UNITED STATES
|
SECURITIES AND EXCHANGE COMMISSION
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Washington, D.C. 20549
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FORM 10-Q
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OR
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Commission File Number: 1-12579
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OGE ENERGY CORP.
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(Exact name of registrant as specified in its charter)
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Oklahoma
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73-1481638
|
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(State or other jurisdiction of
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(I.R.S. Employer
|
|
incorporation or organization)
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Identification No.)
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321 North Harvey
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P.O. Box 321
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Oklahoma City, Oklahoma 73101-0321
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(Address of principal executive offices)
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(Zip Code)
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405-553-3000
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(Registrant’s telephone number, including area code)
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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 þ No o
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o (Do not check if a smaller reporting company)
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Smaller reporting company o
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
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At June 30, 2010, there were 97,372,989 shares of common stock, par value $0.01 per share, outstanding.
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Page
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||
1
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||
Item 1. Financial Statements (Unaudited)
|
||
Condensed Consolidated Statements of Income
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2
|
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Condensed Consolidated Statements of Cash Flows
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3
|
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Condensed Consolidated Balance Sheets
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4
|
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Condensed Consolidated Statements of Changes in Stockholders’ Equity
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6
|
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Notes to Condensed Consolidated Financial Statements
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8
|
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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35
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
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61
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Item 4. Controls and Procedures
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62
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Item 1. Legal Proceedings
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62
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Item 1A. Risk Factors
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64
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
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64
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Item 6. Exhibits
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65
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66
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||
Ÿ
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general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;
|
Ÿ
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the ability of OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) and its subsidiaries to access the capital markets and obtain financing on favorable terms;
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Ÿ
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prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;
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Ÿ
|
business conditions in the energy and natural gas midstream industries;
|
Ÿ
|
competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;
|
Ÿ
|
unusual weather;
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Ÿ
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availability and prices of raw materials for current and future construction projects;
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Ÿ
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Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;
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Ÿ
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environmental laws and regulations that may impact the Company’s operations;
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Ÿ
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changes in accounting standards, rules or guidelines;
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Ÿ
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the discontinuance of accounting principles for certain types of rate-regulated activities;
|
Ÿ
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creditworthiness of suppliers, customers and other contractual parties;
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Ÿ
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the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and
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Ÿ
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other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2009 Form 10-K.
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OGE ENERGY CORP.
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||||||||||||
(Unaudited)
|
||||||||||||
Three Months Ended
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Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
(In millions, except per share data)
|
2010
|
2009
|
2010
|
2009
|
||||||||
OPERATING REVENUES
|
||||||||||||
Electric Utility operating revenues
|
$
|
512.8
|
$
|
425.3
|
$
|
956.8
|
$
|
762.0
|
||||
Natural Gas Pipeline operating revenues
|
374.4
|
218.8
|
806.2
|
488.7
|
||||||||
Total operating revenues
|
887.2
|
644.1
|
1,763.0
|
1,250.7
|
||||||||
COST OF GOODS SOLD (exclusive of depreciation and amortization
|
||||||||||||
shown below)
|
||||||||||||
Electric Utility cost of goods sold
|
218.9
|
176.4
|
457.8
|
335.5
|
||||||||
Natural Gas Pipeline cost of goods sold
|
287.6
|
147.8
|
618.8
|
341.9
|
||||||||
Total cost of goods sold
|
506.5
|
324.2
|
1,076.6
|
677.4
|
||||||||
Gross margin on revenues
|
380.7
|
319.9
|
686.4
|
573.3
|
||||||||
Other operation and maintenance
|
135.0
|
105.6
|
258.6
|
222.1
|
||||||||
Depreciation and amortization
|
71.2
|
64.6
|
141.5
|
127.2
|
||||||||
Impairment of assets
|
---
|
1.4
|
---
|
1.4
|
||||||||
Taxes other than income
|
23.0
|
21.9
|
48.0
|
44.2
|
||||||||
OPERATING INCOME
|
151.5
|
126.4
|
238.3
|
178.4
|
||||||||
OTHER INCOME (EXPENSE)
|
||||||||||||
Loss in earnings of unconsolidated affiliate
|
(1.3)
|
---
|
(1.3)
|
---
|
||||||||
Interest income
|
---
|
0.4
|
---
|
1.1
|
||||||||
Allowance for equity funds used during construction
|
2.3
|
3.9
|
4.6
|
5.2
|
||||||||
Other income
|
3.4
|
6.5
|
6.5
|
13.0
|
||||||||
Other expense
|
(3.7)
|
(2.7)
|
(6.1)
|
(5.0)
|
||||||||
Net other income
|
0.7
|
8.1
|
3.7
|
14.3
|
||||||||
INTEREST EXPENSE
|
||||||||||||
Interest on long-term debt
|
33.4
|
31.9
|
67.0
|
63.3
|
||||||||
Allowance for borrowed funds used during construction
|
(1.0)
|
(1.9)
|
(2.2)
|
(3.0)
|
||||||||
Interest on short-term debt and other interest charges
|
1.6
|
1.7
|
3.3
|
4.1
|
||||||||
Interest expense
|
34.0
|
31.7
|
68.1
|
64.4
|
||||||||
INCOME BEFORE TAXES
|
118.2
|
102.8
|
173.9
|
128.3
|
||||||||
INCOME TAX EXPENSE
|
40.3
|
31.9
|
70.8
|
39.8
|
||||||||
NET INCOME
|
77.9
|
70.9
|
103.1
|
88.5
|
||||||||
Less: Net income attributable to noncontrolling interest
|
0.6
|
0.4
|
1.6
|
1.2
|
||||||||
NET INCOME ATTRIBUTABLE TO OGE ENERGY
|
$
|
77.3
|
$
|
70.5
|
$
|
101.5
|
$
|
87.3
|
||||
BASIC AVERAGE COMMON SHARES OUTSTANDING
|
97.3
|
96.5
|
97.2
|
95.6
|
||||||||
DILUTED AVERAGE COMMON SHARES OUTSTANDING
|
98.7
|
97.5
|
98.6
|
96.4
|
||||||||
BASIC EARNINGS PER AVERAGE COMMON SHARE
|
||||||||||||
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
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$
|
0.79
|
$
|
0.73
|
$
|
1.04
|
$
|
0.91
|
||||
DILUTED EARNINGS PER AVERAGE COMMON SHARE
|
||||||||||||
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS
|
$
|
0.78
|
$
|
0.72
|
$
|
1.03
|
$
|
0.91
|
||||
DIVIDENDS DECLARED PER SHARE
|
$
|
0.3625
|
$
|
0.3550
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$
|
0.7250
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$
|
0.7100
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
|
|||||||
(Unaudited)
|
|||||||
Six Months Ended
|
|||||||
June 30,
|
|||||||
(In millions)
|
2010
|
2009
|
|||||
CASH FLOWS FROM OPERATING ACTIVITIES
|
|||||||
Net income
|
$
|
103.1
|
$
|
88.5
|
|||
Adjustments to reconcile net income to net cash provided from
|
|||||||
operating activities
|
|||||||
Loss in earnings of unconsolidated affiliate
|
1.3
|
---
|
|||||
Depreciation and amortization
|
141.5
|
127.2
|
|||||
Impairment of assets
|
---
|
1.4
|
|||||
Deferred income taxes and investment tax credits, net
|
52.2
|
52.9
|
|||||
Allowance for equity funds used during construction
|
(4.6)
|
(5.2)
|
|||||
Loss on disposition and abandonment of assets
|
0.9
|
0.3
|
|||||
Stock-based compensation expense
|
3.9
|
2.8
|
|||||
Stock-based compensation converted to cash for tax withholding
|
(1.6)
|
(1.7)
|
|||||
Price risk management assets
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(4.4)
|
6.1
|
|||||
Price risk management liabilities
|
11.4
|
(63.0)
|
|||||
Other assets
|
11.7
|
4.9
|
|||||
Other liabilities
|
(40.7)
|
(39.2)
|
|||||
Change in certain current assets and liabilities
|
|||||||
Accounts receivable, net
|
(24.1)
|
33.1
|
|||||
Accrued unbilled revenues
|
(24.4)
|
(26.6)
|
|||||
Income taxes receivable
|
150.6
|
(27.3)
|
|||||
Fuel, materials and supplies inventories
|
(28.5)
|
(34.4)
|
|||||
Gas imbalance assets
|
(1.8)
|
3.9
|
|||||
Fuel clause under recoveries
|
(0.6)
|
23.9
|
|||||
Other current assets
|
8.9
|
(0.5)
|
|||||
Accounts payable
|
4.8
|
(74.3)
|
|||||
Customer deposits
|
18.3
|
2.6
|
|||||
Accrued taxes
|
20.4
|
16.4
|
|||||
Accrued interest
|
(7.8)
|
10.6
|
|||||
Accrued compensation
|
(3.6)
|
(3.5)
|
|||||
Gas imbalance liabilities
|
(4.2)
|
(13.2)
|
|||||
Fuel clause over recoveries
|
(50.1)
|
118.8
|
|||||
Other current liabilities
|
8.9
|
(17.6)
|
|||||
Net Cash Provided from Operating Activities
|
341.5
|
186.9
|
|||||
CASH FLOWS FROM INVESTING ACTIVITIES
|
|||||||
Capital expenditures (less allowance for equity funds used during
|
|||||||
construction)
|
(296.6)
|
(491.2)
|
|||||
Construction reimbursement
|
3.3
|
17.6
|
|||||
Proceeds from sale of assets
|
1.6
|
0.7
|
|||||
Other investing activities
|
0.1
|
---
|
|||||
Net Cash Used in Investing Activities
|
(291.6)
|
(472.9)
|
|||||
CASH FLOWS FROM FINANCING ACTIVITIES
|
|||||||
Retirement of long-term debt
|
(289.2)
|
---
|
|||||
Dividends paid on common stock
|
(70.4)
|
(67.5)
|
|||||
(Decrease) increase in short-term debt
|
(62.1)
|
84.2
|
|||||
Repayment of line of credit
|
(50.0)
|
(40.0)
|
|||||
Issuance of common stock
|
9.8
|
68.7
|
|||||
Proceeds from line of credit
|
115.0
|
80.0
|
|||||
Proceeds from long-term debt
|
246.2
|
198.4
|
|||||
Net Cash (Used in) Provided from Financing Activities
|
(100.7)
|
323.8
|
|||||
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
|
(50.8)
|
37.8
|
|||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
|
58.1
|
174.4
|
|||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD
|
$
|
7.3
|
$
|
212.2
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
|
OGE ENERGY CORP.
|
|||||||
June 30,
|
December 31,
|
||||||
2010
|
2009
|
||||||
(In millions)
|
(Unaudited)
|
||||||
ASSETS
|
|||||||
CURRENT ASSETS
|
|||||||
Cash and cash equivalents
|
$
|
7.3
|
$
|
58.1
|
|||
Accounts receivable, less reserve of $1.7 and $2.4, respectively
|
315.5
|
291.4
|
|||||
Accrued unbilled revenues
|
81.6
|
57.2
|
|||||
Income taxes receivable
|
7.1
|
157.7
|
|||||
Fuel inventories
|
140.5
|
118.5
|
|||||
Materials and supplies, at average cost
|
84.9
|
78.4
|
|||||
Price risk management
|
8.0
|
1.8
|
|||||
Gas imbalances
|
5.0
|
3.2
|
|||||
Accumulated deferred tax assets
|
37.0
|
39.8
|
|||||
Fuel clause under recoveries
|
0.9
|
0.3
|
|||||
Prepayments
|
6.4
|
8.7
|
|||||
Other
|
3.4
|
11.0
|
|||||
Total current assets
|
697.6
|
826.1
|
|||||
OTHER PROPERTY AND INVESTMENTS, at cost
|
41.6
|
43.7
|
|||||
PROPERTY, PLANT AND EQUIPMENT
|
|||||||
In service
|
8,925.8
|
8,617.8
|
|||||
Construction work in progress
|
250.5
|
335.4
|
|||||
Total property, plant and equipment
|
9,176.3
|
8,953.2
|
|||||
Less accumulated depreciation
|
3,119.4
|
3,041.6
|
|||||
Net property, plant and equipment
|
6,056.9
|
5,911.6
|
|||||
DEFERRED CHARGES AND OTHER ASSETS
|
|||||||
Income taxes recoverable from customers, net
|
39.8
|
19.1
|
|||||
Benefit obligations regulatory asset
|
341.3
|
357.8
|
|||||
Price risk management
|
2.5
|
4.3
|
|||||
Unamortized loss on reacquired debt
|
16.0
|
16.5
|
|||||
Unamortized debt issuance costs
|
16.7
|
15.3
|
|||||
Other
|
81.7
|
72.3
|
|||||
Total deferred charges and other assets
|
498.0
|
485.3
|
|||||
TOTAL ASSETS
|
$
|
7,294.1
|
$
|
7,266.7
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
|
OGE ENERGY CORP.
|
||||||
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
|
||||||
June 30,
|
December 31,
|
|||||
2010
|
2009
|
|||||
(In millions)
|
(Unaudited)
|
|||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
||||||
CURRENT LIABILITIES
|
||||||
Short-term debt
|
$
|
112.9
|
$
|
175.0
|
||
Accounts payable
|
277.2
|
297.0
|
||||
Dividends payable
|
35.3
|
35.1
|
||||
Customer deposits
|
93.5
|
85.6
|
||||
Accrued taxes
|
55.8
|
37.0
|
||||
Accrued interest
|
52.8
|
60.6
|
||||
Accrued compensation
|
46.5
|
50.1
|
||||
Long-term debt due within one year
|
---
|
289.2
|
||||
Price risk management
|
9.6
|
14.2
|
||||
Gas imbalances
|
7.8
|
12.0
|
||||
Fuel clause over recoveries
|
137.4
|
187.5
|
||||
Other
|
41.3
|
32.4
|
||||
Total current liabilities
|
870.1
|
1,275.7
|
||||
LONG-TERM DEBT
|
2,402.6
|
2,088.9
|
||||
DEFERRED CREDITS AND OTHER LIABILITIES
|
||||||
Accrued benefit obligations
|
337.5
|
369.3
|
||||
Accumulated deferred income taxes
|
1,321.1
|
1,246.6
|
||||
Accumulated deferred investment tax credits
|
11.3
|
13.1
|
||||
Accrued removal obligations, net
|
175.5
|
168.2
|
||||
Price risk management
|
---
|
0.1
|
||||
Other
|
56.3
|
44.0
|
||||
Total deferred credits and other liabilities
|
1,901.7
|
1,841.3
|
||||
Total liabilities
|
5,174.4
|
5,205.9
|
||||
COMMITMENTS AND CONTINGENCIES (NOTE 12)
|
||||||
STOCKHOLDERS’ EQUITY
|
||||||
Common stockholders’ equity
|
902.3
|
887.7
|
||||
Retained earnings
|
1,258.7
|
1,227.8
|
||||
Accumulated other comprehensive loss, net of tax
|
(62.9)
|
(74.7)
|
||||
Total OGE Energy stockholders’ equity
|
2,098.1
|
2,040.8
|
||||
Noncontrolling interest
|
21.6
|
20.0
|
||||
Total stockholders’ equity
|
2,119.7
|
2,060.8
|
||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
|
$
|
7,294.1
|
$
|
7,266.7
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
|
OGE ENERGY CORP.
|
||||||
(Unaudited)
|
||||||
Premium
|
Accumulated
|
|||||
on
|
Other
|
|||||
Common
|
Capital
|
Retained
|
Comprehensive
|
Noncontrolling
|
||
(In millions)
|
Stock
|
Stock
|
Earnings
|
Income (Loss)
|
Interest
|
Total
|
Balance at December 31, 2009
|
$ 1.0
|
$ 886.7
|
$ 1,227.8
|
$ (74.7)
|
$ 20.0
|
$ 2,060.8
|
Comprehensive income (loss)
|
||||||
Net income for first quarter of 2010
|
---
|
---
|
24.2
|
---
|
1.0
|
25.2
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Amortization of deferred net loss, net of tax ($1.2
pre-tax)
|
---
|
---
|
---
|
0.5
|
---
|
0.5
|
Defined benefit postretirement plans:
|
||||||
Amortization of deferred net loss, net of tax ($1.0
pre-tax)
|
---
|
---
|
---
|
0.6
|
---
|
0.6
|
Amortization of deferred net transition obligation,
net of tax ($0.2 pre-tax)
|
---
|
---
|
---
|
0.2
|
---
|
0.2
|
Amortization of prior service cost, net of tax (($0.2)
pre-tax)
|
---
|
---
|
---
|
(0.2)
|
---
|
(0.2)
|
Deferred commodity contracts hedging losses, net of tax
|
||||||
(($4.3) pre-tax)
|
---
|
---
|
---
|
(2.7)
|
---
|
(2.7)
|
Amortization of cash flow hedge, net of tax ($0.1
pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Other comprehensive loss
|
---
|
---
|
---
|
(1.5)
|
---
|
(1.5)
|
Comprehensive income (loss)
|
---
|
---
|
24.2
|
(1.5)
|
1.0
|
23.7
|
Dividends declared on common stock
|
---
|
---
|
(35.3)
|
---
|
---
|
(35.3)
|
Issuance of common stock
|
---
|
6.5
|
---
|
---
|
---
|
6.5
|
Balance at March 31, 2010
|
$ 1.0
|
$ 893.2
|
$ 1,216.7
|
$ (76.2)
|
$ 21.0
|
$ 2,055.7
|
Comprehensive income
|
||||||
Net income for second quarter of 2010
|
---
|
---
|
77.3
|
---
|
0.6
|
77.9
|
Other comprehensive income, net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Amortization of deferred net loss, net of tax ($0.8
pre-tax)
|
---
|
---
|
---
|
0.5
|
---
|
0.5
|
Amortization of prior service cost, net of tax ($0.1
pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Defined benefit postretirement plans:
|
||||||
Amortization of deferred net loss, net of tax ($0.5
pre-tax)
|
---
|
---
|
---
|
0.3
|
---
|
0.3
|
Amortization of deferred net transition obligation,
net of tax ($0.2 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Deferred commodity contracts hedging gains, net of tax
|
||||||
($20.1 pre-tax)
|
---
|
---
|
---
|
12.3
|
---
|
12.3
|
Other comprehensive income
|
---
|
---
|
---
|
13.3
|
---
|
13.3
|
Comprehensive income
|
---
|
---
|
77.3
|
13.3
|
0.6
|
91.2
|
Dividends declared on common stock
|
---
|
---
|
(35.3)
|
---
|
---
|
(35.3)
|
Issuance of common stock
|
---
|
8.1
|
---
|
---
|
---
|
8.1
|
Balance at June 30, 2010
|
$ 1.0
|
$ 901.3
|
$ 1,258.7
|
$ (62.9)
|
$ 21.6
|
$ 2,119.7
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
|
OGE ENERGY CORP.
|
||||||
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (CONTINUED)
|
||||||
(Unaudited)
|
||||||
Premium
|
Accumulated
|
|||||
on
|
Other
|
|||||
Common
|
Capital
|
Retained
|
Comprehensive
|
Noncontrolling
|
||
(In millions)
|
Stock
|
Stock
|
Earnings
|
Income (Loss)
|
Interest
|
Total
|
Balance at December 31, 2008
|
$ 0.9
|
$ 802.0
|
$ 1,107.6
|
$ (13.7)
|
$ 17.2
|
$ 1,914.0
|
Comprehensive income (loss)
|
||||||
Net income for first quarter of 2009
|
---
|
---
|
16.8
|
---
|
0.8
|
17.6
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Amortization of deferred net loss, net of tax ($1.3
pre-tax)
|
---
|
---
|
---
|
0.8
|
---
|
0.8
|
Defined benefit postretirement plans:
|
||||||
Amortization of deferred net loss, net of tax ($0.2
pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Deferred commodity contracts hedging losses, net of tax
|
||||||
(($46.2) pre-tax)
|
---
|
---
|
---
|
(28.3)
|
---
|
(28.3)
|
Amortization of cash flow hedge, net of tax ($0.2 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Other comprehensive loss
|
---
|
---
|
---
|
(27.3)
|
---
|
(27.3)
|
Comprehensive income (loss)
|
---
|
---
|
16.8
|
(27.3)
|
0.8
|
(9.7)
|
Dividends declared on common stock
|
---
|
---
|
(34.2)
|
---
|
---
|
(34.2)
|
Issuance of common stock
|
0.1
|
55.7
|
---
|
---
|
---
|
55.8
|
Balance at March 31, 2009
|
$ 1.0
|
$ 857.7
|
$ 1,090.2
|
$ (41.0)
|
$ 18.0
|
$ 1,925.9
|
Comprehensive income (loss)
|
||||||
Net income for second quarter of 2009
|
---
|
---
|
70.5
|
---
|
0.4
|
70.9
|
Other comprehensive income (loss), net of tax
|
||||||
Defined benefit pension plan and restoration of
|
||||||
retirement income plan:
|
||||||
Amortization of deferred net loss, net of tax ($1.3
|
||||||
pre-tax)
|
---
|
---
|
---
|
0.7
|
---
|
0.7
|
Amortization of prior service cost, net of tax
|
||||||
($0.1 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Defined benefit postretirement plans:
|
||||||
Amortization of prior service cost, net of tax
|
||||||
($0.1 pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Deferred commodity contracts hedging losses, net of tax
|
||||||
(($32.4) pre-tax)
|
---
|
---
|
---
|
(19.8)
|
---
|
(19.8)
|
Amortization of cash flow hedge, net of tax ($0.1
pre-tax)
|
---
|
---
|
---
|
0.1
|
---
|
0.1
|
Other comprehensive loss
|
---
|
---
|
---
|
(18.8)
|
---
|
(18.8)
|
Comprehensive income (loss)
|
---
|
---
|
70.5
|
(18.8)
|
0.4
|
52.1
|
Dividends declared on common stock
|
---
|
---
|
(34.4)
|
---
|
---
|
(34.4)
|
Issuance of common stock
|
---
|
14.1
|
---
|
---
|
---
|
14.1
|
Balance at June 30, 2009
|
$ 1.0
|
$ 871.8
|
$ 1,126.3
|
$ (59.8)
|
$ 18.4
|
$ 1,957.7
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
|
June 30,
|
December 31,
|
|||||
(In millions)
|
2010
|
2009
|
||||
Regulatory Assets
|
||||||
Benefit obligations regulatory asset
|
$
|
341.3
|
$
|
357.8
|
||
Income taxes recoverable from customers, net
|
39.8
|
19.1
|
||||
Deferred storm expenses
|
32.3
|
28.0
|
||||
Unamortized loss on reacquired debt
|
16.0
|
16.5
|
||||
Deferred pension plan expenses
|
15.8
|
18.1
|
||||
Smart Grid
|
7.7
|
---
|
||||
Red Rock deferred expenses
|
7.5
|
7.7
|
||||
Fuel clause under recoveries
|
0.9
|
0.3
|
||||
Miscellaneous
|
3.0
|
3.9
|
||||
Total Regulatory Assets
|
$
|
464.3
|
$
|
451.4
|
||
Regulatory Liabilities
|
||||||
Accrued removal obligations, net
|
$
|
175.5
|
$
|
168.2
|
||
Fuel clause over recoveries
|
137.4
|
187.5
|
||||
Miscellaneous
|
10.2
|
7.3
|
||||
Total Regulatory Liabilities
|
$
|
323.1
|
$
|
363.0
|
June 30, 2010
|
||||||||||||||||||||||
(In millions)
|
Quoted
Market
Prices in
Active
Market for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Total Fair
Value
|
Master
Netting
Agreement
Adjustments
|
Amounts Held
in Clearing
Broker
Accounts
Reflected in
Other Current
Assets
|
Balance
Sheet
Presentation
|
|||||||||||||||
Assets
|
||||||||||||||||||||||
Commodity
contracts
|
$
|
14.3
|
$
|
6.4
|
$
|
42.1
|
$
|
62.8
|
$
|
(36.6)
|
$
|
(15.7)
|
$
|
10.5
|
||||||||
Gas imbalance
assets (A)
|
---
|
5.0
|
---
|
5.0
|
---
|
---
|
5.0
|
|||||||||||||||
Total
|
$
|
14.3
|
$
|
11.4
|
$
|
42.1
|
$
|
67.8
|
$
|
(36.6)
|
$
|
(15.7)
|
$
|
15.5
|
||||||||
Liabilities
|
||||||||||||||||||||||
Commodity
contracts
|
$
|
13.7
|
$
|
45.8
|
$
|
1.8
|
$
|
61.3
|
$
|
(36.6)
|
$
|
(15.1)
|
$
|
9.6
|
||||||||
Gas imbalance
liabilities (A)(B)
|
---
|
3.0
|
---
|
3.0
|
---
|
---
|
3.0
|
|||||||||||||||
Total
|
$
|
13.7
|
$
|
48.8
|
$
|
1.8
|
$
|
64.3
|
$
|
(36.6)
|
$
|
(15.1)
|
$
|
12.6
|
December 31, 2009
|
||||||||||||||||||||||
(In millions)
|
Quoted
Market
Prices in
Active
Market for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
Total Fair
Value
|
Master
Netting
Agreement
Adjustments
|
Amounts Held
in Clearing
Broker
Accounts
Reflected in
Other Current
Assets
|
Balance
Sheet
Presentation
|
|||||||||||||||
Assets
|
||||||||||||||||||||||
Commodity
contracts
|
$
|
16.1
|
$
|
6.2
|
$
|
49.0
|
$
|
71.3
|
$
|
(47.9)
|
$
|
(17.3)
|
$
|
6.1
|
||||||||
Gas imbalance
assets (C)
|
---
|
3.2
|
---
|
3.2
|
---
|
---
|
3.2
|
|||||||||||||||
Total
|
$
|
16.1
|
$
|
9.4
|
$
|
49.0
|
$
|
74.5
|
$
|
(47.9)
|
$
|
(17.3)
|
$
|
9.3
|
||||||||
Liabilities
|
||||||||||||||||||||||
Commodity
contracts
|
$
|
13.3
|
$
|
49.8
|
$
|
14.7
|
$
|
77.8
|
$
|
(47.9)
|
$
|
(15.6)
|
$
|
14.3
|
||||||||
Gas imbalance
liabilities (C)(D)
|
---
|
8.0
|
---
|
8.0
|
---
|
---
|
8.0
|
|||||||||||||||
Total
|
$
|
13.3
|
$
|
57.8
|
$
|
14.7
|
$
|
85.8
|
$
|
(47.9)
|
$
|
(15.6)
|
$
|
22.3
|
Assets
|
Commodity Contracts
|
|||||
(In millions)
|
2010
|
2009
|
||||
Balance at January 1
|
$
|
49.0
|
$
|
121.2
|
||
Total gains or losses
|
||||||
Included in other comprehensive income
|
(3.9)
|
(11.1)
|
||||
Purchases, issuances, sales and settlements
|
||||||
Settlements
|
(4.1)
|
(4.5)
|
||||
Balance at March 31
|
$
|
41.0
|
$
|
105.6
|
||
Total gains or losses
|
||||||
Included in other comprehensive income
|
7.2
|
(34.4)
|
||||
Purchases, issuances, sales and settlements
|
||||||
Settlements
|
(6.1)
|
(3.9)
|
||||
Balance at June 30
|
$
|
42.1
|
$
|
67.3
|
||
The amount of total gains or losses for the period included in earnings attributable
|
||||||
to the change in unrealized gains or losses relating to assets held at June 30
|
$
|
---
|
$
|
---
|
Liabilities
|
Commodity Contracts
|
|||||
(In millions)
|
2010
|
2009
|
||||
Balance at January 1
|
$
|
14.7
|
$
|
---
|
||
Total gains or losses
|
||||||
Included in other comprehensive income
|
(5.1)
|
---
|
||||
Purchases, issuances, sales and settlements
|
||||||
Settlements
|
(1.4)
|
---
|
||||
Balance at March 31
|
$
|
8.2
|
$
|
---
|
||
Total gains or losses
|
||||||
Included in other comprehensive income
|
(3.7)
|
---
|
||||
Purchases, issuances, sales and settlements
|
||||||
Purchases
|
---
|
1.8
|
||||
Settlements
|
(2.7)
|
---
|
||||
Balance at June 30
|
$
|
1.8
|
$
|
1.8
|
||
The amount of total gains or losses for the period included in earnings attributable
|
||||||
to the change in unrealized gains or losses relating to liabilities held at June 30
|
$
|
---
|
$
|
---
|
June 30, 2010
|
December 31, 2009
|
|||||||||||||||||
Carrying
|
Fair
|
Carrying
|
Fair
|
|||||||||||||||
(In millions)
|
Amount
|
Value
|
Amount
|
Value
|
||||||||||||||
Price Risk Management Assets
|
||||||||||||||||||
Energy Derivative Contracts
|
$
|
10.5
|
$
|
10.5
|
$
|
6.1
|
$
|
6.1
|
||||||||||
Price Risk Management Liabilities
|
||||||||||||||||||
Energy Derivative Contracts
|
$
|
9.6
|
$
|
9.6
|
$
|
14.3
|
$
|
14.3
|
||||||||||
Long-Term Debt
|
||||||||||||||||||
OG&E Senior Notes
|
$
|
1,654.9
|
$
|
1,872.6
|
$
|
1,406.4
|
$
|
1,492.1
|
||||||||||
OGE Energy Senior Notes
|
99.6
|
107.4
|
99.5
|
102.6
|
||||||||||||||
OG&E Industrial Authority Bonds
|
135.4
|
135.4
|
135.4
|
135.4
|
||||||||||||||
Enogex Senior Notes
|
447.7
|
484.9
|
736.8
|
746.7
|
||||||||||||||
Enogex Revolving Credit Agreement
|
65.0
|
65.0
|
---
|
---
|
Ÿ
|
natural gas liquids (“NGL”) put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;
|
Ÿ
|
natural gas swaps are used to manage Enogex’s keep-whole natural gas exposure associated with its processing operations and Enogex’s natural gas exposure associated with operating its gathering, transportation and storage assets;
|
Ÿ
|
natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OGE Energy’s natural gas marketing subsidiary, OGE Energy Resources, Inc.’s (“OERI”), natural gas exposure associated with its storage and transportation contracts; and
|
Ÿ
|
natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OERI’s marketing and trading activities.
|
Gross Notional
|
|||||
Commodity
|
Volume (A)
|
Maturity
|
|||
(In millions)
|
|||||
Short Financial Swaps/Futures (fixed)
|
NGLs
|
0.3
|
Current
|
||
Purchased Financial Options
|
NGLs
|
1.3
|
Current
|
||
Purchased Financial Options
|
NGLs
|
0.7
|
Non-Current
|
||
Total Purchased Financial Options
|
2.0
|
||||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
5.7
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
2.6
|
Non-Current
|
||
Total Long Financial Swaps/Futures (fixed)
|
8.3
|
||||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
0.9
|
Current
|
||
Short Financial Basis Swaps
|
Natural Gas
|
0.9
|
Current
|
Gross Notional
|
|||||
Commodity
|
Volume (A)
|
Maturity
|
|||
(In millions)
|
|||||
Short Financial Swaps/Futures (fixed)
|
NGLs
|
0.4
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
NGLs
|
0.4
|
Current
|
||
Physical Purchases (B)
|
Natural Gas
|
16.6
|
Current
|
||
Physical Purchases (B)
|
Natural Gas
|
5.8
|
Non-Current
|
||
Total Physical Purchases
|
22.4
|
||||
Physical Sales (B)
|
Natural Gas
|
30.1
|
Current
|
||
Physical Sales (B)
|
Natural Gas
|
16.8
|
Non-Current
|
||
Total Physical Sales
|
46.9
|
||||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
34.7
|
Current
|
||
Long Financial Swaps/Futures (fixed)
|
Natural Gas
|
1.5
|
Non-Current
|
||
Total Long Financial Swaps/Futures (fixed)
|
36.2
|
||||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
35.2
|
Current
|
||
Short Financial Swaps/Futures (fixed)
|
Natural Gas
|
3.0
|
Non-Current
|
||
Total Short Financial Swaps/Futures (fixed)
|
38.2
|
||||
Purchased Financial Option
|
Natural Gas
|
20.1
|
Current
|
||
Sold Financial Option
|
Natural Gas
|
18.8
|
Current
|
||
Long Financial Basis Swaps
|
Natural Gas
|
11.1
|
Current
|
||
Long Financial Basis Swaps
|
Natural Gas
|
1.5
|
Non-Current
|
||
Total Long Financial Basis Swaps
|
12.6
|
||||
Short Financial Basis Swaps
|
Natural Gas
|
9.8
|
Current
|
||
Short Financial Basis Swaps
|
Natural Gas
|
1.5
|
Non-Current
|
||
Total Short Financial Basis Swaps
|
11.3
|
||||
(A) Natural gas in MMBtu; NGLs in barrels.
|
|||||
(B) Of the natural gas physical purchases and sales volumes not designated as cash flow or fair value hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.
|
Fair Value
|
|||||||||||||||||
Balance Sheet
|
|||||||||||||||||
Instrument
|
Commodity
|
Location
|
Assets
|
Liabilities
|
|||||||||||||
(In millions)
|
|||||||||||||||||
Derivatives Designated as Hedging Instruments
|
|||||||||||||||||
Financial Options
|
NGLs
|
Current PRM
|
$
|
26.2
|
$
|
---
|
|||||||||||
Non-Current PRM
|
14.4
|
---
|
|||||||||||||||
Financial Futures/Swaps
|
NGLs
|
Current PRM
|
0.1
|
0.7
|
|||||||||||||
Financial Futures/Swaps
|
Natural Gas
|
Current PRM
|
---
|
23.5
|
|||||||||||||
Non-Current PRM
|
---
|
12.2
|
|||||||||||||||
Other Current Assets
|
3.1
|
0.1
|
|||||||||||||||
Total Gross Derivatives Designated as Hedging Instruments
|
$
|
43.8
|
$
|
36.5
|
|||||||||||||
Derivatives Not Designated as Hedging Instruments
|
|||||||||||||||||
Financial Futures/Swaps (A)
|
NGLs
|
Current PRM
|
$
|
1.4
|
$
|
1.1
|
|||||||||||
Financial Futures/Swaps (B)
|
Natural Gas
|
Current PRM
|
3.0
|
7.2
|
|||||||||||||
Other Current Assets
|
11.5
|
14.0
|
|||||||||||||||
Physical Purchases/Sales
|
Natural Gas
|
Current PRM
|
1.7
|
1.5
|
|||||||||||||
Non-Current PRM
|
0.3
|
---
|
|||||||||||||||
Financial Options
|
Natural Gas
|
Other Current Assets
|
1.1
|
1.0
|
|||||||||||||
Total Gross Derivatives Not Designated as Hedging Instruments
|
$
|
19.0
|
$
|
24.8
|
|||||||||||||
Total Gross Derivatives (C)
|
$
|
62.8
|
$
|
61.3
|
(A)
|
The fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $1.4 million and Current Liabilities of approximately $1.1 million.
|
(B)
|
The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $2.1 million and Current Liabilities of approximately $6.8 million.
|
(C)
|
See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at June 30, 2010 (see Note 2).
|
Fair Value
|
|||||||||||||||||
Balance Sheet
|
|||||||||||||||||
Instrument
|
Commodity
|
Location
|
Assets
|
Liabilities
|
|||||||||||||
(In millions)
|
|||||||||||||||||
Derivatives Designated as Hedging Instruments
|
|||||||||||||||||
Financial Options
|
NGLs
|
Current PRM
|
$
|
16.4
|
$
|
---
|
|||||||||||
Non-Current PRM
|
23.4
|
---
|
|||||||||||||||
Financial Futures/Swaps
|
NGLs
|
Current PRM
|
---
|
6.1
|
|||||||||||||
Financial Futures/Swaps
|
Natural Gas
|
Current PRM
|
---
|
14.8
|
|||||||||||||
Non-Current PRM
|
---
|
19.7
|
|||||||||||||||
Other Current Assets
|
4.6
|
1.2
|
|||||||||||||||
Total Gross Derivatives Designated as Hedging Instruments
|
$
|
44.4
|
$
|
41.8
|
|||||||||||||
Derivatives Not Designated as Hedging Instruments
|
|||||||||||||||||
Financial Futures/Swaps (D)
|
NGLs
|
Current PRM
|
$
|
9.2
|
$
|
8.6
|
|||||||||||
Financial Futures/Swaps (E)
|
Natural Gas
|
Current PRM
|
3.6
|
12.3
|
|||||||||||||
Non-Current PRM
|
---
|
0.1
|
|||||||||||||||
Other Current Assets
|
11.8
|
13.6
|
|||||||||||||||
Physical Purchases/Sales
|
Natural Gas
|
Current PRM
|
0.8
|
0.6
|
|||||||||||||
Non-Current PRM
|
0.6
|
---
|
|||||||||||||||
Financial Options
|
Natural Gas
|
Other Current Assets
|
0.9
|
0.8
|
|||||||||||||
Total Gross Derivatives Not Designated as Hedging Instruments
|
$
|
26.9
|
$
|
36.0
|
|||||||||||||
Total Gross Derivatives (F)
|
$
|
71.3
|
$
|
77.8
|
|||||||||||||
(D)
|
The entire fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated with offsetting derivatives to close the hedge positions.
|
||||||||||||||||
(E)
|
The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated with offsetting derivatives to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $2.9 million and Current Liabilities of approximately $11.7 million.
|
||||||||||||||||
(F)
|
See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at December 31, 2009 (see Note 2).
|
Amount of
|
||||||||||||||||||
Gain or Loss
|
||||||||||||||||||
Amount of
|
Location of Gain or
|
Recognized
|
||||||||||||||||
Gain or Loss
|
Loss Recognized in
|
in Income on
|
||||||||||||||||
Amount of Gain
|
Reclassified
|
Income on
|
Derivative
|
|||||||||||||||
or Loss
|
from
|
Derivative
|
(Ineffective
|
|||||||||||||||
Recognized in
|
Location of Gain or
|
Accumulated
|
(Ineffective Portion
|
Portion and
|
||||||||||||||
OCI on
|
Loss Reclassified
|
OCI into
|
and Amount
|
Amount
|
||||||||||||||
Derivative
|
from Accumulated
|
Income
|
Excluded from
|
Excluded from
|
||||||||||||||
(Effective
|
OCI into Income
|
(Effective
|
Effectiveness
|
Effectiveness
|
||||||||||||||
Instrument
|
Portion)(A)
|
(Effective Portion)
|
Portion)
|
Testing)
|
Testing)
|
(In millions)
|
|
Derivatives in Cash Flow Hedging Relationships
|
|
NGLs Financial Options
|
$
|
10.5
|
Operating Revenues
|
$
|
1.1
|
Operating Revenues
|
$
|
---
|
||||||||||
NGLs Financial
|
||||||||||||||||||
Futures/Swaps
|
2.0
|
Operating Revenues
|
(0.5)
|
Operating Revenues
|
---
|
|||||||||||||
Natural Gas Financial
|
||||||||||||||||||
Futures/Swaps
|
---
|
Operating Revenues
|
(8.6)
|
Operating Revenues
|
---
|
|||||||||||||
Total
|
$
|
12.5
|
Total
|
$
|
(8.0)
|
Total
|
$
|
---
|
(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2010 that is expected to be reclassified into
|
earnings within the next 12 months is a loss of approximately $12.5 million.
|
Amount of Gain or
|
||||||||||||||||||
Location of Gain or
|
Loss Recognized in
|
|||||||||||||||||
Loss Recognized in
|
Income of
|
|||||||||||||||||
Income on Derivative
|
Derivative
|
|||||||||||||||||
(In millions)
|
||||||||||||||||||
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||||
Natural Gas Physical Purchases/Sales
|
Operating Revenues
|
$
|
(3.7)
|
|||||||||||||||
Natural Gas Financial Futures/Swaps
|
Operating Revenues
|
(0.6)
|
||||||||||||||||
Total
|
$
|
(4.3)
|
Amount of
|
||||||||||||||||||
Gain or Loss
|
||||||||||||||||||
Amount of
|
Location of Gain or
|
Recognized
|
||||||||||||||||
Gain or Loss
|
Loss Recognized in
|
in Income on
|
||||||||||||||||
Amount of Gain
|
Reclassified
|
Income on
|
Derivative
|
|||||||||||||||
or Loss
|
from
|
Derivative
|
(Ineffective
|
|||||||||||||||
Recognized in
|
Location of Gain or
|
Accumulated
|
(Ineffective Portion
|
Portion and
|
||||||||||||||
OCI on
|
Loss Reclassified
|
OCI into
|
and Amount
|
Amount
|
||||||||||||||
Derivative
|
from Accumulated
|
Income
|
Excluded from
|
Excluded from
|
||||||||||||||
(Effective
|
OCI into Income
|
(Effective
|
Effectiveness
|
Effectiveness
|
||||||||||||||
Instrument
|
Portion)
|
(Effective Portion)
|
Portion)
|
Testing)
|
Testing)
|
(In millions)
|
|
Derivatives in Cash Flow Hedging Relationships
|
|
NGLs Financial Options
|
$
|
(23.9)
|
Operating Revenues
|
$
|
1.2
|
Operating Revenues
|
$
|
---
|
||||||||||
NGLs Financial
|
||||||||||||||||||
Futures/Swaps
|
(20.4)
|
Operating Revenues
|
4.6
|
Operating Revenues
|
---
|
|||||||||||||
Natural Gas Financial
|
||||||||||||||||||
Futures/Swaps
|
5.9
|
Operating Revenues
|
(12.3)
|
Operating Revenues
|
(0.3)
|
|||||||||||||
Total
|
$
|
(38.4)
|
Total
|
$
|
(6.5)
|
Total
|
$
|
(0.3)
|
Amount of Gain or
|
||||||||||||||||||
Location of Gain or
|
Loss Recognized in
|
|||||||||||||||||
Loss Recognized in
|
Income of
|
|||||||||||||||||
Income on Derivative
|
Derivative
|
|||||||||||||||||
(In millions)
|
||||||||||||||||||
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||||
Natural Gas Physical Purchases/Sales
|
Operating Revenues
|
$
|
(2.3)
|
|||||||||||||||
Natural Gas Financial Futures/Swaps
|
Operating Revenues
|
1.8
|
||||||||||||||||
Total
|
$
|
(0.5)
|
Amount of
|
||||||||||||||||||
Gain or Loss
|
||||||||||||||||||
Amount of
|
Location of Gain or
|
Recognized
|
||||||||||||||||
Gain or Loss
|
Loss Recognized in
|
in Income on
|
||||||||||||||||
Amount of Gain
|
Reclassified
|
Income on
|
Derivative
|
|||||||||||||||
or Loss
|
from
|
Derivative
|
(Ineffective
|
|||||||||||||||
Recognized in
|
Location of Gain or
|
Accumulated
|
(Ineffective Portion
|
Portion and
|
||||||||||||||
OCI on
|
Loss Reclassified
|
OCI into
|
and Amount
|
Amount
|
||||||||||||||
Derivative
|
from Accumulated
|
Income
|
Excluded from
|
Excluded from
|
||||||||||||||
(Effective
|
OCI into Income
|
(Effective
|
Effectiveness
|
Effectiveness
|
||||||||||||||
Instrument
|
Portion)(A)
|
(Effective Portion)
|
Portion)
|
Testing)
|
Testing)
|
(In millions)
|
|
Derivatives in Cash Flow Hedging Relationships
|
|
NGLs Financial Options
|
$
|
11.0
|
Operating Revenues
|
$
|
0.5
|
Operating Revenues
|
$
|
---
|
||||||||||
NGLs Financial
|
||||||||||||||||||
Futures/Swaps
|
3.3
|
Operating Revenues
|
(1.8)
|
Operating Revenues
|
---
|
|||||||||||||
Natural Gas Financial
|
||||||||||||||||||
Futures/Swaps
|
(9.9)
|
Operating Revenues
|
(12.0)
|
Operating Revenues
|
0.1
|
|||||||||||||
Total
|
$
|
4.4
|
Total
|
$
|
(13.3)
|
Total
|
$
|
0.1
|
(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2010 that is expected to be reclassified into
|
earnings within the next 12 months is a loss of approximately $12.5 million.
|
Amount of Gain or
|
||||||||||||||||||
Location of Gain or
|
Loss Recognized in
|
|||||||||||||||||
Loss Recognized in
|
Income of
|
|||||||||||||||||
Income on Derivative
|
Derivative
|
|||||||||||||||||
(In millions)
|
||||||||||||||||||
Derivatives Not Designated as Hedging Instruments
|
||||||||||||||||||
Natural Gas Physical Purchases/Sales
|
Operating Revenues
|
$
|
(3.8)
|
|||||||||||||||
Natural Gas Financial Futures/Swaps
|
Operating Revenues
|
0.2
|
||||||||||||||||
Total
|
$
|
(3.6)
|
Amount of
|
||||||||||||||||||
Gain or Loss
|
||||||||||||||||||
Amount of
|
Location of Gain or
|
Recognized
|
||||||||||||||||
Gain or Loss
|
Loss Recognized in
|
in Income on
|
||||||||||||||||
Amount of Gain
|
Reclassified
|
Income on
|
Derivative
|
|||||||||||||||
or Loss
|
from
|
Derivative
|
(Ineffective
|
|||||||||||||||
Recognized in
|
Location of Gain or
|
Accumulated
|
(Ineffective Portion
|
Portion and
|
||||||||||||||
OCI on
|
Loss Reclassified
|
OCI into
|
and Amount
|
Amount
|
||||||||||||||
Derivative
|
from Accumulated
|
Income
|
Excluded from
|
Excluded from
|
||||||||||||||
(Effective
|
OCI into Income
|
(Effective
|
Effectiveness
|
Effectiveness
|
||||||||||||||
Instrument
|
Portion)(A)
|
(Effective Portion)
|
Portion)
|
Testing)
|
Testing)
|
(In millions)
|
|
Derivatives in Cash Flow Hedging Relationships
|
|
NGLs Financial Options
|
$
|
(33.9)
|
Operating Revenues
|
$
|
3.0
|
Operating Revenues
|
$
|
---
|
||||||||||
NGLs Financial
|
||||||||||||||||||
Futures/Swaps
|
(25.2)
|
Operating Revenues
|
10.1
|
Operating Revenues
|
---
|
|||||||||||||
Natural Gas Financial
|
||||||||||||||||||
Futures/Swaps
|
(17.0)
|
Operating Revenues
|
(11.1)
|
Operating Revenues
|
(0.3)
|
|||||||||||||
Total
|
$
|
(76.1)
|
Total
|
$
|
2.0
|
Total
|
$
|
(0.3)
|
Amount of Gain or
|
||||||||||
Location of Gain or
|
Loss Recognized in
|
|||||||||
Loss Recognized in
|
Income of
|
|||||||||
Income on Derivative
|
Derivative
|
|||||||||
(In millions)
|
||||||||||
Derivatives Not Designated as Hedging Instruments
|
||||||||||
Natural Gas Physical Purchases/Sales
|
Operating Revenues
|
$
|
(10.5)
|
|||||||
Natural Gas Financial Futures/Swaps
|
Operating Revenues
|
8.4
|
||||||||
NGLs Financial Futures/Swaps | Operating Revenues | (0.2) | ||||||||
Total
|
$
|
(2.3)
|
June 30,
|
December 31,
|
|||||
(In millions)
|
2010
|
2009
|
||||
Defined benefit pension plan and restoration of retirement income plan:
|
||||||
Net loss, net of tax (($63.6) and ($65.6) pre-tax, respectively)
|
$
|
(39.0)
|
$
|
(40.0)
|
||
Prior service cost, net of tax (($0.9) and ($1.1) pre-tax, respectively)
|
(0.6)
|
(0.7)
|
||||
Defined benefit postretirement plans:
|
||||||
Net loss, net of tax (($20.3) and ($21.2) pre-tax, respectively)
|
(9.8)
|
(10.7)
|
||||
Net transition obligation, net of tax (($0.2) and ($0.6) pre-tax, respectively)
|
(0.1)
|
(0.4)
|
||||
Prior service cost, net of tax (($0.4) and ($0.1) pre-tax, respectively)
|
(0.2)
|
---
|
||||
Deferred commodity contacts hedging losses, net of tax (($19.7) and ($35.5)
|
||||||
pre-tax, respectively)
|
(12.1)
|
(21.7)
|
||||
Deferred hedging losses on interest rate swaps, net of tax (($1.7) and ($1.9) pre-
|
||||||
tax, respectively)
|
(1.1)
|
(1.2)
|
||||
Total accumulated other comprehensive loss, net of tax
|
$
|
(62.9)
|
$
|
(74.7)
|
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
(In millions)
|
2010
|
2009
|
2010
|
2009
|
||||||||
Average Common Shares Outstanding
|
||||||||||||
Basic average common shares outstanding
|
97.3
|
96.5
|
97.2
|
95.6
|
||||||||
Effect of dilutive securities:
|
||||||||||||
Contingently issuable shares (performance units)
|
1.4
|
1.0
|
1.4
|
0.8
|
||||||||
Diluted average common shares outstanding
|
98.7
|
97.5
|
98.6
|
96.4
|
||||||||
Anti-dilutive shares excluded from EPS calculation
|
---
|
---
|
---
|
---
|
SERIES
|
DATE DUE
|
AMOUNT
|
||
(In millions)
|
||||
0.30% - 0.50%
|
Garfield Industrial Authority, January 1, 2025
|
$
|
47.0
|
|
0.35% - 0.52%
|
Muskogee Industrial Authority, January 1, 2025
|
32.4
|
||
0.33% - 0.55%
|
Muskogee Industrial Authority, June 1, 2027
|
56.0
|
||
Total (redeemable during next 12 months)
|
$
|
135.4
|
Revolving Credit Agreements and Available Cash
|
||||||||
Aggregate
|
Amount
|
Weighted-Average
|
||||||
Entity
|
Commitment
|
Outstanding (A)
|
Interest Rate
|
Maturity
|
||||
(In millions)
|
||||||||
OGE Energy (B)
|
$
|
596.0
|
$
|
112.9
|
0.38% (D)
|
December 6, 2012
|
||
OG&E (C)
|
389.0
|
9.5
|
---% (D)
|
December 6, 2012
|
||||
Enogex (E)
|
250.0
|
65.0
|
0.66% (D)
|
March 31, 2013
|
||||
1,235.0
|
187.4
|
0.46%
|
||||||
Cash
|
7.3
|
N/A
|
N/A
|
N/A
|
||||
Total
|
$
|
1,242.3
|
$
|
187.4
|
0.46%
|
|||
(A) Includes direct borrowings under the revolving credit agreements, commercial paper borrowings and letters of credit at June 30, 2010.
(B) This bank facility is available to back up OGE Energy’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At June 30, 2010, there were no outstanding borrowings under this revolving credit agreement and approximately $112.9 million in outstanding commercial paper borrowings.
(C) This bank facility is available to back up OG&E’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At June 30, 2010, there was approximately $9.5 million supporting letters of credit. There were no outstanding borrowings under this revolving credit agreement and no outstanding commercial paper borrowings at June 30, 2010.
(D) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements and commercial paper borrowings.
(E) This bank facility is available to provide revolving credit borrowings for Enogex. As Enogex’s credit agreement matures on March 31, 2013, borrowings thereunder are classified as long-term debt in the Company’s Condensed Consolidated Balance Sheets.
|
Pension Plan
|
||||||||||||
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
(In millions)
|
2010 (A)
|
2009 (A)
|
2010 (B)
|
2009 (B)
|
||||||||
Service cost
|
$
|
4.0
|
$
|
4.5
|
$
|
8.4
|
$
|
9.0
|
||||
Interest cost
|
8.1
|
7.9
|
15.9
|
15.7
|
||||||||
Expected return on plan assets
|
(10.5)
|
(8.3)
|
(21.2)
|
(16.5)
|
||||||||
Amortization of net loss
|
5.5
|
5.9
|
10.6
|
11.8
|
||||||||
Amortization of unrecognized prior service cost
|
0.6
|
0.2
|
1.2
|
0.4
|
||||||||
Net periodic benefit cost
|
$
|
7.7
|
$
|
10.2
|
$
|
14.9
|
$
|
20.4
|
Restoration of Retirement Income Plan
|
|||||||||||||
Three Months Ended
|
Six Months Ended
|
||||||||||||
June 30,
|
June 30,
|
||||||||||||
(In millions)
|
2010 (A)
|
2009 (A)
|
2010 (B)
|
2009 (B)
|
|||||||||
Service cost
|
$
|
0.2
|
$
|
0.2
|
$
|
0.4
|
$
|
0.4
|
|||||
Interest cost
|
0.1
|
0.1
|
0.2
|
0.2
|
|||||||||
Amortization of net loss
|
0.1
|
---
|
0.2
|
0.1
|
|||||||||
Amortization of unrecognized prior service cost
|
0.3
|
0.2
|
0.4
|
0.3
|
|||||||||
Net periodic benefit cost
|
$
|
0.7
|
$
|
0.5
|
$
|
1.2
|
$
|
1.0
|
(A)
|
In addition to the $8.4 million and $10.7 million of net periodic benefit cost recognized during the three months ended June 30, 2010 and 2009, respectively, the Company recognized the following:
|
(B)
|
In addition to the $16.1 million and $21.4 million of net periodic benefit cost recognized during the six months ended June 30, 2010 and 2009, respectively, the Company recognized the following:
|
Postretirement Benefit Plans
|
||||||||||||
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
(In millions)
|
2010
|
2009
|
2010
|
2009
|
||||||||
Service cost
|
$
|
0.9
|
$
|
0.9
|
$
|
2.1
|
$
|
1.7
|
||||
Interest cost
|
4.3
|
3.5
|
8.5
|
7.0
|
||||||||
Expected return on plan assets
|
(1.8)
|
(1.7)
|
(3.5)
|
(3.3)
|
||||||||
Amortization of transition obligation
|
0.7
|
0.7
|
1.4
|
1.4
|
||||||||
Amortization of net loss
|
3.4
|
1.3
|
6.1
|
2.5
|
||||||||
Amortization of unrecognized prior service cost
|
---
|
0.2
|
---
|
0.5
|
||||||||
Net periodic benefit cost
|
$
|
7.5
|
$
|
4.9
|
$
|
14.6
|
$
|
9.8
|
Transportation
|
Gathering
|
|||||||||||||
Three Months Ended
|
Electric
|
And
|
and
|
Other
|
||||||||||
June 30, 2010
|
Utility
|
Storage
|
Processing
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In millions)
|
||||||||||||||
Operating revenues
|
$
|
512.8
|
$
|
97.1
|
$
|
235.4
|
$
|
189.0
|
$
|
---
|
$
|
(147.1)
|
$
|
887.2
|
Cost of goods sold
|
230.8
|
60.9
|
168.6
|
192.9
|
---
|
(146.7)
|
506.5
|
|||||||
Gross margin on revenues
|
282.0
|
36.2
|
66.8
|
(3.9)
|
---
|
(0.4)
|
380.7
|
|||||||
Other operation and maintenance
|
101.2
|
12.6
|
23.5
|
2.1
|
(3.5)
|
(0.9)
|
135.0
|
|||||||
Depreciation and amortization
|
50.6
|
5.4
|
12.5
|
---
|
2.7
|
---
|
71.2
|
|||||||
Taxes other than income
|
17.2
|
3.4
|
1.6
|
---
|
0.8
|
---
|
23.0
|
|||||||
Operating income (loss)
|
$
|
113.0
|
$
|
14.8
|
$
|
29.2
|
$
|
(6.0)
|
$
|
---
|
$
|
0.5
|
$
|
151.5
|
Total assets
|
$
|
5,775.9
|
$
|
1,556.2
|
$
|
907.9
|
$
|
104.5
|
$
|
2,691.6
|
$
|
(3,742.0)
|
$
|
7,294.1
|
Transportation
|
Gathering
|
|||||||||||||
Three Months Ended
|
Electric
|
And
|
and
|
Other
|
||||||||||
June 30, 2009
|
Utility
|
Storage
|
Processing
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In millions)
|
||||||||||||||
Operating revenues
|
$
|
425.3
|
$
|
101.0
|
$
|
142.3
|
$
|
117.2
|
$
|
---
|
$
|
(141.7)
|
$
|
644.1
|
Cost of goods sold
|
188.3
|
60.7
|
98.7
|
116.6
|
---
|
(140.1)
|
324.2
|
|||||||
Gross margin on revenues
|
237.0
|
40.3
|
43.6
|
0.6
|
---
|
(1.6)
|
319.9
|
|||||||
Other operation and maintenance
|
77.9
|
9.7
|
19.9
|
2.7
|
(3.3)
|
(1.3)
|
105.6
|
|||||||
Depreciation and amortization
|
46.0
|
5.3
|
10.6
|
---
|
2.7
|
---
|
64.6
|
|||||||
Impairment of assets
|
0.3
|
0.8
|
0.3
|
---
|
---
|
---
|
1.4
|
|||||||
Taxes other than income
|
16.3
|
3.2
|
1.5
|
0.1
|
0.8
|
---
|
21.9
|
|||||||
Operating income (loss)
|
$
|
96.5
|
$
|
21.3
|
$
|
11.3
|
$
|
(2.2)
|
$
|
(0.2)
|
$
|
(0.3)
|
$
|
126.4
|
Total assets
|
$
|
5,161.1
|
$
|
1,565.9
|
$
|
885.9
|
$
|
127.1
|
$
|
2,477.1
|
$
|
(3,212.3)
|
$
|
7,004.8
|
Transportation
|
Gathering
|
|||||||||||||
Six Months Ended
|
Electric
|
And
|
and
|
Other
|
||||||||||
June 30, 2010
|
Utility
|
Storage
|
Processing
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In millions)
|
||||||||||||||
Operating revenues
|
$
|
956.8
|
$
|
208.2
|
$
|
483.3
|
$
|
434.7
|
$
|
---
|
$
|
(320.0)
|
$
|
1,763.0
|
Cost of goods sold
|
481.6
|
127.1
|
348.6
|
437.2
|
---
|
(317.9)
|
1,076.6
|
|||||||
Gross margin on revenues
|
475.2
|
81.1
|
134.7
|
(2.5)
|
---
|
(2.1)
|
686.4
|
|||||||
Other operation and maintenance
|
195.1
|
23.6
|
44.8
|
4.8
|
(7.6)
|
(2.1)
|
258.6
|
|||||||
Depreciation and amortization
|
100.3
|
10.8
|
24.9
|
---
|
5.5
|
---
|
141.5
|
|||||||
Taxes other than income
|
34.9
|
7.3
|
3.5
|
0.2
|
2.1
|
---
|
48.0
|
|||||||
Operating income (loss)
|
$
|
144.9
|
$
|
39.4
|
$
|
61.5
|
$
|
(7.5)
|
$
|
---
|
$
|
---
|
$
|
238.3
|
Total assets
|
$
|
5,775.9
|
$
|
1,556.2
|
$
|
907.9
|
$
|
104.5
|
$
|
2,691.6
|
$
|
(3,742.0)
|
$
|
7,294.1
|
Transportation
|
Gathering
|
|||||||||||||
Six Months Ended
|
Electric
|
And
|
and
|
Other
|
||||||||||
June 30, 2009
|
Utility
|
Storage
|
Processing
|
Marketing
|
Operations
|
Eliminations
|
Total
|
|||||||
(In millions)
|
||||||||||||||
Operating revenues
|
$
|
762.0
|
$
|
209.3
|
$
|
280.8
|
$
|
309.5
|
$
|
---
|
$
|
(310.9)
|
$
|
1,250.7
|
Cost of goods sold
|
359.3
|
126.9
|
194.8
|
304.4
|
---
|
(308.0)
|
677.4
|
|||||||
Gross margin on revenues
|
402.7
|
82.4
|
86.0
|
5.1
|
---
|
(2.9)
|
573.3
|
|||||||
Other operation and maintenance
|
163.2
|
19.6
|
43.0
|
5.3
|
(6.6)
|
(2.4)
|
222.1
|
|||||||
Depreciation and amortization
|
91.5
|
10.0
|
20.7
|
---
|
5.0
|
---
|
127.2
|
|||||||
Impairment of assets
|
0.3
|
0.8
|
0.3
|
---
|
---
|
---
|
1.4
|
|||||||
Taxes other than income
|
32.4
|
6.8
|
2.8
|
0.3
|
1.9
|
---
|
44.2
|
|||||||
Operating income (loss)
|
$
|
115.3
|
$
|
45.2
|
$
|
19.2
|
$
|
(0.5)
|
$
|
(0.3)
|
$
|
(0.5)
|
$
|
178.4
|
Total assets
|
$
|
5,161.1
|
$
|
1,565.9
|
$
|
885.9
|
$
|
127.1
|
$
|
2,477.1
|
$
|
(3,212.3)
|
$
|
7,004.8
|
Ÿ
|
Pre-approval for system-wide deployment of smart grid technology and authorization for OG&E to begin recovering the costs of the system-wide deployment of smart grid technology through a rider mechanism that will become effective in accordance with the order approving the settlement agreement;
|
Ÿ
|
OG&E’s total project costs eligible for recovery (those costs expended or accrued by OG&E prior to the termination of the period authorized by the DOE as eligible for grant funds) shall be capped at $366.4 million (“Smart Grid Cost”), inclusive of the DOE grant award amount. The Smart Grid Cost includes the cost of implementing the Norman, Oklahoma smart grid pilot program previously authorized by the OCC. Under the terms of the settlement, the Smart Grid Cost would be deemed to represent an investment that is fair, just and reasonable and in the public interest and to be prudent and will be recognized in OG&E’s 2013 general rate case;
|
Ÿ
|
To the extent that OG&E’s total expenditure for system-wide deployment of smart grid technology during the eligible period exceeds the Smart Grid Cost, OG&E shall be entitled to offer evidence and seek to establish that the excess above the Smart Grid Cost was prudently incurred and any such contention may be addressed in OG&E’s 2013 rate case;
|
Ÿ
|
Implementation of the recovery rider would commence with the first billing cycle in July 2010;
|
Ÿ
|
Continued utilization of a return on equity previously approved by the OCC for other various recovery riders;
|
Ÿ
|
The recovery rider shall be designed to collect, on a levelized basis, the revenue requirement associated with the estimated project cost of $357.4 million and shall be subject to a true-up in 2014 after the recovery rider expires, including a true-up for project costs, if any, in excess of $357.4 million but less than the Smart Grid Cost. Any over/under recovery remaining will be passed or credited through OG&E’s fuel adjustment clause;
|
Ÿ
|
OG&E guarantees that customers will receive the benefit of certain operations and maintenance cost reductions resulting from the smart grid deployment as a credit to the recovery rider;
|
Ÿ
|
Beginning January 1, 2011, OG&E shall make available the smart grid web portal to all customers having a smart meter. OG&E shall expend funds to educate customers regarding the best use of the information available on the portal. In addition, OG&E shall make available to all customers who do not have internet access the opportunity to receive a monthly home energy report. This report shall be made available, free of charge, to customers eligible for the Company’s Low Income Home Energy Assistance Program and/or Senior Citizen program who are without internet service. The incremental costs for web portal access, education and the providing of home energy reports free of charge are to be accumulated as a regulatory asset in an amount up to $6.9 million and recovered in base rates beginning in 2014;
|
Ÿ
|
The stranded costs associated with OG&E’s existing meters which are being replaced by smart meters will be accumulated in a regulatory asset and recovered in base rates beginning in 2014; and
|
Ÿ
|
OG&E will file an application with the APSC related to the deployment of smart grid technology by the end of 2010.
|
Ÿ
|
Authorization for OG&E to begin recovering the costs of Crossroads through a rider mechanism that will be effective until new rates are implemented after OG&E’s 2013 general rate case;
|
Ÿ
|
Continued utilization of a return on equity previously approved by the OCC for other various recovery riders, subject to adjustment in the future to reflect the return on equity authorized in subsequent general rate cases;
|
Ÿ
|
OG&E’s capital costs for which it is entitled recovery for a 197.8 MW wind farm (“Capped Investment Amount”) is $407.7 million;
|
Ÿ
|
To the extent OG&E’s total investment in Crossroads exceeds the Capped Investment Amount, OG&E shall be entitled to offer evidence and seek to establish that the excess above the Capped Investment Amount was prudently incurred and should be included in OG&E’s rate base;
|
Ÿ
|
If the three-year rolling average of Crossroads megawatt-hours (“MWH”) of production (including a credit for energy not produced due to curtailments or other events caused by system emergencies, force majeure events, or transmission system issues) falls below 712,844 MWHs, OG&E shall file testimony demonstrating the appropriate operation of Crossroads as part of its fuel cost recovery filing; and
|
Ÿ
|
OG&E has the opportunity to expand Crossroads by an additional 29.7 MWs (12 additional turbines). If the pending Southwest Power Pool (“SPP”) interconnection study concludes on or before September 1, 2010, that these additional turbines can be interconnected at incremental costs below $4.7 million, the costs and associated recovery for these additional turbines shall be included in the Crossroads rider, and the Capped Investment Amount and the three-year rolling average of MWH production will be adjusted to approximately $469.7 million and 819,879 MWHs, respectively.
|
Ÿ
|
an increase in net income at OG&E of approximately $3.6 million or 6.4 percent, or $0.03 per diluted share of the Company’s common stock, primarily due to a higher gross margin on revenues (“gross margin”) mainly due to rate increases and riders partially offset by higher other operation and maintenance expense;
|
Ÿ
|
an increase in net income at Enogex of approximately $6.3 million or 39.4 percent, or $0.07 per diluted share of the Company’s common stock, primarily due to a higher gross margin mainly due to higher processing spreads, higher natural gas liquids (“NGL”) prices and volumes and higher natural gas prices and volumes partially offset by higher other operation and maintenance expense; and
|
Ÿ
|
an increase in the net loss at OGE Energy Resources, Inc. (“OERI”) of approximately $2.4 million, or $0.03 per diluted share of the Company’s common stock, primarily due to a lower gross margin partially offset by a higher income tax benefit.
|
Ÿ
|
an increase in net income at OG&E of approximately $3.5 million or 6.1 percent, or $0.02 per diluted share of the Company’s common stock, primarily due to a higher gross margin mainly due to rate increases and riders, cooler weather in the first quarter of 2010 and warmer weather in the second quarter of 2010 partially offset by higher other operation and maintenance expense and higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 6 of Notes to Condensed Consolidated Financial Statements);
|
Ÿ
|
an increase in net income at Enogex of approximately $18.3 million or 58.3 percent, or $0.17 per diluted share of the Company’s common stock, primarily due to a higher gross margin mainly due to higher processing spreads, higher NGLs prices and volumes and higher natural gas prices and volumes partially offset by higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 6 of Notes to Condensed Consolidated Financial Statements);
|
Ÿ
|
an increase in the net loss at OGE Energy of approximately $2.4 million, or $0.02 per diluted share of the Company’s common stock, primarily due to higher income tax expense mainly attributable to the elimination of the tax deduction for the Medicare Part D subsidy (discussed in Note 6 of Notes to Condensed Consolidated Financial Statements) partially offset by lower interest expense primarily due to lower average commercial paper borrowings in the first half of 2010; and
|
Ÿ
|
an increase in the net loss at OERI of approximately $4.4 million, or $0.05 per diluted share of the Company’s common stock, primarily due to a lower gross margin partially offset by a higher income tax benefit.
|
Ÿ
|
Excludes a one-time, non-cash charge recorded in March 2010 of approximately $11.4 million, or $0.11 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy. Approximately $7.0 million is related to OG&E, approximately $2.0 million is related to Enogex and approximately $2.4 million is related to the holding company.
|
Ÿ
|
Includes a projected increase for the remainder of 2010 in income tax expense of approximately $2.3 million, or $0.02 per average diluted share, related to the elimination of the tax deduction for the Medicare Part D subsidy. Approximately $1.9 million is related to OG&E, approximately $0.2 million is related to Enogex and approximately $0.2 million is related to the holding company.
|
Ÿ
|
An effective tax rate of approximately 33 percent up from the previous guidance of 29 percent primarily a result of lower than previously projected investment and production tax credits at OG&E. The projected effective tax rate excludes the approximately $11.4 million charge related to the Medicare Part D subsidy; and
|
Ÿ
|
A projected loss at the holding company between $11 million and $13 million, or $0.11 to $0.13 per average diluted share, up from the previous projected loss between $7 million and $9 million, or $0.07 to $0.09 per average diluted share. The increase in the projected loss at the holding company is primarily due to lower than previously estimated revenues in the marketing business associated with various transportation contracts and the write-off of costs associated with the Tallgrass joint venture.
|
Ÿ
|
Allowance for equity funds used during construction (“AEFUDC”) income of approximately $15 million up from the previous guidance of $5 million primarily as a result of OCC approval of the Crossroads wind farm; and
|
Ÿ
|
An effective tax rate of approximately 31 percent up from the previous guidance of 27 percent primarily as a result of lower investment and production tax credits than previously projected. The projected effective tax rate excludes the approximately $7.0 million charge related to the Medicare Part D subsidy.
|
Ÿ
|
Assumed increase of between 8 percent and 10 percent in gathered volumes over 2009 compared to the previous guidance of an increase of between 5 percent and 7 percent;
|
Ÿ
|
Assumed increase of between 15 percent and 17 percent in inlet processing volumes over 2009 compared to the previous guidance of an increase of between 10 percent and 12 percent;
|
Ÿ
|
Ethane rejection in the processing business for the remainder of the year; and
|
Ÿ
|
Operating expenses of approximately $230 million to $240 million, up from the previous guidance of between $220 million to $230 million, primarily as a result of increased pipeline integrity and maintenance projects in the transportation business.
|
(In millions)
|
Twelve Months Ended December 31, 2010
|
||||||||||||||||
OG&E
|
Enogex
|
Holding Company
|
Consolidated
|
||||||||||||||
Low
|
High
|
Low
|
High
|
Low
|
High
|
Low
|
High
|
||||||||||
Ongoing earnings (loss)
|
$
|
207.0
|
$
|
217.0
|
$
|
63.0
|
$
|
85.0
|
$
|
(13.0)
|
$
|
(11.0)
|
$
|
265.0
|
$
|
290.0
|
|
Medicare Part D tax subsidy
|
(7.0)
|
(7.0)
|
(2.0)
|
(2.0)
|
(2.4)
|
(2.4)
|
(11.4)
|
(11.4)
|
|||||||||
Projected GAAP net income
|
$
|
200.0
|
$
|
210.0
|
$
|
61.0
|
$
|
83.0
|
$
|
(15.4)
|
$
|
(13.4)
|
$
|
253.6
|
$
|
278.6
|
Twelve Months Ended December 31, 2010
|
|||||||||||||||||
OG&E
|
Enogex
|
Holding Company
|
Consolidated
|
||||||||||||||
Low
|
High
|
Low
|
High
|
Low
|
High
|
Low
|
High
|
||||||||||
Ongoing EPS
|
$
|
2.10
|
$
|
2.20
|
$
|
0.64
|
$
|
0.86
|
$
|
(0.13)
|
$
|
(0.11)
|
$
|
2.70
|
$
|
2.95
|
|
Medicare Part D tax subsidy
|
(0.07)
|
(0.07)
|
(0.02)
|
(0.02)
|
(0.02)
|
(0.02)
|
(0.11)
|
(0.11)
|
|||||||||
Projected GAAP EPS
|
$
|
2.03
|
$
|
2.13
|
$
|
0.62
|
$
|
0.84
|
$
|
(0.15)
|
$
|
(0.13)
|
$
|
2.59
|
$
|
2.84
|
Twelve Months Ended
|
|||
(In millions)
|
December 31, 2010 (A)
|
||
Ongoing net income attributable to Enogex LLC
|
$
|
85.0
|
|
Add:
|
|||
Interest expense, net
|
33.0
|
||
Income tax expense
|
49.0
|
||
Depreciation and amortization
|
69.0
|
||
EBITDA
|
$
|
236.0
|
(A)
|
At the top end of Enogex’s earnings assumptions for 2010.
|
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
(In millions, except per share data)
|
2010
|
2009
|
2010
|
2009
|
||||||||
Operating income
|
$
|
151.5
|
$
|
126.4
|
$
|
238.3
|
$
|
178.4
|
||||
Net income attributable to OGE Energy
|
$
|
77.3
|
$
|
70.5
|
$
|
101.5
|
$
|
87.3
|
||||
Basic average common shares outstanding
|
97.3
|
96.5
|
97.2
|
95.6
|
||||||||
Diluted average common shares outstanding
|
98.7
|
97.5
|
98.6
|
96.4
|
||||||||
Basic earnings per average common share attributable to
|
||||||||||||
OGE Energy common shareholders
|
$
|
0.79
|
$
|
0.73
|
$
|
1.04
|
$
|
0.91
|
||||
Diluted earnings per average common share attributable to
|
||||||||||||
OGE Energy common shareholders
|
$
|
0.78
|
$
|
0.72
|
$
|
1.03
|
$
|
0.91
|
||||
Dividends declared per share
|
$
|
0.3625
|
$
|
0.3550
|
$
|
0.7250
|
$
|
0.7100
|
Three Months Ended
|
Six Months Ended
|
||||||||||||
June 30,
|
June 30,
|
||||||||||||
(In millions)
|
2010
|
2009
|
2010
|
2009
|
|||||||||
OG&E (Electric Utility)
|
$
|
113.0
|
$
|
96.5
|
$
|
144.9
|
$
|
115.3
|
|||||
Enogex (Natural Gas Pipeline)
|
|||||||||||||
Transportation and storage
|
14.8
|
21.3
|
39.4
|
45.2
|
|||||||||
Gathering and processing
|
29.2
|
11.3
|
61.5
|
19.2
|
|||||||||
OERI (Natural Gas Marketing)
|
(6.0)
|
(2.2)
|
(7.5)
|
(0.5)
|
|||||||||
Other Operations (A)
|
0.5
|
(0.5)
|
---
|
(0.8)
|
|||||||||
Consolidated operating income
|
$
|
151.5
|
$
|
126.4
|
$
|
238.3
|
$
|
178.4
|
Three Months Ended
|
Six Months Ended
|
||||||||||||
June 30,
|
June 30,
|
||||||||||||
(Dollars in millions)
|
2010
|
2009
|
2010
|
2009
|
|||||||||
Operating revenues
|
$
|
512.8
|
$
|
425.3
|
$
|
956.8
|
$
|
762.0
|
|||||
Cost of goods sold
|
230.8
|
188.3
|
481.6
|
359.3
|
|||||||||
Gross margin on revenues
|
282.0
|
237.0
|
475.2
|
402.7
|
|||||||||
Other operation and maintenance
|
101.2
|
77.9
|
195.1
|
163.2
|
|||||||||
Depreciation and amortization
|
50.6
|
46.0
|
100.3
|
91.5
|
|||||||||
Impairment of assets
|
---
|
0.3
|
---
|
0.3
|
|||||||||
Taxes other than income
|
17.2
|
16.3
|
34.9
|
32.4
|
|||||||||
Operating income
|
113.0
|
96.5
|
144.9
|
115.3
|
|||||||||
Interest income
|
---
|
0.3
|
---
|
0.8
|
|||||||||
Allowance for equity funds used during construction
|
2.3
|
3.9
|
4.6
|
5.2
|
|||||||||
Other income
|
0.8
|
4.2
|
3.3
|
8.8
|
|||||||||
Other expense
|
0.4
|
0.7
|
1.0
|
1.2
|
|||||||||
Interest expense
|
25.2
|
23.2
|
49.4
|
47.5
|
|||||||||
Income tax expense
|
30.5
|
24.6
|
41.2
|
23.7
|
|||||||||
Net income
|
$
|
60.0
|
$
|
56.4
|
$
|
61.2
|
$
|
57.7
|
|||||
Operating revenues by classification
|
|||||||||||||
Residential
|
$
|
207.7
|
$
|
167.6
|
$
|
398.9
|
$
|
303.9
|
|||||
Commercial
|
132.0
|
112.3
|
233.0
|
191.7
|
|||||||||
Industrial
|
52.8
|
43.0
|
98.3
|
75.8
|
|||||||||
Oilfield
|
40.4
|
33.2
|
76.0
|
62.1
|
|||||||||
Public authorities and street light
|
50.5
|
41.3
|
90.0
|
72.8
|
|||||||||
Sales for resale
|
14.5
|
12.0
|
31.2
|
24.7
|
|||||||||
Provision for rate refund
|
---
|
(0.4)
|
---
|
(0.6)
|
|||||||||
System sales revenues
|
497.9
|
409.0
|
927.4
|
730.4
|
|||||||||
Off-system sales revenues (A)
|
7.5
|
8.6
|
13.9
|
14.5
|
|||||||||
Other
|
7.4
|
7.7
|
15.5
|
17.1
|
|||||||||
Total operating revenues
|
$
|
512.8
|
$
|
425.3
|
$
|
956.8
|
$
|
762.0
|
|||||
MWH (B) sales by classification (in millions)
|
|||||||||||||
Residential
|
2.082
|
2.069
|
4.426
|
4.063
|
|||||||||
Commercial
|
1.754
|
1.704
|
3.163
|
3.090
|
|||||||||
Industrial
|
0.966
|
0.861
|
1.857
|
1.710
|
|||||||||
Oilfield
|
0.756
|
0.720
|
1.481
|
1.452
|
|||||||||
Public authorities and street light
|
0.784
|
0.759
|
1.426
|
1.412
|
|||||||||
Sales for resale
|
0.351
|
0.309
|
0.679
|
0.620
|
|||||||||
System sales
|
6.693
|
6.422
|
13.032
|
12.347
|
|||||||||
Off-system sales
|
0.202
|
0.305
|
0.339
|
0.495
|
|||||||||
Total sales
|
6.895
|
6.727
|
13.371
|
12.842
|
|||||||||
Number of customers
|
779,359
|
773,436
|
779,359
|
773,436
|
|||||||||
Average cost of energy per KWH (C) – cents
|
|||||||||||||
Natural gas
|
4.503
|
3.310
|
5.050
|
3.519
|
|||||||||
Coal
|
1.916
|
1.778
|
1.858
|
1.659
|
|||||||||
Total fuel
|
2.832
|
2.340
|
3.049
|
2.285
|
|||||||||
Total fuel and purchased power
|
3.127
|
2.624
|
3.334
|
2.601
|
|||||||||
Degree days (D)
|
|||||||||||||
Heating - Actual
|
158
|
254
|
2,298
|
1,929
|
|||||||||
Heating - Normal
|
236
|
236
|
2,199
|
2,199
|
|||||||||
Cooling - Actual
|
737
|
637
|
745
|
660
|
|||||||||
Cooling - Normal
|
547
|
547
|
555
|
555
|
|||||||||
(A) Sales to other utilities and power marketers.
(B) Megawatt-hour.
(C) Kilowatt-hour.
(D) Degree days are calculated as follows: The high and low degrees of a particular day are added together and then averaged. If the calculated average is above 65 degrees, then the difference between the calculated average and 65 is expressed as cooling degree days, with each degree of difference equaling one cooling degree day. If the calculated average is below 65 degrees, then the difference between the calculated average and 65 is expressed as heating degree days, with each degree of difference equaling one heating degree day. The daily calculations are then totaled for the particular reporting period.
|
Ÿ
|
increased price variance, which included revenues from various rate riders, including the Windspeed rider, the OU Spirit rider, the Smart Grid rider and the system hardening rider, and higher revenues from the sales and customer mix, which increased the gross margin by approximately $26.7 million;
|
Ÿ
|
the $48.3 million Oklahoma rate increase in which the majority of the annual increase is recovered during the summer months, which increased the gross margin by approximately $14.9 million;
|
Ÿ
|
warmer weather in OG&E’s service territory, which increased the gross margin by approximately $1.8 million;
|
Ÿ
|
revenues from the Arkansas rate increase, which increased the gross margin by approximately $1.4 million; and
|
Ÿ
|
new customer growth in OG&E’s service territory, which increased the gross margin by approximately $1.4 million.
|
Ÿ
|
an increase of approximately $8.0 million in contract technical and construction services expense primarily attributable to increased spending for ongoing maintenance at some of OG&E’s power plants in the second quarter of 2010 as compared to the same period in 2009;
|
Ÿ
|
an increase of approximately $7.0 million in employee benefits expense primarily due to a reclassification in May 2009 of 2006 and 2007 pension settlement costs to a regulatory asset, as prescribed in the Arkansas rate case settlement, an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010 and an increase in pension expense due to a decrease in the amount
|
Ÿ
|
an increase of approximately $2.3 million in intercompany allocations due to increased spending at the holding company;
|
Ÿ
|
an increase of approximately $2.0 million in salaries and wages expense primarily due to salary increases in 2010 and increased overtime expense due to storms in May 2010; and
|
Ÿ
|
an increase of approximately $1.9 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider.
|
Ÿ
|
increased price variance, which included revenues from various rate riders, including the Windspeed rider, the OU Spirit rider, the Smart Grid rider and the system hardening rider, and higher revenues from the sales and customer mix, which increased the gross margin by approximately $36.3 million;
|
Ÿ
|
the $48.3 million Oklahoma rate increase in which the majority of the annual increase is recovered during the summer months, which increased the gross margin by approximately $18.9 million;
|
Ÿ
|
cooler weather in the first quarter of 2010 and warmer weather in the second quarter of 2010 in OG&E’s service territory, which increased the gross margin by approximately $13.4 million;
|
Ÿ
|
revenues from the Arkansas rate increase, which increased the gross margin by approximately $3.5 million; and
|
Ÿ
|
new customer growth in OG&E’s service territory, which increased the gross margin by approximately $3.0 million.
|
Ÿ
|
an increase of approximately $11.5 million in contract technical and construction services attributable to increased spending for ongoing maintenance at some of OG&E’s power plants in the first half of 2010 as compared to the same period in 2009;
|
Ÿ
|
an increase of approximately $10.0 million in employee benefits expense primarily due to an increase in postretirement benefits due to an increase in medical costs and changes in actuarial assumptions in 2010, a reclassification in May 2009 of 2006 and 2007 pension settlement costs to a regulatory asset, as prescribed in the Arkansas rate case settlement, and an increase in pension expense due to a decrease in the amount deferred as a pension regulatory asset in OG&E’s Oklahoma jurisdiction resulting from OG&E’s 2009 Oklahoma rate case;
|
Ÿ
|
an increase of approximately $6.8 million in salaries and wages expense primarily due to salary increases in 2010, increased incentive compensation expense and increased overtime expense due to the storms in January and May 2010;
|
Ÿ
|
an increase of approximately $2.6 million in intercompany allocations due to increased spending at the holding company;
|
Ÿ
|
an increase of approximately $2.4 million due to increased spending on vegetation management related to system hardening, which expenses are being recovered through a rider; and
|
Ÿ
|
an increase of approximately $1.7 million in injuries and damages.
|
Ÿ
|
an increase of approximately $3.4 million in capitalized labor primarily due to certain January and May 2010 storm costs being recorded as a regulatory asset as Deferred Storm Expenses (see Note 1) and certain costs being capitalized in conjunction with OG&E’s Smart Grid Program during the first half of 2010; and
|
Ÿ
|
a decrease of approximately $1.2 million due to lower bad debt expense.
|
Transportation
|
Gathering
|
|||||||||||
Three Months Ended
|
and
|
and
|
||||||||||
June 30, 2010
|
Storage
|
Processing
|
Eliminations
|
Total
|
||||||||
(In millions)
|
||||||||||||
Operating revenues
|
$
|
97.1
|
$
|
235.4
|
$
|
(62.5)
|
$
|
270.0
|
||||
Cost of goods sold
|
60.9
|
168.6
|
(62.5)
|
167.0
|
||||||||
Gross margin on revenues
|
36.2
|
66.8
|
---
|
103.0
|
||||||||
Other operation and maintenance
|
12.6
|
23.5
|
---
|
36.1
|
||||||||
Depreciation and amortization
|
5.4
|
12.5
|
---
|
17.9
|
||||||||
Taxes other than income
|
3.4
|
1.6
|
---
|
5.0
|
||||||||
Operating income
|
$
|
14.8
|
$
|
29.2
|
$
|
---
|
$
|
44.0
|
Transportation
|
Gathering
|
|||||||||||
Three Months Ended
|
and
|
and
|
||||||||||
June 30, 2009
|
Storage
|
Processing
|
Eliminations
|
Total
|
||||||||
(In millions)
|
||||||||||||
Operating revenues
|
$
|
101.0
|
$
|
142.3
|
$
|
(52.4)
|
$
|
190.9
|
||||
Cost of goods sold
|
60.7
|
98.7
|
(52.4)
|
107.0
|
||||||||
Gross margin on revenues
|
40.3
|
43.6
|
---
|
83.9
|
||||||||
Other operation and maintenance
|
9.7
|
19.9
|
---
|
29.6
|
||||||||
Depreciation and amortization
|
5.3
|
10.6
|
---
|
15.9
|
||||||||
Impairment of assets
|
0.8
|
0.3
|
---
|
1.1
|
||||||||
Taxes other than income
|
3.2
|
1.5
|
---
|
4.7
|
||||||||
Operating income
|
$
|
21.3
|
$
|
11.3
|
$
|
---
|
$
|
32.6
|
Transportation
|
Gathering
|
|||||||||||
Six Months Ended
|
and
|
and
|
||||||||||
June 30, 2010
|
Storage
|
Processing
|
Eliminations
|
Total
|
||||||||
(In millions)
|
||||||||||||
Operating revenues
|
$
|
208.2
|
$
|
483.3
|
$
|
(137.3)
|
$
|
554.2
|
||||
Cost of goods sold
|
127.1
|
348.6
|
(137.3)
|
338.4
|
||||||||
Gross margin on revenues
|
81.1
|
134.7
|
---
|
215.8
|
||||||||
Other operation and maintenance
|
23.6
|
44.8
|
---
|
68.4
|
||||||||
Depreciation and amortization
|
10.8
|
24.9
|
---
|
35.7
|
||||||||
Taxes other than income
|
7.3
|
3.5
|
---
|
10.8
|
||||||||
Operating income
|
$
|
39.4
|
$
|
61.5
|
$
|
---
|
$
|
100.9
|
Transportation
|
Gathering
|
|||||||||||
Six Months Ended
|
and
|
and
|
||||||||||
June 30, 2009
|
Storage
|
Processing
|
Eliminations
|
Total
|
||||||||
(In millions)
|
||||||||||||
Operating revenues
|
$
|
209.3
|
$
|
280.8
|
$
|
(109.1)
|
$
|
381.0
|
||||
Cost of goods sold
|
126.9
|
194.8
|
(109.1)
|
212.6
|
||||||||
Gross margin on revenues
|
82.4
|
86.0
|
---
|
168.4
|
||||||||
Other operation and maintenance
|
19.6
|
43.0
|
---
|
62.6
|
||||||||
Depreciation and amortization
|
10.0
|
20.7
|
---
|
30.7
|
||||||||
Impairment of assets
|
0.8
|
0.3
|
---
|
1.1
|
||||||||
Taxes other than income
|
6.8
|
2.8
|
---
|
9.6
|
||||||||
Operating income
|
$
|
45.2
|
$
|
19.2
|
$
|
---
|
$
|
64.4
|
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||
Gathered volumes – TBtu/d (A)
|
1.33
|
1.25
|
1.30
|
1.25
|
||||||||
Incremental transportation volumes – TBtu/d (B)
|
0.41
|
0.57
|
0.44
|
0.49
|
||||||||
Total throughput volumes – TBtu/d
|
1.74
|
1.82
|
1.74
|
1.74
|
||||||||
Natural gas processed – TBtu/d
|
0.83
|
0.70
|
0.78
|
0.67
|
||||||||
NGLs sold (keep-whole) – million gallons
|
50
|
26
|
92
|
48
|
||||||||
NGLs sold (purchased for resale) – million gallons
|
121
|
85
|
220
|
154
|
||||||||
NGLs sold (percent-of-liquids) – million gallons
|
8
|
9
|
15
|
17
|
||||||||
Total NGLs sold – million gallons
|
179
|
120
|
327
|
219
|
||||||||
Average sales price per gallon
|
$
|
0.86
|
$
|
0.66
|
$
|
0.94
|
$
|
0.64
|
||||
Estimated realized keep-whole spreads (C)
|
$
|
4.74
|
$
|
3.50
|
$
|
5.21
|
$
|
3.20
|
Ÿ●
|
lower crosshaul volumes as fewer customers moved natural gas to eastern markets in the second quarter of 2010 as there were smaller differences in natural gas prices at various U.S. market locations, which decreased the gross margin by approximately $3.3 million; and
|
Ÿ ●
|
an increase in the imbalance liability, net of fuel recoveries and natural gas length positions, which decreased the gross margin by approximately $1.6 million.
|
Ÿ
|
increased gross margin on keep-whole processing of approximately $12.0 million;
|
Ÿ
|
increased fixed processing fees of approximately $4.1 million; and
|
Ÿ
|
increased gross margin on NGLs retained under percent-of-liquids (“POL”) contracts of approximately $3.0 million.
|
Ÿ
|
an increase in condensate revenues associated with the gathering and processing operations due to increases in prices and volumes as a result of several new expansion projects with higher GPM gas, which increased the gross margin by approximately $2.7 million; and
|
Ÿ
|
increased gathering volumes associated with expansion projects, which increased the gathering fees by approximately $1.6 million.
|
Ÿ
|
decreased crosshaul volumes as fewer customers moved natural gas to eastern markets in the first half of 2010 as there were smaller differences in natural gas prices at various U.S. market locations, which decreased the gross margin by approximately $7.4 million;
|
Ÿ
|
an increase in the imbalance liability, net of fuel recoveries and natural gas length positions, which decreased the gross margin by approximately $2.4 million;
|
Ÿ
|
lower realized margins on operational storage hedges as the result of lower transacted volumes during the first half of 2010 as compared to the same period in 2009, which decreased the gross margin by approximately $2.3 million; and
|
Ÿ
|
decreased low/high pressure revenues due to a customer shipping its production through the Section 311 firm East side service, which decreased the gross margin by approximately $1.1 million.
|
Ÿ
|
capacity lease service under the MEP and Gulf Crossing capacity leases that were placed into service in June 2009 that increased transportation fees by approximately $6.3 million;
|
Ÿ
|
no adjustment of natural gas storage inventory during the first half of 2010 as compared to an approximate $5.8 million lower of cost or market adjustment to the natural gas storage inventory during the six months ended June 30, 2009 due to lower natural gas prices; and
|
Ÿ
|
implementation of the Section 311 firm East side service in April 2009 that increased transportation fees by approximately $1.1 million, net of an approximate $1.5 million refund for the second quarter 2010 service outage as maintenance activities were being conducted.
|
Ÿ
|
increased gross margin on keep-whole processing of approximately $17.9 million;
|
Ÿ
|
increased fixed processing fees of approximately $8.2 million; and
|
Ÿ
|
increased gross margin on NGLs retained under POL contracts of approximately $6.6 million.
|
Ÿ
|
an increase in condensate revenues associated with the gathering and processing operations due to increases in prices and volumes as a result of cooler weather in the first quarter of 2010 and several new expansion projects with higher GPM gas, which increased the gross margin by approximately $9.1 million;
|
Ÿ
|
higher volumes and realized margin on sales of physical natural gas long/short positions associated with gathering operations, which increased the gross margin by approximately $5.5 million, net of imbalance and fuel tracker obligations; and
|
Ÿ
|
increased gathered volumes associated with expansion projects, which increased the gathering fees by approximately $2.1 million.
|
Three Months Ended
|
Six Months Ended
|
|||||||||||
June 30,
|
June 30,
|
|||||||||||
2010
|
2009
|
2010
|
2009
|
|||||||||
(In millions)
|
||||||||||||
Operating revenues
|
$
|
189.0
|
$
|
117.2
|
$
|
434.7
|
$
|
309.5
|
||||
Cost of goods sold
|
192.9
|
116.6
|
437.2
|
304.4
|
||||||||
Gross margin on revenues
|
(3.9)
|
0.6
|
(2.5)
|
5.1
|
||||||||
Other operation and maintenance
|
2.1
|
2.7
|
4.8
|
5.3
|
||||||||
Taxes other than income
|
---
|
0.1
|
0.2
|
0.3
|
||||||||
Operating loss
|
$
|
(6.0)
|
$
|
(2.2)
|
$
|
(7.5)
|
$
|
(0.5)
|
●
|
smaller differences in natural gas prices at various U.S. market locations which resulted in a reduced spread that OERI was able to realize from delivering gas under its transportation contracts, which decreased the gross margin from transportation by approximately $5.1 million; and
|
●
|
lower realized gains on storage withdrawals, which decreased the gross margin by approximately $1.5 million.
|
(In millions)
|
Six Months Ended
June 30, 2010
Ongoing Earnings
|
Medicare Part D
Tax Subsidy
|
Six Months Ended
June 30, 2010
GAAP Net Income
|
Six Months Ended
June 30, 2009
GAAP and Ongoing
Net Income (A)
|
||||||||
OG&E
|
$
|
68.2
|
$
|
(7.0)
|
$
|
61.2
|
$
|
57.7
|
||||
Enogex
|
51.7
|
(2.0)
|
49.7
|
31.4
|
||||||||
Holding Company
|
(7.0)
|
(2.4)
|
(9.4)
|
(1.8)
|
||||||||
Consolidated
|
$
|
112.9
|
$
|
(11.4)
|
$
|
101.5
|
$
|
87.3
|
(A) There were no one-time charges for the six months ended June 30, 2009 therefore, ongoing and GAAP net income are the same.
|
(In millions)
|
Six Months Ended
June 30, 2010
Ongoing EPS
|
Medicare Part D
Tax Subsidy
|
Six Months Ended
June 30, 2010
GAAP EPS
|
Six Months Ended
June 30, 2009
GAAP and Ongoing
EPS (B)
|
||||||||
OG&E
|
$
|
0.69
|
$
|
(0.07)
|
$
|
0.62
|
$
|
0.60
|
||||
Enogex
|
0.52
|
(0.02)
|
0.50
|
0.33
|
||||||||
Holding Company
|
(0.07)
|
(0.02)
|
(0.09)
|
(0.02)
|
||||||||
Consolidated
|
$
|
1.14
|
$
|
(0.11)
|
$
|
1.03
|
$
|
0.91
|
Ÿ
|
the financial performance of Enogex’s assets without regard to financing methods, capital structure or historical cost basis;
|
Ÿ
|
Enogex’s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and
|
Ÿ
|
the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
|
Three Months Ended
|
Six Months Ended
|
||||||||||||
June 30,
|
June 30,
|
||||||||||||
(In millions)
|
2010
|
2009
|
2010
|
2009
|
|||||||||
Net income attributable to Enogex LLC
|
$
|
22.3
|
$
|
16.0
|
$
|
49.7
|
$
|
31.4
|
|||||
Add:
|
|||||||||||||
Interest expense, net
|
7.2
|
6.4
|
15.4
|
12.2
|
|||||||||
Income tax expense
|
13.9
|
9.8
|
34.2
|
19.5
|
|||||||||
Depreciation and amortization
|
17.9
|
15.9
|
35.7
|
30.7
|
|||||||||
EBITDA
|
$
|
61.3
|
$
|
48.1
|
$
|
135.0
|
$
|
93.8
|
Six Months Ended
|
||||||
June 30,
|
||||||
(In millions)
|
2010
|
2009
|
||||
Net cash provided from operating activities
|
$
|
341.5
|
$
|
186.9
|
||
Net cash used in investing activities
|
(291.6)
|
(472.9)
|
||||
Net cash (used in) provided from financing activities
|
(100.7)
|
323.8
|
Ÿ
|
an increase in cash receipts for sales at Enogex and OERI due to an increase in natural gas prices and NGLs prices and volumes in the first half of 2010 as compared to the same period in 2009;
|
Ÿ
|
an income tax refund received in February 2010 related to a carry back of the 2008 tax loss resulting from a change in tax method of accounting for capitalization of repairs expense;
|
Ÿ
|
a cash collateral payment to counterparties of OERI related to OERI’s NGLs hedge positions in the first half of 2009; and
|
Ÿ
|
cash received in the first half of 2010 from the implementation of rate increases and riders at OG&E.
|
Ÿ
|
an increase in payments for purchases at Enogex and OERI due to an increase in natural gas prices and NGLs prices and volumes in the first half of 2010 as compared to the same period in 2009; and
|
Ÿ
|
higher fuel refunds at OG&E in the first half of 2010 as compared to the same period in 2009.
|
Ÿ
|
repayment of the remaining balance of Enogex’s $400 million 8.125% senior notes which matured on January 15, 2010;
|
Ÿ
|
a decrease in short-term debt borrowings in the first half of 2010;
|
Ÿ
|
a decrease in the issuance of common stock in the first half of 2010; and
|
Ÿ
|
proceeds received from the issuance of $200 million of long-term debt at Enogex in June 2009.
|
Less than
|
|||||||||||||||
1 year
|
1-3 years
|
3-5 years
|
More than
|
||||||||||||
(In millions)
|
(2010)
|
(2011-2012)
|
(2013-2014)
|
5 years
|
Total
|
||||||||||
OG&E Base Transmission
|
$
|
45
|
$
|
40
|
$
|
35
|
$
|
20
|
$
|
140
|
|||||
OG&E Base Distribution
|
215
|
465
|
460
|
230
|
1,370
|
||||||||||
OG&E Base Generation
|
50
|
70
|
70
|
35
|
225
|
||||||||||
OG&E Other
|
25
|
50
|
50
|
25
|
150
|
||||||||||
Total OG&E Base Transmission, Distribution,
|
|||||||||||||||
Generation and Other
|
335
|
625
|
615
|
310
|
1,885
|
||||||||||
OG&E Known and Committed Projects:
|
|||||||||||||||
Transmission Projects:
|
|||||||||||||||
Sunnyside-Hugo (345 kV)
|
25
|
175
|
---
|
---
|
200
|
||||||||||
Sooner-Rose Hill (345 kV)
|
15
|
45
|
---
|
---
|
60
|
||||||||||
Windspeed (345 kV)
|
25
|
---
|
---
|
---
|
25
|
||||||||||
Balanced Portfolio 3E Projects
|
10
|
205
|
120
|
---
|
335
|
||||||||||
SPP Priority Projects (A)
|
---
|
230
|
100
|
---
|
330
|
||||||||||
Total Transmission Projects
|
75
|
655
|
220
|
---
|
950
|
||||||||||
Other Projects:
|
|||||||||||||||
Smart Grid Program (B)
|
40
|
120
|
60
|
10
|
230
|
||||||||||
Crossroads (C)
|
160
|
290
|
---
|
---
|
450
|
||||||||||
System Hardening
|
10
|
25
|
---
|
---
|
35
|
||||||||||
OU Spirit
|
10
|
---
|
---
|
---
|
10
|
||||||||||
Other
|
15
|
25
|
---
|
---
|
40
|
||||||||||
Total Other Projects
|
235
|
460
|
60
|
10
|
765
|
||||||||||
Total OG&E Known and Committed Projects
|
310
|
1,115
|
280
|
10
|
1,715
|
||||||||||
Total OG&E (D)
|
645
|
1,740
|
895
|
320
|
3,600
|
||||||||||
Enogex (Base Maintenance and Known
|
|||||||||||||||
and Committed Projects)
|
205
|
180
|
90
|
45
|
520
|
||||||||||
OGE Energy and OERI
|
20
|
50
|
50
|
25
|
145
|
||||||||||
Total capital expenditures
|
$
|
870
|
$
|
1,970
|
$
|
1,035
|
$
|
390
|
$
|
4,265
|
(C) These capital expenditures assume the 227.5 MW configuration.
|
Revolving Credit Agreements and Available Cash
|
||||||||
Aggregate
|
Amount
|
Weighted-Average
|
||||||
Entity
|
Commitment
|
Outstanding
|
Interest Rate
|
Maturity
|
||||
(In millions)
|
||||||||
OGE Energy
|
$
|
596.0
|
$
|
112.9
|
0.38%
|
December 6, 2012
|
||
OG&E
|
389.0
|
9.5
|
---%
|
December 6, 2012
|
||||
Enogex
|
250.0
|
65.0
|
0.66%
|
March 31, 2013
|
||||
1,235.0
|
187.4
|
0.46%
|
||||||
Cash
|
7.3
|
N/A
|
N/A
|
N/A
|
||||
Total
|
$
|
1,242.3
|
$
|
187.4
|
0.46%
|
June 30 (In millions)
|
2010
|
2009
|
||||
Commodity market risk, net
|
$
|
0.1
|
$
|
0.3
|
June 30 (In millions)
|
2010
|
2009
|
||||
Commodity market risk, net
|
$
|
10.9
|
$
|
4.9
|
Approximate Dollar
|
||||||||
Total Number of
|
Value of Shares that
|
|||||||
Shares Purchased as
|
May Yet Be
|
|||||||
Total Number of
|
Average Price Paid
|
Part of Publicly
|
Purchased Under the
|
|||||
Period
|
Shares Purchased
|
per Share
|
Announced Plan
|
Plan
|
||||
4/1/10 – 4/30/10
|
17,100
|
$
|
38.58
|
N/A
|
N/A
|
|||
5/1/10 – 5/31/10
|
114,100
|
$
|
38.12
|
N/A
|
N/A
|
|||
6/1/10 – 6/30/10
|
34,400
|
$
|
36.15
|
N/A
|
N/A
|
3.01
|
OGE Energy Corp. Restated Certificate of Incorporation.
|
|
3.02
|
OGE Energy Corp. Amended By-laws dated May 20, 2010.
|
|
4.01
|
Supplemental Indenture No. 11 dated as of June 1, 2010 between OG&E and UMB Bank, N.A., as trustee, creating the Senior Notes. (Filed as Exhibit 4.01 to OG&E’s Form 8-K filed June 8, 2010 (File No. 1-1097) and incorporated by reference herein)
|
|
31.01
|
Certifications Pursuant to Rule 13a-14(a)/15d-14(a) As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32.01
|
Certification Pursuant to 18 U.S.C. Section 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
99.01
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E’s Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed June 1, 2010 (File No. 1-12579) and incorporated by reference herein)
|
|
99.02
|
Copy of Settlement Agreement with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E’s Crossroads application. (Filed as Exhibit 99.01 to OGE Energy’s Form 8-K filed July 1, 2010 (File No. 1-12579) and incorporated by reference herein)
|
|
99.03
|
Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E’s Smart Grid application. (Filed as Exhibit 99.02 to OGE Energy’s Form 8-K filed July 7, 2010 (File No. 1-12579) and incorporated by reference herein)
|
|
99.04
|
Copy of OCC Order with Oklahoma Corporation Commission Staff, the Oklahoma Attorney General and others relating to OG&E’s Crossroads application.
|
|
101.INS
|
XBRL Instance Document.
|
|
101.SCH
|
XBRL Taxonomy Schema Document.
|
|
101.PRE
|
XBRL Taxonomy Presentation Linkbase Document.
|
|
101.LAB
|
XBRL Taxonomy Label Linkbase Document.
|
|
101.CAL
|
XBRL Taxonomy Calculation Linkbase Document.
|
|
101.DEF
|
XBRL Definition Linkbase Document.
|
OGE ENERGY CORP.
|
|
(Registrant)
|
|
By
|
/s/ Scott Forbes
|
Scott Forbes
|
|
Controller and Chief Accounting Officer
|
ARTICLE 1.
AMENDMENTS
Section 1.1. Amendment of By-Laws. Subject to the provisions of the Corporation’s Restated Certificate of Incorporation, these By-laws may be amended or repealed at any regular meeting of the shareholders (or at any special meeting thereof duly called for that purpose) by the holders of at least a majority of the voting power of the shares represented and entitled to vote thereon at such meeting at which a quorum is present; provided that in the notice of such special meeting notice of such purpose shall be given. Subject to the laws of the State of Oklahoma, the Corporation’s Restated Certificate of Incorporation and these By-laws, the Board of Directors may by majority vote of those present at any meeting at which a quorum is present amend these By-laws, or
adopt such other By-laws as in their judgment may be advisable for the regulation of the conduct of the affairs of the Corporation.
ARTICLE 2.
OFFICES
Section 2.1. Registered Office. The Corporation shall continuously maintain a registered office in the State of Oklahoma which may, but need not be, the same as its place of business, and a registered agent whose business office is identical with such registered office.
Section 2.2. Other Offices. The Corporation may also have offices at such other places both within and without the State of Oklahoma as the Board of Directors may from time to time determine or the business of the corporation may require.
ARTICLE 3.
SHARES
Section 3.1. Form of Shares. Shares either shall be represented by certificates or shall be uncertificated shares.
3.1.1. Signing of Certificates. Certificates representing shares of the corporation shall be signed by the appropriate officers and may be sealed with the seal or a facsimile of the seal of the Corporation if the corporation uses a seal. If a certificate is countersigned by a transfer agent or registrar, other than an employee of the corporation, any other signatures may be
|
facsimile. Each certificate representing shares shall be consecutively numbered or otherwise identified, and shall also state the name of the person to whom issued, the number and class of shares (with designation of series, if any), the date of issue, that the corporation is organized under Oklahoma law, and any other information required by law.
3.1.2. Uncertificated Shares. Unless prohibited by the Restated Certificate of Incorporation, the Board of Directors may provide by resolution that some or all of any class or series of shares shall be uncertificated shares. Any such resolution shall not apply to shares represented by a certificate until the certificate (or such documentation as may be allowed under Section 3.2 below) has been surrendered to the Corporation. Within a reasonable time after the issuance or transfer of uncertificated shares, the Corporation shall send the registered owner thereof a written notice of all information that would appear on a certificate. Except as otherwise expressly provided by law, the rights and obligations of the holders of uncertificated shares shall be identical to those
of the holders of certificates representing shares of the same class and series.
3.1.3. Identification of Shareholders. The name and address of each shareholder, the number and class of shares held and the date on which the shares were issued shall be entered on the books of the Corporation. The person in whose name shares stand on the books of the Corporation shall be deemed the owner thereof for all purposes as regards the Corporation.
Section 3.2. Lost. Stolen or Destroyed
|
Certificates. If a certificate representing shares has allegedly been lost, stolen or destroyed, the Board of Directors may in its discretion, except as may be required by law, direct that a new certificate be issued upon such identification and other reasonable requirements as it may impose.
Section 3.3. Transfers of Shares. Transfer of shares of the Corporation shall be recorded on the books of the Corporation. Transfer of shares represented by a certificate, except in the case of a lost or destroyed certificate, shall be made on surrender for cancellation of the certificate for such shares. A certificate presented for transfer must be duly endorsed and accompanied by proper guaranty of signature or other appropriate assurances that the endorsement is effective. Transfer of an uncertificated share shall be made on receipt by the Corporation of an instruction from the registered owner or other appropriate person. The instruction shall be in writing or a communication in such form as may be agreed upon in writing by the Corporation.
ARTICLE 4.
SHAREHOLDERS
Section 4.1. Annual Meeting. The annual meeting of the shareholders for the election of directors and the transaction of any other proper business shall be held at a time and date to be annually designated by the Board of Directors.
Section 4.2. Special Meetings. Except as otherwise mandated by Oklahoma law and except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, special meetings of shareholders of the Corporation may be called only by the Board of Directors pursuant to a resolution approved by a majority of the entire Board of Directors or by the President of the Corporation.
Section 4.3. Place of Meeting. The Board of Directors may designate the place of meeting for any annual or special meeting of shareholders. In the absence of any such designation, the place of meeting shall be the principal place of business of the Corporation.
Section 4.4. Notice of Meetings. For all meetings of shareholders, a written or printed notice of the meeting shall be delivered, personally or by mail, to each shareholder of record entitled to vote at such meeting, which notice shall state the place, date and hour of the meeting. For all special meetings and when and as otherwise required by law, the notice shall state the
|
purpose or purposes of the meeting. The notice of the meeting shall be given not less than 10 nor more than 60 days before the date of the meeting, or in the case of a meeting involving a merger, consolidation, share exchange, dissolution or sale, lease or an exchange of all or substantially all, of the property or assets of the corporation not less than 20 nor more than 60 days before the date of such meeting. If mailed, such notice shall be deemed to have been delivered when deposited in the United States mail, postage prepaid, directed to the shareholder at his or her address as it appears on the records of the corporation. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting if the time and place thereof are announced at the meeting at which the adjournment is taken unless otherwis
e required by law.
Section 4.5. Quorum of Shareholders. The holders of a majority of the outstanding shares of the corporation entitled to vote, present in person or represented by proxy, shall constitute a quorum at any meeting of shareholders unless a greater or lesser number is required by the certificate of incorporation. At any adjourned meeting at which a quorum is present or represented, any business may be transacted which might have been transacted at the original meeting, unless otherwise required by law. Withdrawal of shareholders from any meeting shall not cause failure of a duly constituted quorum at the meeting, unless otherwise required by law.
Section 4.6. Manner of Acting. The affirmative vote of holders of a majority of the shares represented at a meeting and entitled to vote on a matter at which a quorum is present shall be valid action by the shareholders, unless voting by a greater number of shareholders or voting by class or classes of shareholders is required by law or the certificate of incorporation.
Section 4.7. Fixing of Record Date. If no record date is fixed for the determination of shareholders entitled to notice of or to vote at a meeting of shareholders, or shareholders entitled to receive payment of a dividend, or in order to make a determination of shareholders for any other proper purpose, the date on which notice of the meeting is mailed or the date on which the resolution of the Board of Directors declaring such dividend is adopted, as the case may be, shall be the record date for such determination of shareholders. If a record date is specifically set for the purpose of determining shareholders entitled to notice of or to vote at any meeting of shareholders, or shareholders entitled to receive payment of any dividend, or in order to make a determination
of shareholders for any other proper purpose, the Board of Directors may fix in advance a
|
date as the record date for any such determination of shareholders, such date in any case to be not more than 60 days (or such longer period as is then permitted by Oklahoma law) and, for a meeting of shareholders, not less than 10 days, or in the case of a merger, consolidation, share exchange, dissolution or sale, lease or exchange of assets, not less than 20 days, immediately preceding such meeting. When a determination of shareholders entitled to vote at any meeting of shareholders has been made as provided in this Section, such determination shall apply to any adjournment thereof.
Section 4.8. Voting Lists. The officer or agent having charge of the transfer book for shares of the Corporation shall make, within 20 days after the record date for a meeting of shareholders or 10 days before such meeting, whichever is earlier, a complete list of the shareholders entitled to vote at such meeting, arranged in alphabetical order, with the address of and the number of shares held by each, which list, for a period of 10 days prior to such meeting, shall be kept on file at the registered office of the corporation and shall be subject to inspection by any shareholders, and to copying at the shareholder’s expense, at any time during usual business hours. Such list shall also be produced and kept open at the time and place of the meeting and shall be subj
ect to the inspection of any shareholder during the whole time of the meeting. The original share ledger or transfer book, or a duplicate thereof kept in the State of Oklahoma, shall be prima facie evidence as to who are the shareholders entitled to examine such list or share ledger or transfer book or to vote at any meeting of shareholders.
Section 4.9. Proxies. A shareholder may appoint a proxy to vote or otherwise act for him or her by signing an appointment form and delivering it to the person so appointed. All appointments of proxies shall be in accordance with Oklahoma law. An appointment of a proxy is revocable by the shareholder unless the appointment form conspicuously states that it is irrevocable and the appointment is coupled with an interest in the shares or in the corporation generally.
Section 4.10. Voting of Shares by Certain Holders. Shares of a corporation held by the Corporation in a fiduciary capacity may be voted and shall be counted in determining the total number of outstanding shares entitled to vote at any given time.
4.10.1. Shares Held by Corporation. Shares registered in the name of another corporation, domestic or foreign, may be voted by any officer, agent, proxy or other legal representative authorized to vote such shares under the laws of the state of incorporation of such corporation. This Corporation shall treat the president or other person holding the chief executive office of
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such other corporation as authorized to vote such shares. However, such other corporation may designate any other person or any other holder of an office of the corporate shareholder to this Corporation as the person or officeholder authorized to vote such shares. Such persons or offices indicated shall be registered by this Corporation on the transfer books for shares and included in any voting list prepared in accordance with Section 4.8 of this Article.
4.10.2. Shares Held by Fiduciary. Shares registered in the name of a deceased person, a minor ward or a person under legal disability may be voted by his or her administrator, executor, or court appointed guardian, either in person or by proxy, without a transfer of such shares into the name of such administrator, executor, or court appointed guardian. Shares registered in the name of a trustee may be voted by him or her, either in person or by proxy.
4.10.3. Shares Held by Receiver. Shares registered in the name of a receiver may be voted by such receiver, and shares held by or under the control of a receiver may be voted by such receiver without the transfer thereof into his or her name if authority to do so is contained in an appropriate order of the court by which such receiver was appointed.
4.10.4. Shares Pledged. A shareholder whose shares are pledged shall be entitled to vote such shares until the shares have been transferred into the name of the pledgee, and thereafter the pledgee shall be entitled to vote the shares so transferred.
Section 4.11. Inspectors. At any meeting of shareholders, the chairman of the meeting may, or upon the request of any shareholder shall, appoint one or more persons as inspectors for such meeting. Inspectors shall:
4.11.1. Vote Count and Report. Determine the validity and effect of proxies; ascertain and report the number of shares represented at the meeting; count all votes and report the results; and perform such other acts as are required and appropriate to conduct all elections with impartiality and fairness to the shareholders.
4.11.2. Written Reports. Each report shall be in writing and such report shall be signed by the inspector or by a majority of them if there be more than one inspector acting at such meeting. If there is more than one inspector, the report of a majority shall be the report of the inspectors. The report of the inspector or inspectors on the number of shares represented at the meeting and the results of the voting shall be prima facie evidence thereof.
Section 4.12. Informal Action by Shareholders. Any action required or permitted to be taken by the shareholders of the Corporation must be effected at a duly called annual or special meeting of such holders
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and, except as otherwise mandated by Oklahoma law, may not be effected without such a meeting by any consent in writing by such holders.
Section 4.13. Waiver of Notice. Whenever any notice whatever is required to be given under the provisions of the law, the certificate of incorporation or these By-laws, a waiver thereof in writing signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of such notice. Attendance at any meeting shall constitute waiver of notice thereof unless the person at the meeting objects to the holding of the meeting because proper notice was not given.
Section 4.14. Notice of Shareholder Business. At an annual meeting of the shareholders, only such business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise properly be requested to be brought before the meeting by a shareholder. For business to be properly requested to be brought before an annual meeting by a shareholder, the shareholder must have given timely notice thereof in writing to the Secretary of the Corporation. To be timely, a s
hareholder’s notice must be delivered to or mailed and received at the principal executive offices of the Corporation, not less than 90 days prior to the meeting; provided, however, that in the event that the date of the meeting is not publicly announced by the Corporation by mail, press release or otherwise more than 90 days prior to the meeting, notice by the shareholder to be timely must be delivered to the Secretary of the Corporation not later than the close of business on the seventh day following the day on which such announcement of the date of the meeting was communicated to shareholders. A shareholder’s notice to the Secretary shall set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and address, as they appear on the Corporation’s books, of the shareholder proposing such busines
s, (c) the class and number of shares of the Corporation which are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. Notwithstanding anything in the By-laws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section 4.14. The Chairman of an annual meeting shall, if the facts
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warrant, determine and declare to the meeting that business was not properly brought before the meeting and in accordance with the provisions of this Section 4.14, and if he should so determine, he shall so declare to the meeting that any such business not properly brought before the meeting shall not be transacted.
ARTICLE 5.
DIRECTORS
Section 5.1. General Powers and Qualification. The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors. Directors need not be residents of the State of Oklahoma or shareholders of the Corporation.
Section 5.2. Number. Tenure and Resignation. The number of directors of the Corporation shall be fixed from time to time by the Board of Directors, but shall be no more than 15; provided, however, that no decrease in the number of directors shall have the effect of shortening the term of any incumbent director. Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Corporation’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, the directors elected at or prior to the annual meeting of shareholders in
2010 shall be classified, with respect to the time for which they severally hold office, into three classes, as nearly equal in number as possible, with each class of directors to serve for a term expiring at the annual meeting of shareholders held in the third year following the year of their election and until their successors are elected and qualified, subject to earlier death, resignation or removal. At each annual meeting of the shareholders after the annual meeting of shareholders in 2010 and except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Corporation’s Common Stock as to dividends or upon liquidation to elected directors under specified circumstances, the directors shall be elected for terms expiring at the next annual meeting of shareholders and until their successors a
re elected and qualified, subject to earlier death, resignation or removal; provided that the directors elected at or prior to the 2010 annual meeting of shareholders shall continue to serve until their terms expire. In each case, directors shall hold office until their successors are elected and qualified.
Advance notice of shareholder nominations for the election of directors shall be given in the manner provided in Section 5.3 of this Article 5.
Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the
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Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Corporation’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances: (i) newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause shall be filled by the affirmative vote of a majority of the remaining directors then in office, even though less than quorum of the Board of Directors, (ii) any director elected in accordance with the preceding clause (i) shall hold office until the next annual meeting of shareholders and until such director’s successor shall have been elected and qu
alified and (iii) no decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director.
Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Corporation’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, any director may be removed from office, with or without cause, only by the affirmative vote of the holders of at least a majority of the combined voting power of the then outstanding shares of the Corporation’s stock entitled to vote generally (as defined in Article VII of the Corporation’s Restated Certificate of Incorporation), voting together as a single class.
Section 5.3. Notification of Nominations. Except as may otherwise be provided in or fixed by or pursuant to the provisions of Article IV of the Corporation’s Restated Certificate of Incorporation relating to the rights of the holders of any class or series of stock having a preference over the Corporation’s Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, nominations for the election of directors may be made by the Board of Directors or a committee appointed by the Board of Directors or by any shareholder entitled to vote in the election of directors generally. However, any shareholder entitled to vote in the election of directors generally may nominate one or more persons for election as directors at a
meeting only if written notice of such shareholder’s intent to make such nomination or nominations has been given, either by personal delivery or by United States mail, postage prepaid, to the Secretary of the Corporation not later than (i) with respect to an election to be held at an annual meeting of shareholders, 90 days in advance of such meeting, and (ii) with respect to an election to be held at a special meeting of stockholders for the election of directors, the
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close of business on the seventh day following the date on which notice of such meeting is first given to shareholders. Each such notice shall set forth (a) the name and address of the shareholder who intends to make the nomination and of the person or persons to be nominated; (b) a representation that the shareholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice; (c) a description of all arrangements or understandings between the shareholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the shareholder; (d) such other information regarding each nominee proposed by such shareholder as woul
d be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission, had the nominee been nominated, or intended to be nominated, by the Board of Directors; and (e) the consent of each nominee to serve as a director of the Corporation if so elected. The Chairman of the meeting may refuse to acknowledge the nomination of any person not made in compliance with the foregoing procedure. A director may resign at any time by written notice to the board, its chairman, or the president or secretary of the Corporation. The resignation is effective on the date it bears, or its designated effective date.
Section 5.4. Quorum of Directors. A majority of the number of directors fixed in Section 5.2 of this Article shall constitute a quorum for the transaction of business at any meeting of the Board of Directors; provided, however, that if less than a majority of the number of directors fixed in Section 5.2 of this Article is present at a meeting, a majority of the directors present may adjourn the meeting at any time without further notice, unless otherwise required by law.
Section 5.5. Manner of Acting. The act of a majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors, unless the act of a greater number is required by law or these By-laws.
Section 5.6. Regular Meetings. Regular meetings of the Board of Directors may be held without notice at such time and place as shall from time to time be determined by the Board of Directors.
Section 5.7. Special Meetings. Special meetings of the Board of Directors may be called by or at the request of the Chairman of the Board or any two directors. The person or persons authorized to call special meetings of the Board of Directors may fix the place for holding any special meeting of the Board of Directors called by them.
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Section 5.8. Notice. Notice of any special meeting of the Board of Directors shall be given at least one day prior to the meeting by written notice delivered personally, by mail, cable, facsimile, telegram, or telex to each director at his or her business address. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Board of Directors need be specified in the notice or waiver of notice of such meeting. The attendance of a director at any meeting shall constitute a waiver of notice of such meeting, except where a director attends a meeting for the express purpose of objecting to the transaction of any business because the meeting is not lawfully called or convened.
Section 5.9. Presumption of Assent. A director of the Corporation who has been present at a meeting of the Board of Directors at which action on any corporate matter is taken shall be conclusively presumed to have assented to the action taken, unless his or her dissent shall have been entered in the minutes of the meeting or unless he or she shall have filed his or her written dissent to such action with the person acting as the secretary of the meeting before the adjournment thereof, or shall have forwarded such dissent by registered mail or certified mail to the Secretary of the Corporation immediately after the adjournment of the meeting. No director who voted in favor of any action may dissent from such action after adjournment of the meeting.
Section 5.10. Committees. A majority of the directors may, by resolution passed by a majority of the number of directors fixed by the shareholders under Section 5.2 of this Article, create one or more committees and appoint members of the board to serve on the committee or committees. Each committee shall have two or more members, who serve at the pleasure of the board. To the extent specified in the resolution of the Board of Directors establishing a committee each committee shall have and exercise all the authority of the Board of Directors, provided, however, that no such committee shall have the authority to take any action that under Oklahoma law can only be taken by the Board of Directors.
Section 5.11. Informal Action by Directors. Any action required by the Oklahoma General Corporation Act to be taken at a meeting of the Board of Directors of the Corporation, or any other action which may be taken at a meeting of the Board of Directors or a committee thereof, may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by all of the directors entitled to vote with respect to the subject matter thereof, or by all members of such committee, as the case may be.
5.11.1. Effective Date. The consent shall be evidenced by one or more written approvals, each of
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which sets forth the action taken and bears the signature of one or more directors. All the approvals evidencing the consent shall be delivered to the secretary to be filed in the corporate records. The action taken shall be effective when all the directors or all members of a committee have approved the consent unless the consent specifies a different effective date.
5.11.2. Effect of Consent. Any consent signed by all the directors or all the members of a committee shall have the same effect as a unanimous vote, and may be stated as such in any document filed with the Secretary of State under the Oklahoma General Corporation Law.
Section 5.12. Meeting by Conference Telephone. Members of the Board of Directors or of any committee of the Board of Directors may participate in and act at any meeting of the board or committee by means of conference telephone or other communications equipment through which all persons participating in the meeting can hear each other. Participation in such a meeting shall be equivalent to attendance and presence in person at the meeting of the person or persons so participating.
Section 5.13. Compensation. The Board of Directors, by the affirmative vote of a majority of the directors then in office, and irrespective of any personal interest of any of its members, shall have authority to establish reasonable compensation of all directors for services to the Corporation as directors, officers, or otherwise.
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ARTICLE 6.
OFFICERS
Section 6.1. Number. The officers of the Corporation may consist of a Chairman of the Board, a President, one or several vice presidents, a treasurer, one or more assistant treasurers (if elected by the Board of Directors), a secretary, one or more assistant secretaries (if elected by the Board of Directors), and such other officers as may be elected in accordance with the provisions of this Article. Any two or more offices may be held by the same person.
Section 6.2. Election and Term of Office. The officers of the Corporation shall be elected annually by the Board of Directors at the first meeting of the Board of Directors held after each annual meeting of shareholders. If the election of officers shall not be held at such meeting, such election shall be held as soon thereafter as reasonably practicable. Subject to the provisions of Section 6.3 hereof, each officer shall hold office until the last to occur of the next annual meeting of the Board of Directors or until the election and qualification of his or her successor.
Section 6.3. Removal of Officers. Any officer elected or appointed by the Board of Directors may be removed by the Board of Directors whenever in its judgment the best interests of the Corporation would be served thereby, but such removal shall be without prejudice to the contract rights, if any, of the person so removed.
Section 6.4. Vacancies; New Offices. A vacancy occurring in any office may be filled and new offices may be created and filled, at any time, by the Board of Directors.
Section 6.5. Chairman of the Board and Chief Executive Officer. The Chairman of the Board shall be the chief executive officer of the Corporation. He or she shall be in charge of the day to day business and affairs of the Corporation, subject to the direction and control of the Board of Directors and shall have the general powers and duties of supervision and management usually vested in the position of Chief Executive Officer. He or she shall preside at all meetings of the Board of Directors. He or she shall have the power to appoint such agents and employees as in his or her judgment may be necessary or proper for the transaction of the business of the Corporation. He or she may sign: (i) with the secretary or other proper officer of the Corporation thereunto authorize
d by the Board of Directors, stock certificates of the Corporation the issuance of which shall have been authorized by the Board of Directors; and (ii) any contracts, deeds, mortgages, bonds, or other instruments which the Board of Directors has authorized to be executed, according to the requirements of the form of the instrument.
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Section 6.6. President. The President shall assist the Chairman of the Board in the discharge of his or her duties as the Chairman of the Board may direct, and shall perform such other duties from time to time as may be assigned to him or her by the Chairman of the Board or the Board of Directors. In the absence of the Chairman of the Board or in the event of his or her inability to act, the President shall perform the duties and exercise the authority of the Chairman of the Board.
Section 6.7. Vice President(s). The vice president (or in the event there is more than one vice president, each of them) shall assist the Chairman of the Board and the President in the discharge of his or her respective duties as the Chairman of the Board or the President may direct, and shall perform such other duties as from time to time may be assigned to him or her (or them) by the Chairman of the Board, the President or the Board of Directors. In the absence of the President or in the event of his or her inability to act, the vice president (or vice presidents, in the order of their election), shall perform the duties and exercise the authority of the President.
Section 6.8. Treasurer. The treasurer shall have charge and custody of and be responsible for all funds and securities of the Corporation, receive and give receipts for moneys due and payable to the Corporation from any source whatsoever, and deposit all such moneys in the name of the Corporation in such banks, trust companies or other depositaries as shall be selected in accordance with the provisions of Article 7 of these By-laws, have charge of and be responsible for the maintenance of adequate books of account for the Corporation, and, in general, perform all duties incident to the office of treasurer and such other duties not inconsistent with these By-laws as from time to time may be assigned to him or her by the Chairman of the Board, the President or the Board of
Directors.
Section 6.9. Secretary. The secretary shall keep the minutes of the shareholders’ and the Board of Directors’ meetings, see that all notices are duly given in accordance with the provisions of these By-laws or as required by law, have general charge of the corporate records and of the seal of the Corporation, have general charge of the stock transfer books of the Corporation, keep a register of the post office address of each shareholder which shall be furnished to the secretary by such shareholder, sign with the Chairman of the Board, the President, or any other officer thereunto authorized by the Board of Directors, certificates for shares of the Corporation, the issuance of which shall have been authorized by the Board of Directors, and any contracts, deed
s, mortgages, bonds, or other instruments which the Board of Directors has authorized to be executed,
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according to the requirements of the form of the instrument, and, in general, perform all duties incident to the office of secretary and such other duties not inconsistent with these By-laws as from time to time may be assigned to him or her by the Chairman of the Board, the President or the Board of Directors.
Section 6.10. Assistant Treasurers and Assistant Secretaries. The Board of Directors may elect one or more than one assistant treasurer and assistant secretary. In the absence of the treasurer or in the event of his or her inability to act, the assistant treasurers, in the order of their election, shall perform the duties and exercise the authority of the treasurer. In the absence of the secretary or in the event of his or her inability to act, the assistant secretaries, in the order of their election, shall perform the duties and exercise the authority of the secretary. The assistant treasurers and assistant secretaries, in general, shall perform such other duties not inconsistent with these By-laws as shall be assigned to them by the treasurer or the secretary, respectively, o
r by the Chairman of the Board, the President or the Board of Directors.
Section 6.11. Compensation. The compensation of all directors and officers shall be fixed from time to time by the Board of Directors. No officer shall be prevented from receiving such compensation by reason of the fact that he or she is also a director of the Corporation. All compensation so established shall be reasonable and solely for services rendered to the Corporation.
ARTICLE 7.
FISCAL MATTERS
Section 7.1. Fiscal Year. The fiscal year of the Corporation shall begin on the first day of January in each year.
Section 7.2. Contracts. The Board of Directors may authorize any officer or officers, agent or agents, to enter into any contract or execute and deliver any instrument, in the name of and on behalf of the Corporation, and such authority may be general or confined to specific instances.
Section 7.3. Loans and Indebtedness. No substantial or material loans shall be contracted on behalf of the Corporation and no evidences of indebtedness shall be issued in its name unless authorized by a resolution of the Board of Directors. Such authority may be general or confined to specific instances.
Section 7.4. Checks. Drafts. Etc. All checks, drafts or other orders for the payment of money, notes or other evidences of indebtedness issued in the name of the Corporation shall be signed by such officer or officers, agent or agents of the Corporation as the Board
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of Directors shall from time to time designate.
Section 7.5. Deposits. All funds of the Corporation not otherwise employed shall be deposited from time to time to the credit of the Corporation in such banks, trust companies or other depositaries as the Chairman of the Board, the President, the Treasurer or the Board of Directors may select.
ARTICLE 8.
GENERAL PROVISIONS
Section 8.1. Dividends and Distributions. The Board of Directors may from time to time declare or otherwise authorize, and the Corporation may pay distributions in money, shares or other property on its outstanding shares in the manner and upon the terms, conditions and limitations provided by law or certificate of incorporation.
Section 8.2. Corporate Seal. The Board of Directors may provide a corporate seal which shall be in the form of a circle and shall have inscribed thereon the name of the Corporation and the words “Corporate Seal, Oklahoma.” The seal may be used by causing it or a facsimile thereof to be impressed or affixed or in any manner reproduced.
Section 8.3. Waiver of Notice. Whenever any notice is required to be given by law, certificate of incorporation or under the provisions of these By-laws, a waiver thereof in writing, signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of such notice.
Section 8.4. Headings. Section or paragraph headings are inserted herein only for convenience of reference and shall not be considered in the construction of any provision hereof.
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ARTICLE 9.
EMERGENCY BY-LAWS
Section 9.1. Emergency By-Laws. The emergency by-laws provided in this Article 9 shall be operative during any emergency resulting from an attack on the United States or on or during any nuclear or atomic disaster, or during the existence of any catastrophe, or other similar emergency condition, as a result of which a quorum of the Board of Directors cannot readily be convened for action. To the extent not inconsistent with these emergency by-laws, the By-Laws of the Corporation shall remain in effect during any emergency and upon its termination these emergency by-laws shall cease to be operative.
Section 9.2. Meetings. During any such emergency, a meeting of the Board of Directors may be called by any officer or director by giving two days’ notice thereof to such of the directors as it may be feasible to reach at the time and by such means as may be feasible at the time. The notice shall specify the time and the place of the meeting, which shall be the principal executive offices of the Corporation or any other place specified in the notice. At any such meeting, three members of the then existing Board of Directors shall constitute a quorum, which may act by majority vote.
Section 9.3. Temporary Directors. If the number of directors who are available to act shall drop below three, additional directors, in whatever number is necessary to constitute a Board of three Directors, shall be selected automatically from the first available officers or employees in the order provided in the emergency succession list established by the Board of Directors and in effect at the time an emergency arises. Additional directors, beyond the minimum number of three directors, but not more than three additional directors, may be elected from any officers or employees on the emergency succession list.
Section 9.4. Authority. The Board of Directors is empowered with the maximum authority possible under the Oklahoma General Corporation Act, and all other applicable law, to conduct the interim management of the affairs of the Corporation in an emergency in what it considers to be in the best interests of the Corporation (including the right to amend this Article) irrespective of the provisions of the Restated Certificate of Incorporation or of the By-Laws.
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Section 9.5 Liability. No officer, director or employee acting in accordance with this Article 9 shall be liable except for willful misconduct.
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/s/ Peter B. Delaney
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Peter B. Delaney
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Chairman of the Board, President and
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Chief Executive Officer
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/s/ Sean Trauschke
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Sean Trauschke
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Vice President and Chief Financial Officer
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1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/
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Peter B. Delaney
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Peter B. Delaney
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Chairman of the Board, President and
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Chief Executive Officer
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/s/
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Sean Trauschke
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Sean Trauschke
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Vice President and Chief Financial Officer
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IN THE MATTER OF THE APPLICATION OF
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)
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OKLAHOMA GAS AND ELECTRIC COMPANY
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)
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FOR AN ORDER GRANTING PRE-APPROVAL
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)
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TO CONSTRUCT THE CROSSROADS WIND
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)
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CAUSE NO. PUD 201000037
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FARM, AND AUTHORIZING A RECOVERY
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)
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RIDER
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)
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ORDER NO.
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HEARING:
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July 14, 2010, in Courtroom 301
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2101 North Lincoln Blvd., Oklahoma City, OK 73105
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Before the Commission en banc and Jacqueline T. Miller, Referee
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APPEARANCES:
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James L. Myles, Deputy General Counsel, representing Public
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Utility Division, Oklahoma Corporation Commission
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William J. Bullard, Kimber L. Shoop, and Stephanie G. Houle, Attorneys,
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representing Oklahoma Gas and Electric Company
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William L. Humes and Elizabeth Ryan, Assistant Attorneys General,
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representing Office of Attorney General, State of Oklahoma
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Thomas P. Schroedter, James D. Satrom, and J. Fred Gist, Attorneys,
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representing Oklahoma Industrial Energy Consumers
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Jack G. Clark, Jr. and Ronald E. Stakem, Attorneys, representing OG&E
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Shareholders Association
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Richard K. Goodwin, Attorney, representing Chermac Energy
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Corporation
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1.
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Applicant OG&E, requested in its Application that the Commission find that Crossroads is a prudent investment for OG&E; that the Crossroads Wind Farm Facility will be “used and useful” when placed in service; that OG&E be permitted to implement a recovery rider so that the costs of Crossroads can be recovered as the turbines are placed in service; and that it is appropriate to approve a waiver from the Commission’s competitive procurement rules.
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2.
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Applicant submitted pre-filed testimony of Jesse B. Langston, K. Wayne Walker and Bryan J. Scott in this cause; supplemental testimonies of Mr. Langston and Mr. Scott supporting and recommending approval of the Settlement Agreement; testimony summaries of all testimony filed by its witnesses in this cause; and oral testimony of Mr. Langston and Mr. Scott supporting approval of the Settlement Agreement.
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3.
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Mr. Langston testified that the company believes the terms of the Settlement Agreement represent a fair, just and
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PUD 201000037-FINAL ORDER | Page 2 of 13 |
1.
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PUD submitted pre-filed testimony of Frank Mossburg and Craig Roach in this cause and also filed supplemental testimony of Mr. Roach supporting and recommending approval of the Settlement Agreement and testimony summaries of the pre-filed testimonies of Mr. Roach and Mr. Mossburg, and Mr. Roach’s supplemental testimony.
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2.
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PUD provided the oral testimony of Mr. Roach recommending approval of the Settlement Agreement as a fair, just and reasonable resolution of the matters in this cause and stating that the Settlement Agreement is in the public interest and that OG&E has demonstrated a need for Crossroads.
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1.
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William L. Humes, Assistant Attorney General, on behalf of the Attorney General, filed the pre-filed testimony of Mr. Daniel Peaco.
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2.
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The Attorney General did not submit testimony addressing the Settlement Agreement, but recommended approval of the Settlement Agreement as a fair, just and reasonable resolution of the matters in this cause and stated that the record demonstrates a need for Crossroads and that approval of the Settlement Agreement is in the public interest.
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1.
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OIEC, Intervenor, submitted pre-filed testimony of Mr. Scott Norwood and participated in the hearing.
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2.
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OIEC did not submit testimony addressing the Settlement Agreement, but recommended approval of the Settlement Agreement as a fair, just and reasonable resolution of the matters in this cause and stated that the record demonstrates a need for Crossroads and that approval of the Settlement Agreement is in the public interest.
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3.
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Ronald E. Stakem, Attorney, representing OG&E Shareholders, Intervenor, filed a Statement of Position and participated in the hearing.
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4.
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OG&E Shareholders recommended approval of the Settlement Agreement as a fair, just and reasonable resolution of the matters in this cause and stated that the record demonstrates a need for Crossroads and that approval of the Settlement Agreement is in the public interest.
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5.
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Chermac, Intervenor, filed a Statement of Position.
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6.
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Chermac recommended approval of the Settlement Agreement as a fair, just and reasonable resolution of the matters in this cause.
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PUD 201000037-FINAL ORDER | Page 3 of 13 |
PUD 201000037-FINAL ORDER | Page 4 of 13 |
1.
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Kimber L. Shoop, attorney for the Applicant, announced that notice of this cause was published in accordance with the notice requirements directed by the Commission in Order No. 576086.
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1.
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Jesse Langston, Vice-President, Utility Commercial Operations, filed pre-filed Direct Testimony on behalf of OG&E on April 8, 2010, and Supplemental Testimony Supporting the Joint Stipulation and Settlement Agreement on July 8, 2010. He stated that the purpose of his Supplemental Testimony was to sponsor the Joint Stipulation and Settlement Agreement executed by the Stipulating Parties on June 28, 2010. In addition, during the hearing, Mr. Langston provided some background on the Crossroads project.
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2.
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First, Mr. Langston described the Crossroads project. He testified that Crossroads is an 86-turbine, 197.8 MW wind-powered electric generation facility located in Dewey County, Oklahoma. He stated that the Crossroads facility is expected to come on-line during the second half of 2011 and will interconnect to OG&E’s new 345 kV Woodward to Oklahoma City transmission line (“Windspeed”). He testified that the Crossroads facilities will utilize Siemens Energy SWT-2.3-101 wind turbine generators each with a nameplate rating of 2.3 MW. Mr. Langston further testified that each turbine will have a 101-meter rotor diameter and will be supported by an 80-meter tower (262 feet). Mr. Langston explained that this 101 meter rotor diameter is larger than the 93 meter rotor diameter on the OU Spirit turbines and such additional length blades impro
ves the energy output for each unit. Mr. Langston testified that a separate interconnection request has been made with the Southwest Power Pool (“SPP”) for an incremental 29.7 MWs of wind turbines to be located on the same site. He stated that if the additional 29.7 MWs are included, the Crossroads facility would have a capacity of 227.5 MW.
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3.
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Mr. Langston explained that OG&E has executed definitive agreements with Siemens for the supply and erection of turbines and with RES Americas for the preparation of the site and construction of the balance of the plant (“Balance of Plant”). He also gave a brief description of both RES Americas and Siemens. With regard to the agreement with Siemens, Mr. Langston explained that under the Siemens Turbine Supply Agreement, Siemens is obligated to solicit bids to manufacture components of the turbines in Oklahoma, including a specific requirement related to DMI Industries, which has manufacturing facilities for the production of wind towers in Tulsa, Oklahoma and is a Siemens qualified vendor. In addition, Mr. Langston explained that Siemens has agreed
to jointly engage in discussions with Oklahoma State University, the University of Oklahoma, and the High Plains Technology Center Tech Partnership, and potentially
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PUD 201000037-FINAL ORDER | Page 5 of 13 |
4.
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Mr. Langston testified that the Crossroads turbines will begin delivering wind energy as they come on-line during the second half of 2011. The entire facility is expected to be in service by the end of 2011. Mr. Langston testified that this large, approximately 20,000-acre site possesses the necessary attributes to support a successful large scale commercial wind energy project. He explained that the land agreements are in place to construct and interconnect the project and three meteorological towers have been collecting wind speed data during the last two years. He explained that the favorable wind speed conditions at this particular site, when combined with the large contiguous site, allow OG&E to optimize turbine placement that he believes will produce an exceptional capacity factor. In addition, Mr. Langston testified t
hat the site is located close to major transmission facilities. Mr. Langston also explained that the Oklahoma Department of Wildlife Conservation (“ODWC”) recently determined that the Crossroads site lies outside the current range of the Lesser Prairie Chicken (“LPC”) and that negative impacts to the LPC is not a concern. Mr. Langston stated that OG&E does not believe it will need to perform any environmental remediation at the site and has not included any such remediation costs in this request.
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5.
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Mr. Langston testified that OG&E is requesting a waiver of the competitive procurement rules because the exceptional pricing and other attractive terms negotiated by OG&E are contingent upon the execution of contracts in a period of time which made it unrealistic to attempt to adhere to the process set out in the Commission’s competitive procurement rules. Also, Mr. Langston explained that OG&E was obligated to seek a waiver of the competitive procurement rules because of commitments made in Cause No. PUD 200900167 and adopted by the Commission in Order No. 571788 (“OU Spirit Proceeding”).
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6.
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Mr. Langston testified that all parties in this case executed the Settlement Agreement. He explained that the signatories of the Stipulation were OG&E, the Public Utility Division of the Oklahoma Corporation Commission, the Attorney General, Chermac Energy Corporation, the Oklahoma Industrial Energy Consumers, and the OG&E Shareholders Association.
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7.
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Mr. Langston described the agreements reached by the Stipulating Parties regarding whether construction of the Crossroads facility is prudent. He testified that in Section III.A, the Stipulating Parties request that the Commission issue an order granting preapproval of the Crossroads facility as described in the Settlement Agreement and finding that Crossroads is a prudent investment. Mr. Langston further testified that the Stipulating Parties also request that the Commission issue an order finding that Crossroads, when constructed, placed in service and interconnected to Windspeed, will be used and useful to OG&E’s customers, subject to material compliance with expected operations. He testified that the Stipulating Parties further agreed that the operational performance of Crossroads shall be reviewed pursuant to the regular Commission reviews provided for in OAC 165:3
5-39 and OAC 165:35-35.
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8.
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Mr. Langston provided further testimony on the agreements reached by the Stipulating Parties regarding the recovery mechanism for costs associated with the Crossroads project. He testified that in Section III.B, the Stipulating Parties agreed on the Crossroads Rider as the mechanism through which OG&E would recover costs associated with the Crossroads project.
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9.
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Mr. Langston further testified that in Section III.C, the Stipulating Parties request that the Commission grant OG&E’s request for a waiver from the Commission’s competitive bidding requirements. He testified that the Stipulating Parties agreed that their recommendation is based on: (i) OG&E’s representations that the Crossroads project will deliver significantly greater benefit to customers than other top bidders in its most recent RFP and other wind resource opportunities available to OG&E at this time, and that the opportunity to realize these benefits may be lost if action is not taken at this time; and (ii) the agreements described in the Settlement Agreement.
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10.
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Mr. Langston further testified on the agreements that were reached regarding Crossroads’ construction costs. He testified that the Stipulating Parties, in Section III.D of the Settlement Agreement, agreed to cap OG&E’s capital costs for which it is entitled recovery (“Capped Investment Amount”). He testified that this Capped Investment Amount for the 197.8 MW facility will be the lesser of (i) $389 million as adjusted for the Krone/Dollar exchange rate on the date a Commission order is issued in this cause, plus a variance which does not exceed three percent; or (ii) a maximum cost of $416.2 million. Mr. Langston testified that the Krone/Dollar exchange rate provision impacts approximately 40 percent of the Turbine Service Agreement. He further testified that the Capped Investment Amount approved by a Commission order adopting the Settlement
Agreement will be calculated using the Danish Krone/U.S. Dollar exchange rate posted on the Yahoo Financial web site as of 9:00 a.m. Central time on the date of the Commission’s action. At the hearing, Mr.
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PUD 201000037-FINAL ORDER | Page 6 of 13 |
11.
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Mr. Langston further testified that there is a limitation on the Capped Investment Amount. He stated that the Stipulating Parties have agreed to a “walk-away” provision should the Capped Investment Amount as of the date of the final Commission order exceed $416.2 million. He testified that this provision is intended to reflect an adverse movement in the Danish Krone/U.S. Dollar exchange rate before the date of a Commission order that is so extraordinary as to significantly change the value to be provided by Crossroads.
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12.
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Mr. Langston testified as to what would happen if OG&E’s actual construction costs exceeded the Capped Investment Amount. He testified that to the extent OG&E’s total investment in Crossroads exceeds the Capped Investment Amount, the Stipulating Parties have agreed that OG&E has the option to seek recovery of any excess above the Capped Investment Amount in a general rate case. He further testified that the Settlement Agreement specifies that any construction costs incurred by OG&E in excess of the Capped Investment Amount will not be eligible for cost recovery prior to OG&E’s next general rate case and in no circumstances may that recovery include interim carrying costs on the excess Plant in Service.
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13.
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Mr. Langston further testified that the Capped Investment Amount discussed in Section III.D is related to the Crossroads project at 197.8 MW. He stated that the Crossroads site is large enough to support a 98-turbine, 227.5 MW wind farm, but the developer, RES Americas, initially requested interconnection service for only 197.8 MW. Mr. Langston testified that OG&E is working within the SPP interconnection study process to determine what interconnection costs an incremental 29.7 MWs would add to the project. He testified that the Stipulating Parties agreed that if those additional 29.7 MWs (twelve additional turbines including nine 2.3 MW turbines and three 3 MW turbines) can be added to the Crossroads site with incremental interconnection costs below $4.7 million, this incremental quality of wind generation capacity would be beneficial to OG&E’s customers.
0;He testified that consequently, the Settlement Agreement provides that, subject to this contingency and other limitations described therein, OG&E’s decision to proceed with the construction of those additional twelve turbines is prudent, the turbines will be used and useful when placed in service, and the costs and associated recovery for these additional turbines shall be included in the Crossroads Rider.
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14.
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Mr. Langston testified that the three 3MW turbines were next generation turbines that OG&E would be one of the first in the country to own and operate. He explained that OG&E was successful in negotiating a price for these new turbines that matched the price for the 2.3 MW turbines.
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15.
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Mr. Langston testified that if OG&E constructs Crossroads as a 227.5 MW project the Capped Investment Amount would change. He stated that Section III.O specifies that if OG&E moves forward with the additional twelve turbines and constructs Crossroads as a 227.5 MW project, the Capped Investment Amount calculation will be the lesser of (i) $448.8 million as adjusted for the Krone/Dollar exchange rate on the date a Commission Order; plus a variance which does not exceed three (3) percent; or (ii) a maximum cost of $480.2 million. He further testified that in the same manner as with the Capped Investment Amount for the 197.8 MW project, the Company will have the option to request recovery of any actual costs in excess of that amount. Mr. Langston testified that there is also a Maximum Stipulated Cost associated with the 227.5 MW project. He stated that Secti
on III.O specifies that the Settlement Agreement will not become effective if the 227.5 MW Capped Investment Amount on the date of the final order exceeds $480.2 million and this is referred to in the Settlement Agreement as the “Alternative Maximum Stipulated Cost.”
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16.
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Mr. Langston further testified that an agreement has been reached regarding the recovery of Operation and Maintenance (“O&M”) costs. He testified that as specified in Section III.L of the Settlement Agreement, O&M cost recovery will be capped until after OG&E’s 2013 general rate case. He further testified that since the O&M expense cap will depend on whether the Crossroads project is constructed at 197.8 MW or 227.5 MW, Stipulation Exhibit BJS-2 identifies the capped O&M expense in 2012 and 2013 for both projects. He testified that after 2013, the appropriate level of O&M cost recovery will be determined by the Commission in the periodic rate case process.
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17.
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Mr. Langston testified that in Section III.F of the Settlement Agreement, OG&E has agreed to pass through to Oklahoma retail customers one hundred percent of the Oklahoma jurisdictional Renewable Energy Credit (“REC”) proceeds (after
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PUD 201000037-FINAL ORDER | Page 7 of 13 |
18.
|
Mr. Langston testified that in Section III.G of the Settlement Agreement, OG&E agreed to file an application with the Commission within sixty days of a final Commission order in this proceeding requesting amendments to the current Minimum Filing Requirements (OAC 165:35-39) for the purpose of providing additional information regarding electric utility wind generation facilities and wind energy purchase power agreements (“PPAs”). He further testified that the Stipulating Parties agree to collaborate in developing the requested amendments, but agreed that this additional information shall at a minimum include the amount of Production Tax Credits (“PTCs”) utilized in the reporting year. He testified that OG&E has also agreed to provide the additional information simultaneously with the filing of its Minimum Filing Requirements until such time as the proposed amendments are
either adopted or rejected by the Commission.
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19.
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Mr. Langston further testified that the Stipulating Parties reached agreement regarding the treatment of PTCs. He testified that in Section III.H, the Stipulating Parties agreed that OG&E’s Oklahoma retail customers will be credited with one hundred percent of the Oklahoma jurisdictional share of the actual Crossroads’ PTCs created during the term of, and as specified in, the Crossroads Rider. He further testified that at the end of the Crossroads Rider and for the remaining life of the Crossroads project PTCs, OG&E will continue to credit its Oklahoma retail customers with one hundred percent of the Oklahoma jurisdictional share of the actual test year benefits of the PTCs (as adjusted for known and measurable changes) in the determination of the revenue requirements in each general rate proceeding.
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20.
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Mr. Langston testified that the Stipulating Parties agreed on how damage payments received from or bonus payments made to the wind developer or turbine manufacturer should be treated through the Crossroads Rider. He stated that the agreements with RES Americas Construction, Inc. and Siemens include certain incentive and penalty provisions that protect the interests of OG&E and its customers. He further testified that the Stipulating Parties agreed that OG&E will pass through to Oklahoma retail customers the Oklahoma jurisdictional share of all net damage payments received from the wind developer or the turbine manufacturer. He further stated that it was acknowledged by the Stipulating Parties that these damage payments would not exceed $85 million. Mr. Langston testified that the Stipulating Parties further agreed that, in light of the benefits to custome
rs associated with higher achieved Crossroads output and the early completion of the Crossroads project, OG&E will pass through to Oklahoma customers the Oklahoma jurisdictional share of all bonuses paid to the wind developer or the turbine manufacturer pursuant to contract and it was acknowledged by the Stipulating Parties that these bonuses would not exceed $3.2 million.
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21.
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Mr. Langston testified that as described in Section III. J, one hundred percent of all margins from incremental sales of capacity and energy into the SPP Energy Imbalance Services (“EIS”) market will be credited to customers. He testified that these incremental sales represent the net proceeds from sales of coal or natural gas-fired generation made possible by the availability of Crossroads.
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22.
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Mr. Langston further testified that in Section III.K, the Stipulating Parties agreed that OG&E would agree to certain obligations if the three-year rolling average of Crossroads megawatt-hours of production (including a credit for energy not produced due to curtailments or other events caused by system emergencies, force majeure events or transmission system issues) falls below a specified level. He stated that this level corresponds to a 41.14 percent capacity factor for the facility. Mr. Langston testified that under such circumstances, OG&E agreed to file testimony demonstrating the prudent operation of the Crossroads facility simultaneously with its filing of Minimum Filing Requirements pursuant to OAC 165:35-39. Mr. Langston testified that as he explained in his direct testimony, using probability analysis, OG&E determined that there is a ten percent probability
that the capacity factor could be 41.14 percent or lower. He further testified that the Company contends that if a 41.14 percent capacity factor is achieved Crossroads will produce significant production cost savings for customers; nevertheless, OG&E agreed to provide testimony specifically addressing the prudency of its operations if Crossroads’ output fails to meet the agreed upon standard. Mr. Langston also stated that output levels below 41.14 percent would not necessarily be considered imprudent, but merely the agreed on level of output where OG&E would provide testimony demonstrating the facility’s prudent operation.
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23.
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Mr. Langston testified that the Stipulating Parties reached an agreement regarding the Company’s Integrated Resource analysis. He testified that in Section III.M of the Settlement Agreement, OG&E agreed to submit an interim, updated Integrated Resource Plan (“IRP”) as contemplated by Subsection 37 of Chapter 35 of the Commission’s Rules. He testified that for this interim updated IRP, OG&E agreed that the updated IRP analysis will specifically address the need and timing for additional wind resources in OG&E’s system, including but not limited to various amounts of wind and
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PUD 201000037-FINAL ORDER | Page 8 of 13 |
24.
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Mr. Langston further testified that the Stipulating Parties agreed that the agreements described in Section III.M do not constitute an admission by the Stipulating Parties that OG&E has a need for future wind resources nor is it intended to relieve OG&E of its burden of proof to demonstrate that any agreements it enters into to acquire future wind energy assets or to purchase additional wind energy are reasonable or prudent.
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25.
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Mr. Langston also testified that in Section III.N of the Settlement Agreement, OG&E agreed not to seek Commission preapproval for the construction or acquisition of any new wind generation asset or for a long term wind purchase power agreement until it finalizes and submits a new IRP described in Section III.M of the Settlement Agreement. He stated that the Stipulating Parties agreed that this restriction would not apply to (i) preapproval of the Crossroads expansion from 197.8 MW to 227.5 MW identified in Section III.O of the Settlement Agreement; or (ii) the procurement of the Company’s next incremental amount of wind energy (at least 100 MW and no more than 150 MW), which shall be awarded through a competitive procurement process. Mr. Langston further testified that the Stipulating Parties agreed that for the purposes of the wind energy competitive procurement process agreed to
in Section III.N of the Settlement Agreement, the Independent Evaluator selected to participate in the process shall be either: a) a Commission staff member or a third party agreed to by OG&E, the Attorney General and Public Utility Division staff; or b) if OG&E, the Attorney General and Public Utility Division staff cannot agree to an Independent Evaluator pursuant to (a), a Commission staff member or third party appointed by the Commission after notice and hearing.
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26.
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Mr. Langston testified as to the evidence in the record which he believes supports a finding by the Commission that there is a need for the Crossroads project, including the substantial economic benefits accruing almost immediately to customers as well as the hedge the Crossroads project provides against prospective environmental costs and future fluctuations in natural gas costs. Mr. Langston stated that because OG&E is able to obtain the turbines at such a favorable price, the addition of Crossroads to the OG&E portfolio will provide exceptional production cost savings which will benefit OG&E’s customers almost immediately and continue throughout the life of the facility. Mr. Langston testified that OG&E’s analyses demonstrate that Crossroads, after taking into consideration various risk factors, will provide production cost savings to OG&E’s customer
s under a wide range of scenarios, including under varying natural gas prices, carbon costs and capacity factors. Further, Mr. Langston testified that if approved, Crossroads would increase the amount of wind capacity in OG&E’s portfolio from 554 MW (including OU Spirit and the CPV Keenan and Taloga PPAs) to 751 MW (or approximately 780 MW if Crossroads is constructed at 227.5 MW). Mr. Langston testified that this would bring the overall amount of OG&E’s renewable energy to approximately 10 percent of its total resource portfolio. Mr. Langston further testified that the Company strongly believes that the addition of wind energy provides OG&E and its customers with an effective hedge against higher and volatile fuel prices, the cost imposed by the creation of a Federal renewable portfolio standard and costly carbon tax regulations, whether imposed by new laws or the Environmental Protection Agency. Mr. Langston further testified that the appl
ication was consistent with the need demonstrated in the 2010 IRP for additional wind generation by 2012, as reflected in his Direct Testimony in this cause. He also testified that the Crossroads project will help the State of Oklahoma meet the new renewable energy goal of 15 percent by 2015 that was adopted in recently enacted Oklahoma House Bill 3028.
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27.
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Mr. Langston concluded by testifying that, in his opinion, the Settlement Agreement is in the public interest.
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PUD 201000037-FINAL ORDER | Page 9 of 13 |
2.
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Mr. Scott testified that the Crossroads Rider is attached to the Settlement Agreement as Stipulation Exhibit BJS-1 and is designed to begin recovering the annual revenue requirement associated with the Crossroads site assets as each asset is placed in service or otherwise becomes used and useful. He further testified that this would include the turbines, roads, generation lead, building and other supporting infrastructure. He stated that the Crossroads Rider will become effective upon the issuance of the final order approving this Settlement Agreement and the submission to and approval of the Crossroads Rider tariff by the Director of the Public Utility Division. Mr. Scott testified that upon its effective date, the Crossroads Rider is designed to begin recovering the annual revenue requirement associated with each Crossroads wind turbine placed in service and the Crossroads Ride
r will be effective until new rates are implemented after OG&E’s 2013 general rate case. He testified that in the 2013 general rate proceeding, the net depreciated balance of Crossroads’ plant costs will be included in rate base. He further testified that as agreed to in the Settlement Agreement, the rate of return utilized for the Crossroads Rider will initially be calculated using the capital structure, return on equity, interest costs and tax effect as approved in Order No. 516261 in Cause No. PUD 200500151. He further testified that this rate of return will be adjusted to reflect the rate of return approved by the Commission in OG&E’s 2011 rate case and the new rate of return will be applied on the effective date of the rates approved in the 2011 rate case.
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3.
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Mr. Scott testified that some turbines may be placed in service as early as the third quarter of 2011, but most of the turbines are expected to be placed in service during the fourth quarter of 2011 and the facility is expected to be fully operational by December 31, 2011. Mr. Scott further testified regarding why it is appropriate for the Crossroads Rider to be implemented before all of the turbines are placed in service. He stated that first, customers will benefit from the energy produced by each individual turbine as it is placed in service by lowering fuel costs. He further testified that when a turbine is placed in service, the accumulation of Allowance for Funds Used during Construction (“AFUDC”) ceases. Therefore, synchronizing the recovery of costs with each turbine becoming operational (used and useful) is reasonable and fair to all parties.
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4.
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Mr. Scott further testified that OG&E expects to file a rate case with a test year of 2012 and implement new rates in January 2014. He testified that these new rates will include the revenue requirement for Crossroads. He further testified that the rider should be in existence from sometime in 2011 through December 2013.
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5.
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Mr. Scott testified regarding what is included in the Crossroads Rider. He testified that the rider will recover from OG&E’s Oklahoma retail customers a revenue requirement based on the return on rate base and income taxes, O&M expense, depreciation, insurance and property taxes associated with the Crossroads project. He further testified that as agreed to in the Settlement Agreement, the Crossroads Rider also will be used to credit Oklahoma retail customers with one hundred percent of the Oklahoma jurisdictional share of the actual Crossroads PTCs created during the term of the Crossroads Rider. He further testified that the Crossroads Rider allows for the Oklahoma jurisdictional share of all net damage payments received from the wind developer or the turbine manufacturer to pass through to Oklahoma retail customers and also allows OG&E to pass through to Oklah
oma customers the Oklahoma jurisdictional share of all bonuses paid to the wind developer or the turbine manufacturer pursuant to contract.
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6.
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Mr. Scott testified that the rider has a true-up provision to align actual costs with revenues recovered. He further testified that the rider also contains a mechanism for crediting Oklahoma retail customers for one hundred percent of the Oklahoma jurisdictional RECs proceeds (after deduction of third-party transaction costs, if applicable) generation by Crossroads’ RECs during the term of and through the Crossroads Rider. He stated that the REC proceeds will be allocated to jurisdictions and customer classes using an energy allocator.
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7.
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Mr. Scott further testified that the proceeds from the sale of Crossroads’ RECs will help offset the revenue requirement for the project and will be credited to customers. He testified that OG&E originally proposed that the Crossroads’ REC revenues be credited to customers under the New Renewable Energy Credits (“NREC”) portion of the Renewable Transmission System Additions (“RTSA”) rider, which was approved September 11, 2008, in Cause No. PUD 200800148, Commission Order No. 559353. He testified that the RTSA specifies that eighty percent of the REC revenues from new wind facilities, like Crossroads, will be credited back to customers. Mr. Scott testified that in the Settlement Agreement, the Stipulating Parties agreed that OG&E will credit customers with one hundred percent of the proceeds from sales of Crossroads’ RECs through
the Crossroads Rider instead of the RTSA.
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8.
|
Mr. Scott testified that the final estimated cost of the project cannot be finally determine at this time given the Danish Krone/U.S. Dollar exchange rate and the possibility of Crossroads moving from 197.8 MW to 227.5 MW. He testified
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PUD 201000037-FINAL ORDER | Page 10 of 13 |
9.
|
Mr. Scott further testified that Attachment 2 to Stipulation Exhibit BJS-1 contains an illustration of the estimated revenue requirement for the 227.5 MW Crossroads project at a total capital cost of $448.8 million in 2012 and 2013. He testified that this $448.8 million in capital cost was included as utility plant in rate base and then adjusted for accumulated depreciation, ARO and deferred income taxes before calculating a return using the capital structure, return on equity, interest costs and tax effect as approved in Order No. 516261 in Cause No. PUD 200500151. He further testified that OG&E’s calculation also included the capped amount of O&M expense contained in the Settlement Agreement, as well as estimated amounts for depreciation expense, insurance, ARO and ad valorem taxes. He testified that after adding the expense to the return on rate base, OG&E su
btracted the estimated amount of the PTCs from this annual amount to determine the annual revenue requirement. Mr. Scott testified that based on the assumptions utilized in the illustration, the approximate total company annual revenue requirement would be $44,326,049 in 2012 and $36,313,057 in 2013.
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10.
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Mr. Scott testified that the annual revenue requirement will be based on actual costs. He stated that this annual revenue requirements shown in the illustrations are calculated on a total company basis and do not reflect the Oklahoma jurisdictional portion of the revenue requirement.
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11.
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Mr. Scott testified that OG&E used its resource planning models to compare a portfolio that included Crossroads to a portfolio that did not include Crossroads. He further testified that the addition of Crossroads to the OG&E portfolio will provide production cost savings as wind energy displaces more expensive generation resources.
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12.
|
Mr. Scott testified that, as demonstrated in Chart 1 in his Supplemental Testimony and based on the assumptions therein, there is an estimated net cost of $1.7 million for the 197.8 MW project in 2012 and of $1.2 million for the 227.5 MW project in 2012. He further testified that there is an estimated net savings of $10.7 million for the 197.8 MW project in 2013 and of $12.9 million for the 227.5 MW project in 2013.
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13.
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Mr. Scott testified regarding the estimated overall impact of Crossroads on an average Oklahoma residential retail customer during the first three years of the project. He testified that for the 197.8 MW project, the estimated overall impact on an average residential customer using 1,100 kWh is a $0.54 per month increase in 2012, a $0.04 per month reduction in 2013 and additional monthly reductions in each year subsequent to 2013. He further testified that the estimated impact of the 227.5 MW project to an average residential customer using 1,100 kWh a month is $0.60 per month in 2012, a reduction of $0.07 per month in 2013 and additional monthly reductions in each year subsequent to 2013. Mr. Scott testified that the calculation of estimated impacts for the major customer classes is shown by Chart 2 in his supplemental testimony. At the hearing, Mr. Scott explained th
at OG&E would be willing to create a revised chart for the Commission website that illustrates the estimated customer impact for not only 2012 and 2013, but also during 2011 when the Crossroads facility will be constructed.
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14.
|
Finally, Mr. Scott testified that the Stipulating parties have agreed to actions which shifted certain risks of the project from ratepayers to OG&E’s shareowners, including treatment of RECs and cap on construction costs. He also testified that, in addition, OG&E retained the risk related to regulatory lag between the period it incurs cost and the date it begins recovery under the Crossroads Rider. The parties attempted to rebalance the potential risks of Crossroads in the Settlement Agreement.
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PUD 201000037-FINAL ORDER | Page 11 of 13 |
1.
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Craig R. Roach, President, Boston Pacific Company, filed pre-filed Direct Testimony on behalf of the PUD of the Commission and also filed Supplemental Testimony in support of the Settlement Agreement.
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2.
|
Mr. Roach testified that the purpose of his testimony was to provide his opinion on the Settlement Agreement.
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3.
|
He testified that he supported the Settlement Agreement for three reasons. He stated that his first reason was that the Crossroads project, under OG&E’s assumptions, appears to provide a levelized cost that is substantially lower than that for current market alternatives. He further testified that the second reason was the Settlement Agreement provides an adequate level of ratepayer risk protection against the three key risks created by utility-owned wind projects. He further stated that these three risks are: (i) that capital expenditures will be higher than originally estimated, (ii) that the electricity generated will be lower than predicted and (iii) that the utility will not be able to use the PTCs generated by the project because they do not have sufficient tax liability elsewhere in the company. Finally, Mr. Roach testified that he supported the Settlement Agreem
ent because it reflects a proper definition of prudence for this case; it acknowledges Crossroads must beat the next-best alternatives to be found to be prudent. And, he further explained, that the capital cost caps and performance thresholds were driven by that definition of prudence.
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4.
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Mr. Roach further testified that there was a need for the Crossroads project. He testified that there was evidence in the record that there was a need for wind in the most recent OG&E IRP and that the cost-benefit analysis performed by OG&E for Crossroads and the pricing comparison between Crossroads and other recent wind projects confirmed that need for Crossroads. Mr. Roach testified that the need for wind energy is different from the need for generation capacity for serving customer load; that the need for wind is based on economic benefits associated with wind energy in a resource portfolio and is always essentially “economic need”; and that need was satisfied in this case because the evidence established the project was the least cost project when compared to the next best alternative.”
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Attorney General
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1.
|
The Attorney General filed Responsive Testimony of Daniel Peaco, participated in the settlement discussions on June 15, 16, 22, and 24, 2010, and appeared at the hearing on the merits. The Attorney General agrees with and signed the Settlement Agreement, and recommends that the Commission approve the Settlement Agreement. The Attorney General also stated that OG&E has demonstrated a need for the Crossroads project.
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Intervenors
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1.
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OIEC filed Responsive Testimony of Scott Norwood, participated in the settlement discussions on June 15, 16, 22, and 24, 2010, and appeared at the hearing on the merits. OIEC agrees with and signed the Settlement Agreement, and recommends that the Commission approve the Settlement Agreement. In addition, at the hearing, OIEC stated that OG&E has demonstrated a need for the Crossroads project.
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2.
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OG&E Shareholders Association filed a Statement of Position, participated in the settlement discussions on June 15, 16, 22, and 24, 2010, and appeared at the hearing on the merits. The OG&E Shareholders agrees with and signed the Settlement Agreement, and recommends that the Commission approve the Settlement Agreement. In addition, at the hearing, the OG&E Shareholders stated that OG&E has demonstrated a need for the Crossroads project.
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3.
|
Chermac Energy Corporation, filed a Statement of Position, participated in the settlement discussions on June 15, 16, 22, and 24, 2010, and appeared at the hearing on the merits. Chermac agrees with and signed the Settlement Agreement, and recommends that the Commission approve the Settlement Agreement.
|
1.
|
The Commission finds that notice has been properly given in accordance with Order No. 576086, issued in this cause, with due and proper notice by publication having been made and proof of publication having been filed with the office of
|
PUD 201000037-FINAL ORDER | Page 12 of 13 |
2.
|
The Commission further finds that the Stipulating Parties executed a Settlement Agreement, hereto attached as Attachment “A,” and incorporated herein by reference.
|
3.
|
The Commission further finds that the Settlement Agreement reflects a full, final, and complete settlement of all issues in this proceeding.
|
4.
|
The Commission further finds that based upon the record, the Settlement Agreement is in the public interest and should be adopted as the order of this Commission.
|
5.
|
The Commission further finds that based upon the record, there is a need for the Crossroads project.
|
6.
|
The Commission further finds that based upon the record, that the Crossroads Wind Farm, as described in the Settlement Agreement is fair, just and reasonable and represents a prudent investment by OG&E. The Commission further finds that, when constructed and placed in service, Crossroads will be used and useful to OG&E’s customers, subject to material compliance with expected operations.
|
7.
|
The Commission further finds that based upon the record and consistent with the Settlement Agreement, that OG&E is authorized to recover the costs associated with Crossroads through the Crossroads Rider attached to the Settlement Agreement as Stipulation Exhibit BJS-1, which shall become effective with the issuance of the final order approving this Settlement Agreement and the submission to and approval of the Crossroads Rider tariff by the Director of the Public Utility Division. The Crossroads Rider will be effective until new rates are implemented after OG&E’s 2013 general rate case and, in that 2013 general rate proceeding, the net depreciated balance of Crossroads’ plant costs will be included in rate base.
|
8.
|
The Commission further finds that the Capped Investment Amount (as defined in the Settlement Agreement and as calculated pursuant to the Settlement Agreement) shall be $407.66 million for the 198.7 MW project and $469.68 million for the 227.5 MW project.
|
9.
|
The Commission further finds that based on the record, $407.66 million for the 198.7 MW project and $469.68 million for the 227.5 MW project represents an investment that is fair, just and reasonable and in the public interest and is deemed prudent and will be included in the revenue requirement in OG&E’s planned 2013 general rate case.
|
10.
|
The Commission further finds that any finding of fact stated herein which should properly be included as a conclusion of law is so included.
|
1.
|
The Commission finds that it has jurisdiction with respect to the issues presented in this proceeding by virtue of Article IX, § 18 of the Oklahoma Constitution; 17 O.S. §§ 151-152; and 17 O.S. §286(C).
|
2.
|
The Commission further finds that notice has been properly given and is in compliance with OAC 165:50-5-3(1) and OAC 165:5-7-51(b) of the Commission’s Rules of Practice.
|
3.
|
The Commission further finds that, under 17 O.S. §§ 151-152; and 17 O.S. §286(C), Crossroads should be pre-approved and is fair, just and reasonable and represents a prudent investment by OG&E. The Commission further finds that, when constructed and placed in service, Crossroads will be used and useful to OG&E’s customers, subject to material compliance with expected operations.
|
4.
|
The Commission further finds that the approval of the Settlement Agreement and the pre-approval of Crossroads is in the public interest.
|
5.
|
Any conclusion of law stated herein which should properly be a finding of fact is so included.
|
PUD 201000037-FINAL ORDER | Page 13 of 13 |
OKLAHOMA CORPORATION COMMISSION
|
||
/s/ Bob Anthony
|
||
BOB ANTHONY, Chairman
|
||
/s/ Jeff Cloud
|
||
JEFF CLOUD, Vice-Chairman
|
||
/s/ Dana L. Murphy
|
||
DANA L. MURPHY, Commissioner
|
/s/ Peggy Mitchell
|
||
PEGGY MITCHELL, Secretary
|
/s/ Jacqueline T. Miller
|
July 26, 2010
|
||
JACQUELINE T. MILLER
|
Date
|
||
Referee, Administrative Law Judge
|
OKLAHOMA GAS & ELECTRIC COMPANY
|
Dated: 6/28/2010
|
By: /s/ William J. Bullard
|
William J. Bullard
|
|
Kimber L. Shoop
|
OKLAHOMA OFFICE OF THE ATTORNEY GENERAL
|
Dated: 6/28/2010
|
By: /s/ William L. Humes
|
William L. Humes
|
OKLAHOMA INDUSTRIAL ENERGY CONSUMERS
|
Dated: 6/28/2010
|
By: /s/ J. Fred Gist
|
J. Fred Gist
|
OG&E SHAREHOLDERS ASSOCIATION
|
Dated: 6/28/2010
|
By: /s/ Ronald E. Stakem
|
Ronald E. Stakem
|
PUBLIC UTILITY DIVISION
|
|
OKLAHOMA CORPORATION COMMISSION
|
Dated: 6/28/2010
|
By: /s/ Brandy L. Wreath
|
Brandy L. Wreath
|
|
Deputy Director
|
CHERMAC ENERGY CORPORATION
|
Dated: 6/28/2010
|
By: /s/ Richard Goodwin
|
Richard Goodwin
|
OKLAHOMA GAS AND ELECTRIC COMPANY | Original Sheet No. 55.00 |
P. O. Box 321 | Replacing Original Sheet No. N/A |
Oklahoma City, Oklahoma 73101 | Date Issued XXXXXX xx, 20xx |
STANDARD PRICING SCHEDLUE:CR
|
STATE OF OKLAHOMA
|
CROSSROADS RIDER
|
|
A) Oklahoma Jurisdiction Crossroads Rider Revenue Requirement: The revenue requirement shall be based upon the most recently approved return on rate base (ROR), income tax expense, O&M expense, insurance expense, asset retirement obligation, depreciation, property tax, project damage payments, project bonuses, and reduced for production tax credits. The revenue requirement will also be reduced by the proceeds from REC sales as described in C) Annual Class True-Up.
|
OKLAHOMA GAS AND ELECTRIC COMPANY | Original Sheet No. 55.01 |
P. O. Box 321 | Replacing Original Sheet No. N/A |
Oklahoma City, Oklahoma 73101 | Date Issued XXXXXX xx, 20xx |
STANDARD PRICING SCHEDLUE:CR
|
STATE OF OKLAHOMA
|
CROSSROADS RIDER
|
|
B) Production Demand Allocation Factor: The most recently approved production demand allocation factor (1CP Average & Excess).
|
Class
|
Allocator
Percentage*
|
||
Residential
|
46.8208
|
||
General Service
|
8.7280
|
||
Power and Light
|
27.2523
|
||
Large Power and Light
|
14.6669
|
||
Other
|
2.5320
|
||
*Adjusted to exclude jurisdictions not at issue
|
|
C) Annual Class True-Up: The over or under amount which will be the difference between the revenues collected through the rider from a previous period and the Oklahoma Actual Revenue Requirements of the corresponding period. All true-up amounts for any previous period will be added to or subtracted from the expected Oklahoma Retail jurisdictional amount by Class or “Other” for the next calendar year collection. In addition, 100 percent of the Oklahoma jurisdictional share of the proceeds (after deduction of third party transaction costs if applicable) from the sale of Crossroads RECs generated during the term of this rider shall be credited to Class based on an energy allocator.<
/div>
|
|
D) Base kWh: The applicable projected Oklahoma jurisdictional kWh as determined by the Company computed using the most current twelve (12) billing month kWh (November thru October, weather adjusted) and submitted to the Commission in November of each year.
|
Attachment 1 to Stipulation Exhibit BJS-1
|
|||
Illustration of Estimated Revenue Requirement for Crossroads Wind Farm
|
|||
Performed 6/24/2010
|
|||
46.38% CF; Expected CO2 and Gas; 197.8 MW
|
2012
|
2013
|
|||||
REVENUE REQUIREMENTS
|
||||||
Rate Base
|
||||||
Utility Plant
|
$389,000,000
|
$389,000,000
|
||||
Asset Retirement Obligation (ARO) Asset
|
$5,704,308
|
$5,704,308
|
||||
ARO Accumulated Amortization
|
-$52,289
|
-$166,376
|
||||
ARO Liability
|
-$5,857,930
|
-$6,202,962
|
||||
Accumulated Provision for Depreciation
|
-$7,137,694
|
-$22,710,844
|
||||
State PTC Tax Asset
|
$0
|
$0
|
||||
Accumulated Deferred Income Taxes
|
-$10,561,781
|
-$41,654,729
|
||||
Total Rate Base
|
$371,094,613
|
$323,969,397
|
||||
Return with Taxes
|
$45,793,075
|
$39,977,824
|
||||
Expenses
|
||||||
O&M Expenses
|
$6,770,903
|
$6,886,803
|
||||
ARO Accretion
|
$335,984
|
$355,773
|
||||
ARO Amortization
|
$114,086
|
$114,086
|
||||
Depreciation
|
$15,573,150
|
$15,573,150
|
||||
Insurance
|
$125,779
|
$128,924
|
||||
Property Taxes
|
$3,893,288
|
$3,893,288
|
||||
Total Expenses
|
$26,813,190
|
$26,952,024
|
||||
Revenue Requirement
|
||||||
Total Company Revenue Requirement
|
$72,606,265
|
$66,929,847
|
||||
Production Tax Credits - Federal & state
|
-$34,072,778
|
-$35,370,789
|
||||
Net Total Company Revenue Requirement
|
$38,533,487
|
$31,559,059
|
||||
PRODUCTION COST SAVINGS
|
||||||
OGE Fuel Cost
|
$28,521,154
|
$31,219,578
|
||||
COGEN Cost
|
$1,950,437
|
$3,690,109
|
||||
Purchase Power
|
$2,600
|
$26,200
|
||||
Total Fuel Cost
|
$30,474,191
|
$34,935,887
|
||||
Variable O&M
|
$1,799,311
|
$1,443,556
|
||||
CO2 Costs
|
$3,552,709
|
$4,903,696
|
||||
Total Variable Production Costs
|
$35,826,210
|
$41,283,139
|
||||
CREDITS
|
||||||
Renewable Energy Certificates (REC)
|
$967,009
|
$964,367
|
||||
Total Company NET BENEFIT/(COST)
|
($1,740,267)
|
$10,688,448
|
Attachment 2 to Stipulation Exhibit BJS-1
|
|||
Illustration of Estimated Revenue Requirement for Crossroads Wind Farm
|
|||
Performed 6/24/2010
|
|||
46.38% CF; Expected CO2 and Gas; 227.5 MW
|
2012
|
2013
|
|||||
REVENUE REQUIREMENTS
|
||||||
Rate Base
|
||||||
Utility Plant
|
$448,800,000
|
$448,800,000
|
||||
Asset Retirement Obligation (ARO) Asset
|
$6,560,716
|
$6,560,716
|
||||
ARO Accumulated Amortization
|
-$60,140
|
-$191,354
|
||||
ARO Liability
|
-$6,737,402
|
-$7,134,235
|
||||
Accumulated Provision for Depreciation
|
-$8,227,489
|
-$26,178,374
|
||||
State PTC Tax Asset
|
$0
|
$0
|
||||
Accumulated Deferred Income Taxes
|
-$12,093,024
|
-$47,715,451
|
||||
Total Rate Base
|
$428,242,660
|
$374,141,301
|
||||
Return with Taxes
|
$52,845,144
|
$46,169,037
|
||||
Expenses
|
||||||
O&M Expenses
|
$7,568,537
|
$7,698,176
|
||||
ARO Accretion
|
$386,426
|
$409,187
|
||||
ARO Amortization
|
$131,214
|
$131,214
|
||||
Depreciation
|
$17,950,885
|
$17,950,885
|
||||
Insurance
|
$144,984
|
$148,608
|
||||
Property Taxes
|
$4,487,721
|
$4,487,721
|
||||
Total Expenses
|
$30,669,768
|
$30,825,792
|
||||
Revenue Requirement
|
||||||
Total Company Revenue Requirement
|
$83,514,912
|
$76,994,828
|
||||
Production Tax Credits - Federal & state
|
-$39,188,863
|
-$40,681,772
|
||||
Net Total Company Revenue Requirement
|
$44,326,049
|
$36,313,057
|
||||
PRODUCTION COST SAVINGS
|
||||||
OGE Fuel Cost
|
$31,886,930
|
$33,688,231
|
||||
COGEN Cost
|
$2,648,642
|
$6,410,593
|
||||
Purchase Power
|
-$10,200
|
$12,000
|
||||
Total Fuel Cost
|
$34,525,372
|
$40,110,825
|
||||
Variable O&M
|
$1,609,812
|
$1,557,994
|
||||
CO2 Costs
|
$5,814,626
|
$6,435,406
|
||||
Total Variable Production Costs
|
$41,949,809
|
$48,104,224
|
||||
CREDITS
|
||||||
Renewable Energy Certificates (REC)
|
$1,112,207
|
$1,109,168
|
||||
Total Company NET BENEFIT/(COST)
|
($1,264,033)
|
$12,900,336
|
Stipulation Exhibit BJS-2
|
||||
2012
|
2013
|
|||
O&M Expenses* (based on 197.8 MW)
|
$6,770,903
|
$6,886,803
|
||
O&M Expenses* (based on 227.5 MW)
|
$7,568,537
|
$7,698,176
|