capital structure and cash flow remained strong throughout
the current periods. The Company's combined cash and cash equivalents decreased
approximately $135,000 during the six months ended June 30, 1999. The decrease
reflects the Company's cash flow from operations and short-term debt, offset by
construction expenditures and dividend payments.
In August 1999, Standard & Poor's ("S&P") and Moody's Investors Service
("Moody's") downgraded the debt ratings of the Company. S&P changed the
Company's corporate credit rating and senior unsecured debt ratings from "AA-"
to "A+". Moody's changed the Company's senior unsecured debt ratings from "Aa3"
to "A1". These ratings reflect the views of S&P and Moody's, and an explanation
of the significance of these ratings may be obtained from S&P and Moody's. A
security rating is not a recommendation to buy, sell or hold securities and is
subject to revision or withdrawal at any time by the rating agency.
Like any business, the Company is subject to numerous contingencies, many
of which are beyond its control. For discussion of significant contingencies
that could affect the Company, reference is made to Part II, Item 1 - "Legal
Proceedings" of this Form 10-Q, to Part II, Item 1 - "Legal Proceedings" in the
Company's Form 10-Q for the quarter ended March 31, 1999 and to "Management's
Discussion and Analysis" and Notes 8 and 9 of Notes to the Financial Statements
in the Company's 1998 Form 10-K.
THE YEAR 2000 ISSUE
There has been a great deal of publicity about the Year 2000 ("Y2K") and
the possible problems that information technology systems may suffer as a
result. The Y2K problem originated with the early development of computerized
business applications. To save then-expensive storage space, reduce the
complexity of calculations and yield better system performance, programmers and
developers used a two-digit date scheme to represent the year (i.e., "72" for
"1972"). This two-digit date scheme was used well into the 1980s and 1990s in
traditional computer hardware such as mainframe systems, desktop personal
computers and network servers, in customized software systems, off-the-shelf
applications and operating systems, as well as in embedded systems ("chips") in
everything from elevators to industrial plants to consumer products. As the Year
2000 approaches, date-sensitive systems may recognize the Year 2000 as 1900, or
not at all. This inability to recognize or properly treat the Year 2000 may
cause systems, including those of the Company, its customers, suppliers,
business partners and neighboring utilities to process critical financial and
operational information incorrectly, if they are not Year 2000 ready. A failure
to identify and correct any such processing problems prior to January 1, 2000
could result in material operational and financial risks if the affected systems
either cease to function or produce erroneous data. Such risks are described in
more detail below, but could include an inability to operate OG&E's generating
plants, disruptions in the operation of its transmission and distribution system
and an inability to access interconnections with the systems of neighboring
utilities.
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After the Company's mainframe conversion in 1994, some 300 programs were
identified as having date sensitive code. All of these programs have since been
corrected or replaced by Y2K ready packaged applications.
The Company continues to address the Y2K issues in an aggressive manner.
This is reflected by the January 1, 1997 implementation throughout the Company
of SAP Enterprise Software, which is Y2K ready, for the financial systems. The
SAP installation significantly reduced the potential risks in our older computer
systems. The Company is making significant progress towards the full
implementation of the enterprise-wide software system for customer systems. A
portion of our customer base began to be phased in to the new system in June of
1999. In addition to significantly reducing the potential risks of its current
customer systems, the Company is set to streamline work processes in customer
service and power delivery by integrating separate systems into a single system
using the enterprise-wide software system. This new single system will also
provide for a more flexible automated billing system and enhancements in
handling customer service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project Team
of experienced and knowledgeable members from each business unit to review and
test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency Planning
STATE OF READINESS
The Company has completed the internal inventory and assessment (Phase I)
of the Year 2000 plan. Follow-up vendor surveys are being sent to vendors that
have not responded to our original requests for information (Phase II).
Remediation is complete for systems essential to generate and deliver
electricity to our customers. Even though contingency planning is a normal part
of our business, plans are being updated and finalized to include specific
activities with regard to Y2K issues (Phase III).
In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that are Y2K ready. All existing personal
computers have been upgraded with Y2K ready operating systems. For embedded and
plant operational systems, the Company has completed the corrective process. The
Company's Energy Management System ("EMS") that
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monitors transmission interconnections and automatically signals generation
output changes was replaced in 1999. Software has been configured and new
equipment is installed and operational.
The Company participated in the "Y2K Electric System Readiness Assessment"
program, which provides monthly reports to the Southwest Power Pool ("SPP") and
the North American Electric Reliability Council ("NERC"). In February 1999, the
Company submitted contingency plans to the NERC and the SPP which will be used
along with those of other participating companies to formulate a regional
contingency plan. In April 1999, the Company also participated in a nationwide
communications drill as a part of the electric utility industry's Y2K readiness
preparation. The purpose of the drill was to determine how electric utilities
would communicate with one another in the event of an interruption of standard
communication systems. The ability to communicate would be important to
coordinate the flow of electricity over the nation's electric grid. The drill
was successful overall and communications in the SPP went smoothly with only
minor problems noted. On June 28, 1999, the Company reported to the NERC that
its essential systems used to produce and deliver electricity were ready for the
year 2000. The responses from all participating companies are being compiled for
an industry-wide status report to the Department of Energy ("DOE"). Also, the
Company plans to participate in the September 9, 1999, NERC drill.
COSTS OF YEAR 2000 ISSUES
As described above, with the mainframe conversion, the enterprise software
installations and the EMS replacement, a number of Y2K issues were addressed as
part of the Company's normal course upgrades to the information technology
systems. These upgrades were already contemplated and provided additional
benefits or efficiencies beyond the Year 2000 aspect. Since 1995 the Company has
spent in excess of $36 million on the mainframe conversion, the initial
financial enterprise software systems, the customer care enterprise software
installations to-date and the EMS replacement. The Company expects to spend
slightly less than $5 million in 1999. These costs represent estimates, however,
and there can be no assurance that actual costs associated with the Company's
Y2K issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the Company is considering such potential occurrences in planning for its most
reasonably likely worst case scenarios.
Additionally, risk exists regarding the non-readiness of third parties with
key business or operational importance to the Company. Year 2000 problems
affecting key customers, interconnected utilities, fuel suppliers and
transporters, telecommunications providers or
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financial institutions could result in lost power or gas sales, reductions in
power production or transmission or internal functional and administrative
difficulties on the part of the Company. Although the Company is not presently
aware of any such situations, occurrences of this type, if severe, could have
material adverse impacts upon the business, operating results or financial
condition of the Company. There can be no assurance that the Company will be
able to identify and correct all aspects of the Year 2000 problem that affect it
in sufficient time, that it will develop adequate contingency plans or that the
costs of achieving Y2K readiness will not be material.
RECENT REGULATORY MATTERS
On July 15, 1999, the Company filed with the OCC for approval of a
performance-based ratemaking plan that could lower rates for the Company's
Oklahoma customers by $83 million during the transition to deregulated customer
choice in mid-2002. The Company is the first utility in Oklahoma and among the
first in the nation to seek approval of such a plan.
Under the proposed performance-based ratemaking plan, the Company's rates
would be lowered by $29 million a year compared to June 1999 rates, resulting in
$83 million in savings for customers during the 30-month period ending July 1,
2002. The rates would be fixed and guaranteed. This would be accomplished, in
part, through the elimination of the Company's current fuel adjustment clause
through which increases and decreases in fuel costs are passed on to customers.
The risk of higher prices for the coal and natural gas used in generating
electricity would then shift from the customer to the Company.
Another key component of the proposed performance-based ratemaking plan is
a service quality incentive mechanism, pursuant to which the Company's
performance will be measured against its own benchmarks and recognized utility
industry standards. These measurements will then be used in a financial
reward/penalty program to promote continued reliability in the Company's
electric system, high levels of customer satisfaction and employee safety.
The Company believes that the lower electric rates would be made possible
in part, by a reduction in the cost of transporting natural gas to its power
plants. Under the proposal, Enogex would remain the Company's natural gas
transporter at an annual rate of $25 million, down from the current $41 million
rate. Other provisions of the proposed performance-based ratemaking plan include
termination of the generation efficiency performance rider and the termination
of the Company's rider for off-system electricity sales. In Oklahoma, profits
from off-system sales are shared equally between customers and shareowners. The
Company believes termination of this rider is consistent with providing
customers fixed rates, and would allow the Company to benefit from effectively
managing its business.
If approved by the OCC, the key provisions of the proposed
performance-based ratemaking plan will go into effect on January 1, 2000.
As previously reported, on February 13, 1998, The APSC staff filed a motion
for a show cause order to review the Company's electric rates in the State of
Arkansas. The Staff
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recommended a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Staff and the Company have reached a settlement for a
$2.3 million annual rate reduction. The settlement was presented to the APSC on
May 18, 1999. The APSC issued an order approving the settlement on August 6,
1999.
On April 8, 1999, lawmakers in Arkansas reached consensus on deregulation
of the state's electric industry. On April 15, 1999, Senate Bill 791 was signed
by the governor of Arkansas. Arkansas is the 18th state to pass a law calling
for restructuring of the electric utility industry. The new law targets customer
choice of electricity providers by January 1, 2002. The new law also provides
that utilities owning or controlling transmission assets must transfer control
of such transmission assets to an independent system operator, independent
transmission company or regional transmission group, if any such organization
has been approved by the FERC. Other provisions of the new law permit municipal
electric systems to opt in or out, permit recovery of stranded costs and
transition costs and require unbundled rates by July 1, 2000 for generation,
transmission, distribution and customer service. If implemented as proposed, the
new law will significantly affect the Company's future Arkansas operations. The
Company's electric service area includes parts of western Arkansas, including
Fort Smith, the second-largest metropolitan market in the state.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997. Various amendments to the Act were enacted in 1998.
The Company remains involved in the rulemaking process that will provide for
customer choice in Oklahoma by July 1, 2002.
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PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1998 Form 10-K for a
description of certain legal proceedings presently pending. Except as described
below, there are no new significant cases to report against the Company and
there have been no significant changes in the previously reported proceedings.
United States of America, ex rel., Jack J. Grynberg v. Enogex Inc., Enogex
Services Corporation and Oklahoma Gas & Electric Company. In the United States
District Court for the Western District of Oklahoma Case No. CIV-97-1010-L. On
June 15, 1999, the Company was served with Plaintiff's Complaint. Plaintiff's
action is a qui tam action under the False Claims Act. Plaintiff, Jack J.
Grynberg, as individual Relator on behalf of the United States Government,
alleges: (1) each of the named Defendants have improperly and intentionally
mismeasured gas (both volume and BTU content) purchased from federal and Indian
lands which have resulted in the under-reporting and underpayment of gas
royalties owed to the Federal Government; (2) certain provisions generally found
in gas purchase contracts are improper; (3) transactions by affiliated companies
are not arms-length; (4) excess processing cost deduction; and (5) failure to
account for production separated out as a result of gas processing. Grynberg
seeks the following damages: (a) additional royalties which he claims should
have been paid to the Federal Government, some percentage of which Grynberg, as
Relator, may be entitled to recover; (b) treble damages; (c) civil penalties;
(d) an order requiring Defendants to measure gas the way Grynberg contends is
the better way to do so; and (e) interest costs and attorneys' fees. Plaintiff
has filed over 70 other cases naming over 300 other defendants in various
Federal Courts across the country containing nearly identical allegations.
In qui tam actions, the United States government can intervene and take
over such actions from the Relator. The Department of Justice, on behalf of the
United States government, has decided not to intervene in this action or any of
the other "Grynberg qui tam actions."
There are currently pending before the court various motions filed by the
parties. At this time, the Company cannot predict the ultimate outcome of this
proceeding, but the Company does not believe this matter will have a material
adverse impact on the Company's financial position or results of operations.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareowners was held on May 27, 1999.
(b) Not applicable.
(c) The matters voted upon and the results of the voting at the
Annual Meeting
12
<PAGE>
were as follows:
(1) The Shareowners voted to elect the Company's nominees for
election to the Board of Directors as follows:
Herbert H. Champlin - 40,378,745 votes for election and
no votes withheld
Martha W. Griffin - 40,378,745 votes for election and
no votes withheld
Ronald H. White - 40,378,745 votes for election and
no votes withheld
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K
None
13
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/ Donald R. Rowlett
------------------------------------------
Donald R. Rowlett
Controller Corporate Accounting
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
August 13, 1999
14
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
27.01 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the Oklahoma
Gas and Electric Company Statements of Income, Balance Sheets, and Statements of
Cash Flows as reported on Form 10-Q as of June 30, 1999 and is qualified in its
entirety by reference to such Form 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> JUN-30-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,974,400
<OTHER-PROPERTY-AND-INVEST> 19,637
<TOTAL-CURRENT-ASSETS> 272,132
<TOTAL-DEFERRED-CHARGES> 92,934
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,359,103
<COMMON> 100,947
<CAPITAL-SURPLUS-PAID-IN> 411,499
<RETAINED-EARNINGS> 333,306
<TOTAL-COMMON-STOCKHOLDERS-EQ> 845,752
0
0
<LONG-TERM-DEBT-NET> 702,979
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 1,267
<LEASES-CURRENT> 2,076
<OTHER-ITEMS-CAPITAL-AND-LIAB> 807,029
<TOT-CAPITALIZATION-AND-LIAB> 2,359,103
<GROSS-OPERATING-REVENUE> 564,246
<INCOME-TAX-EXPENSE> 21,449
<OTHER-OPERATING-EXPENSES> 476,250
<TOTAL-OPERATING-EXPENSES> 476,250
<OPERATING-INCOME-LOSS> 87,996
<OTHER-INCOME-NET> 466
<INCOME-BEFORE-INTEREST-EXPEN> 88,462
<TOTAL-INTEREST-EXPENSE> 23,095
<NET-INCOME> 43,918
0
<EARNINGS-AVAILABLE-FOR-COMM> 43,918
<COMMON-STOCK-DIVIDENDS> 51,738
<TOTAL-INTEREST-ON-BONDS> 22,246
<CASH-FLOW-OPERATIONS> 48,476
<EPS-BASIC> 1.09
<EPS-DILUTED> 1.09
</TABLE>
