UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended December 31, 2011
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey | 13-1086010 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
6363 Main Street Williamsville, New York |
14221 | |
(Address of principal executive offices) | (Zip Code) |
(716) 857-7000
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨
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). YES x NO ¨
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 definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer | x | Accelerated Filer | ¨ | |||
Non-Accelerated Filer | ¨ (Do not check if a smaller reporting company) | Smaller Reporting Company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date:
Common stock, $1 par value, outstanding at January 31, 2012: 83,073,132 shares.
GLOSSARY OF TERMS
Frequently used abbreviations, acronyms, or terms used in this report:
National Fuel Gas Companies
Company |
The Registrant, the Registrant and its subsidiaries or the Registrants subsidiaries as appropriate in the context of the disclosure |
|
Distribution Corporation |
National Fuel Gas Distribution Corporation |
|
Empire |
Empire Pipeline, Inc. |
|
ESNE |
Energy Systems North East, LLC |
|
Horizon |
Horizon Energy Development, Inc. |
|
Horizon B.V. |
Horizon Energy Development B.V. |
|
Horizon LFG |
Horizon LFG, Inc. |
|
Horizon Power |
Horizon Power, Inc. |
|
Midstream Corporation |
National Fuel Gas Midstream Corporation |
|
Model City |
Model City Energy, LLC |
|
National Fuel |
National Fuel Gas Company |
|
NFR |
National Fuel Resources, Inc. |
|
Registrant |
National Fuel Gas Company |
|
Seneca |
Seneca Resources Corporation |
|
Seneca Energy |
Seneca Energy II, LLC |
|
Supply Corporation |
National Fuel Gas Supply Corporation |
Regulatory Agencies
EPA |
United States Environmental Protection Agency |
|
FASB |
Financial Accounting Standards Board |
|
FERC |
Federal Energy Regulatory Commission |
|
IASB |
International Accounting Standards Board |
|
NYDEC |
New York State Department of Environmental Conservation |
|
NYPSC |
State of New York Public Service Commission |
|
PaPUC |
Pennsylvania Public Utility Commission |
|
PHMSA |
Pipeline and Hazardous Materials Safety Administration |
|
SEC |
Securities and Exchange Commission |
Other
2011 Form 10-K |
The Companys Annual Report on Form 10-K for the year ended September 30, 2011 |
|
Bbl |
Barrel (of oil) |
|
Bcf |
Billion cubic feet (of natural gas) |
|
Bcfe (or Mcfe) represents Bcf (or Mcf) Equivalent |
The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas. |
|
Btu |
British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit. |
|
Capital expenditure |
Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets. |
|
Degree day |
A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit. |
|
Derivative |
A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps. |
|
Development costs |
Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. |
|
Dodd-Frank Act |
Dodd-Frank Wall Street Reform and Consumer Protection Act. |
-2-
GLOSSARY OF TERMS (Cont.)
Dth |
Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas. |
|
Exchange Act |
Securities Exchange Act of 1934, as amended |
|
Expenditures for long-lived assets |
Includes capital expenditures, stock acquisitions and/or investments in partnerships. |
|
Exploration costs |
Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells. |
|
Firm transportation and/or storage |
The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized. |
|
GAAP |
Accounting principles generally accepted in the United States of America |
|
Goodwill |
An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased. |
|
Hedging |
A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments. |
|
Hub |
Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas. |
|
Interruptible transportation and/or storage |
The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized. |
|
LIBOR |
London Interbank Offered Rate |
|
LIFO |
Last-in, first-out |
|
Marcellus Shale |
A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. |
|
Mbbl |
Thousand barrels (of oil) |
|
Mcf |
Thousand cubic feet (of natural gas) |
|
MD&A |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
|
MDth |
Thousand decatherms (of natural gas) |
|
MMBtu |
Million British thermal units |
|
MMcf |
Million cubic feet (of natural gas) |
|
NGA |
The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717. |
|
NYMEX |
New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas. |
|
Open Season |
A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously. |
|
PCB |
Polychlorinated Biphenyl |
|
Precedent Agreement |
An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called conditions precedent) happen, usually within a specified time. |
|
Proved developed reserves |
Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. |
|
Proved undeveloped (PUD) reserves |
Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive. |
|
Reserves |
The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production. |
-3-
GLOSSARY OF TERMS (Concl.)
Restructuring |
Generally referring to partial deregulation of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or unbundling) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets. |
|
Revenue decoupling mechanism |
A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation. |
|
S&P |
Standard & Poors Rating Service |
|
SAR |
Stock appreciation right |
|
Service agreement |
The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service. |
|
Stock acquisitions |
Investments in corporations. |
|
Unbundled service |
A service that has been separated from other services, with rates charged that reflect only the cost of the separated service. |
|
VEBA |
Voluntary Employees Beneficiary Association |
|
WNC |
Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered. |
-4-
Part I. Financial Information | Page | |||
Item 1. | ||||
6 | ||||
b. Consolidated Balance Sheets December 31, 2011 and September 30, 2011 |
7 - 8 | |||
c. Consolidated Statements of Cash Flows Three Months Ended December 31, 2011 and 2010 |
9 | |||
d. Consolidated Statements of Comprehensive Income - Three Months Ended December 31, 2011 and 2010 |
10 | |||
11 - 27 | ||||
Item 2. |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
28 - 49 | ||
Item 3. | 49 | |||
Item 4. | 49 - 50 | |||
Item 1. | 50 | |||
Item 1 A. | 50 - 53 | |||
Item 2. | 53 - 54 | |||
Item 3. |
Defaults Upon Senior Securities |
| ||
Item 4. |
Mine Safety Disclosures |
| ||
Item 5. |
Other Information |
| ||
Item 6. | 54 - 55 | |||
Signatures | 56 |
| The Company has nothing to report under this item. |
Reference to the Company in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Companys fiscal year ended September 30 of that year, unless otherwise noted.
This Form 10-Q contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2MD&A, under the heading Safe Harbor for Forward-Looking Statements. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words anticipates, estimates, expects, forecasts, intends, plans, predicts, projects, believes, seeks, will, may, and similar expressions.
-5-
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
Three Months Ended
December 31, |
||||||||
(Thousands of Dollars, Except Per Common Share Amounts) | 2011 | 2010 | ||||||
INCOME |
||||||||
Operating Revenues |
$ | 432,423 | $ | 450,948 | ||||
|
|
|
|
|||||
Operating Expenses |
||||||||
Purchased Gas |
132,193 | 163,038 | ||||||
Operation and Maintenance |
100,059 | 97,450 | ||||||
Property, Franchise and Other Taxes |
19,230 | 19,736 | ||||||
Depreciation, Depletion and Amortization |
62,547 | 53,313 | ||||||
|
|
|
|
|||||
314,029 | 333,537 | |||||||
|
|
|
|
|||||
Operating Income Other Income (Expense): |
118,394 | 117,411 | ||||||
Interest Income |
1,105 | 884 | ||||||
Other Income |
1,336 | (107 | ) | |||||
Interest Expense on Long-Term Debt |
(18,641 | ) | (20,192 | ) | ||||
Other Interest Expense |
(770 | ) | (1,401 | ) | ||||
|
|
|
|
|||||
Income Before Income Taxes |
101,424 | 96,595 | ||||||
Income Tax Expense |
40,725 | 38,052 | ||||||
|
|
|
|
|||||
Net Income Available for Common Stock |
60,699 | 58,543 | ||||||
|
|
|
|
|||||
EARNINGS REINVESTED IN THE BUSINESS |
||||||||
Balance at October 1 |
1,206,022 | 1,063,262 | ||||||
|
|
|
|
|||||
1,266,721 | 1,121,805 | |||||||
Dividends on Common Stock (2011$0.355 per share; 2010$0.345 per share) |
(29,479 | ) | (28,407 | ) | ||||
|
|
|
|
|||||
Balance at December 31 |
$ | 1,237,242 | $ | 1,093,398 | ||||
|
|
|
|
|||||
Earnings Per Common Share: |
||||||||
Basic: |
||||||||
Net Income Available for Common Stock |
$ | 0.73 | $ | 0.71 | ||||
|
|
|
|
|||||
Diluted: |
||||||||
Net Income Available for Common Stock |
$ | 0.73 | $ | 0.70 | ||||
|
|
|
|
|||||
Weighted Average Common Shares Outstanding: |
||||||||
Used in Basic Calculation |
82,870,931 | 82,223,428 | ||||||
|
|
|
|
|||||
Used in Diluted Calculation |
83,699,981 | 83,420,351 | ||||||
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-6-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
(Unaudited)
(Thousands of Dollars) |
December 31,
2011 |
September 30,
2011 |
||||||
ASSETS |
||||||||
Property, Plant and Equipment |
$ | 5,922,308 | $ | 5,646,918 | ||||
LessAccumulated Depreciation, Depletion and Amortization |
1,694,366 | 1,646,394 | ||||||
|
|
|
|
|||||
4,227,942 | 4,000,524 | |||||||
|
|
|
|
|||||
Current Assets |
||||||||
Cash and Temporary Cash Investments |
224,262 | 80,428 | ||||||
Hedging Collateral Deposits |
25,118 | 19,701 | ||||||
ReceivablesNet of Allowance for Uncollectible Accounts of $35,849 and $31,039, Respectively |
152,888 |
|
131,885
|
|
||||
Unbilled Utility Revenue |
47,335 | 17,284 | ||||||
Gas Stored Underground |
50,808 | 54,325 | ||||||
Materials and Suppliesat average cost |
27,263 | 27,932 | ||||||
Unrecovered Purchased Gas Costs |
3,002 | | ||||||
Other Current Assets |
43,516 | 38,334 | ||||||
Deferred Income Taxes |
14,921 | 15,423 | ||||||
|
|
|
|
|||||
589,113 | 385,312 | |||||||
|
|
|
|
|||||
Other Assets |
||||||||
Recoverable Future Taxes |
145,469 | 144,377 | ||||||
Unamortized Debt Expense |
14,579 | 10,571 | ||||||
Other Regulatory Assets |
570,927 | 574,644 | ||||||
Deferred Charges |
4,429 | 5,552 | ||||||
Other Investments |
81,055 | 79,365 | ||||||
Goodwill |
5,476 | 5,476 | ||||||
Fair Value of Derivative Financial Instruments |
106,115 | 76,085 | ||||||
Other |
2,650 | 2,836 | ||||||
|
|
|
|
|||||
930,700 | 898,906 | |||||||
|
|
|
|
|||||
Total Assets |
$ | 5,747,755 | $ | 5,284,742 | ||||
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-7-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
(Thousands of Dollars) |
December 31,
2011 |
September 30,
2011 |
||||||
CAPITALIZATION AND LIABILITIES |
||||||||
Capitalization: |
||||||||
Comprehensive Shareholders Equity |
||||||||
Common Stock, $1 Par Value |
||||||||
Authorized 200,000,000 Shares; |
||||||||
Issued and Outstanding 83,038,485 Shares and 82,812,677 Shares, Respectively |
$ | 83,038 | $ | 82,813 | ||||
Paid in Capital |
654,000 | 650,749 | ||||||
Earnings Reinvested in the Business |
1,237,242 | 1,206,022 | ||||||
|
|
|
|
|||||
Total Common Shareholders Equity Before Items of Other Comprehensive Loss |
1,974,280 | 1,939,584 | ||||||
Accumulated Other Comprehensive Loss |
(53,132 | ) | (47,699 | ) | ||||
|
|
|
|
|||||
Total Comprehensive Shareholders Equity |
1,921,148 | 1,891,885 | ||||||
Long-Term Debt, Net of Current Portion |
1,399,000 | 899,000 | ||||||
|
|
|
|
|||||
Total Capitalization |
3,320,148 | 2,790,885 | ||||||
|
|
|
|
|||||
Current and Accrued Liabilities |
||||||||
Notes Payable to Banks and Commercial Paper |
20,000 | 40,000 | ||||||
Current Portion of Long-Term Debt |
| 150,000 | ||||||
Accounts Payable |
105,209 | 126,709 | ||||||
Amounts Payable to Customers |
11,997 | 15,519 | ||||||
Dividends Payable |
29,479 | 29,399 | ||||||
Interest Payable on Long-Term Debt |
16,320 | 25,512 | ||||||
Customer Advances |
25,814 | 19,643 | ||||||
Customer Security Deposits |
17,685 | 17,321 | ||||||
Other Accruals and Current Liabilities |
146,251 | 94,787 | ||||||
Fair Value of Derivative Financial Instruments |
48,210 | 9,728 | ||||||
|
|
|
|
|||||
420,965 | 528,618 | |||||||
|
|
|
|
|||||
Deferred Credits |
||||||||
Deferred Income Taxes |
991,805 | 955,384 | ||||||
Taxes Refundable to Customers |
65,547 | 65,543 | ||||||
Unamortized Investment Tax Credit |
2,441 | 2,586 | ||||||
Cost of Removal Regulatory Liability |
144,770 | 135,940 | ||||||
Other Regulatory Liabilities |
100,832 | 94,684 | ||||||
Pension and Other Post-Retirement Liabilities |
467,396 | 481,520 | ||||||
Asset Retirement Obligations |
76,930 | 75,731 | ||||||
Other Deferred Credits |
156,921 | 153,851 | ||||||
|
|
|
|
|||||
2,006,642 | 1,965,239 | |||||||
|
|
|
|
|||||
Commitments and Contingencies |
| | ||||||
|
|
|
|
|||||
Total Capitalization and Liabilities |
$ | 5,747,755 | $ | 5,284,742 | ||||
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-8-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
Three Months Ended
December 31, |
||||||||
(Thousands of Dollars) | 2011 | 2010 | ||||||
OPERATING ACTIVITIES |
||||||||
Net Income Available for Common Stock |
$ | 60,699 | $ | 58,543 | ||||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |
||||||||
Depreciation, Depletion and Amortization |
62,547 | 53,313 | ||||||
Deferred Income Taxes |
39,398 | 36,600 | ||||||
Other |
2,375 | 3,543 | ||||||
Change in: |
||||||||
Hedging Collateral Deposits |
(5,417 | ) | (20,312 | ) | ||||
Receivables and Unbilled Utility Revenue |
(51,054 | ) | (53,984 | ) | ||||
Gas Stored Underground and Materials and Supplies |
(2,226 | ) | (5,828 | ) | ||||
Unrecovered Purchased Gas Costs |
(3,002 | ) | | |||||
Prepayments and Other Current Assets |
(5,182 | ) | 8,768 | |||||
Accounts Payable |
(21,500 | ) | 29,246 | |||||
Amounts Payable to Customers |
(3,522 | ) | (14,195 | ) | ||||
Customer Advances |
6,171 | (5 | ) | |||||
Customer Security Deposits |
364 | 188 | ||||||
Other Accruals and Current Liabilities |
(4,008 | ) | 1,387 | |||||
Other Assets |
(28,139 | ) | (10,463 | ) | ||||
Other Liabilities |
31,724 | 670 | ||||||
|
|
|
|
|||||
Net Cash Provided by Operating Activities |
79,228 | 87,471 | ||||||
|
|
|
|
|||||
INVESTING ACTIVITIES |
||||||||
Capital Expenditures |
(232,670 | ) | (193,802 | ) | ||||
Other |
(966 | ) | (298 | ) | ||||
|
|
|
|
|||||
Net Cash Used in Investing Activities |
(233,636 | ) | (194,100 | ) | ||||
|
|
|
|
|||||
FINANCING ACTIVITIES |
||||||||
Changes in Notes Payable to Banks and Commercial Paper |
(20,000 | ) | 20,500 | |||||
Net Proceeds from Issuance of Long-Term Debt |
496,085 | | ||||||
Reduction of Long-Term Debt |
(150,000 | ) | (200,000 | ) | ||||
Dividends Paid on Common Stock |
(29,398 | ) | (28,316 | ) | ||||
Net Proceeds from Issuance (Repurchase) of Common Stock |
1,555 | (3,104 | ) | |||||
|
|
|
|
|||||
Net Cash Provided by (Used in) Financing Activities |
298,242 | (210,920 | ) | |||||
|
|
|
|
|||||
Net Increase (Decrease) in Cash and Temporary Cash Investments |
143,834 | (317,549 | ) | |||||
Cash and Temporary Cash Investments at October 1 |
80,428 | 397,171 | ||||||
|
|
|
|
|||||
Cash and Temporary Cash Investments at December 31 |
$ | 224,262 | $ | 79,622 | ||||
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-9-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
Three Months Ended
December 31, |
||||||||
(Thousands of Dollars) | 2011 | 2010 | ||||||
Net Income Available for Common Stock |
$ | 60,699 | $ | 58,543 | ||||
|
|
|
|
|||||
Other Comprehensive Income (Loss), Before Tax: |
||||||||
Foreign Currency Translation Adjustment |
| 17 | ||||||
Reclassification Adjustment for Realized Foreign Currency Translation Loss in Net Income |
| 34 | ||||||
Unrealized Gain on Securities Available for Sale Arising During the Period |
712 | 2,540 | ||||||
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period |
2,155 | (27,136 | ) | |||||
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income |
(11,864 | ) | (9,053 | ) | ||||
|
|
|
|
|||||
Other Comprehensive Loss, Before Tax |
(8,997 | ) | (33,598 | ) | ||||
|
|
|
|
|||||
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period |
263 | 960 | ||||||
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period |
817 | (11,168 | ) | |||||
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income |
(4,644 | ) | (3,725 | ) | ||||
|
|
|
|
|||||
Income Taxes Net |
(3,564 | ) | (13,933 | ) | ||||
|
|
|
|
|||||
Other Comprehensive Loss |
(5,433 | ) | (19,665 | ) | ||||
|
|
|
|
|||||
Comprehensive Income |
$ | 55,266 | $ | 38,878 | ||||
|
|
|
|
See Notes to Condensed Consolidated Financial Statements
-10-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1Summary of Significant Accounting Policies
Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. The equity method is used to account for entities in which the Company has a non-controlling financial interest. All significant intercompany balances and transactions are eliminated.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2011, 2010 and 2009 that are included in the Companys 2011 Form 10-K. The consolidated financial statements for the year ended September 30, 2012 will be audited by the Companys independent registered public accounting firm after the end of the fiscal year.
The earnings for the three months ended December 31, 2011 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2012. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Companys business segments are discussed more fully in Note 7 Business Segment Information.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid investments purchased with a maturity of generally three months or less to be cash equivalents.
At December 31, 2011, the Company accrued $88.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $15.8 million of capital expenditures in the Pipeline and Storage segment and $14.5 million of capital expenditures in the All Other category at December 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at December 31, 2011 since they represent non-cash investing activities at that date. Accrued capital expenditures at December 31, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
At September 30, 2011, the Company accrued $63.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $7.3 million of capital expenditures in the Pipeline and Storage segment. In addition, the Company accrued $1.4 million of capital expenditures in the All Other category. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2011 and have been included in the Consolidated Statement of Cash Flows for the quarter ended December 31, 2011. Accrued capital expenditures at September 30, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.
-11-
Item 1. Financial Statements (Cont.)
At December 31, 2010, the Company accrued $60.7 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $2.0 million of capital expenditures in the Pipeline and Storage segment at December 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at December 31, 2010 since they represented non-cash investing activities at that date.
At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the quarter ended December 31, 2010.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At December 31, 2011, the Company had hedging collateral deposits of $4.5 million related to its exchange-traded futures contracts and $20.6 million related to its over-the-counter crude oil swap agreements. At September 30, 2011, the Company had hedging collateral deposits of $5.5 million related to its exchange-traded futures contracts and $14.2 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.
Gas Stored UndergroundCurrent. In the Utility segment, gas stored underground current is carried at lower of cost or market, on a LIFO method. Gas stored underground current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption Other Accruals and Current Liabilities. Such reserve, which amounted to $7.1 million at December 31, 2011, is reduced to zero by September 30 of each year as the inventory is replenished.
Property, Plant and Equipment. In the Companys Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $226.5 million and $226.3 million at December 31, 2011 and September 30, 2011, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to
-12-
Item 1. Financial Statements (Cont.)
calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At December 31, 2011, the ceiling exceeded the book value of the oil and gas properties by approximately $360.3 million.
Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):
At December 31, 2011 | At September 30, 2011 | |||||||
Funded Status of the Pension and Other Post-Retirement Benefit Plans |
$ | (89,587 | ) | $ | (89,587 | ) | ||
Net Unrealized Gain on Derivative Financial Instruments |
35,097 | 40,979 | ||||||
Net Unrealized Gain on Securities Available for Sale |
1,358 | 909 | ||||||
|
|
|
|
|||||
Accumulated Other Comprehensive Loss |
$ | (53,132 | ) | $ | (47,699 | ) | ||
|
|
|
|
Other Current Assets . The components of the Companys Other Current Assets are as follows (in thousands):
At December 31, 2011 | At September 30, 2011 | |||||||
Prepayments |
$ | 5,857 | $ | 9,489 | ||||
Prepaid Property and Other Taxes |
15,146 | 13,240 | ||||||
Federal Income Taxes Receivable |
378 | 385 | ||||||
State Income Taxes Receivable
|
5,089 | 6,124 | ||||||
Fair Values of Firm Commitments |
17,046 | 9,096 | ||||||
|
|
|
|
|||||
$ | 43,516 | $ | 38,334 | |||||
|
|
|
|
Earnings Per Common Share. Basic earnings per common share is computed by dividing net income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 191,285 and 23,478 securities excluded as being antidilutive for the quarters ended December 31, 2011 and 2010, respectively.
Stock-Based Compensation. During the quarter ended December 31, 2011, the Company granted 166,000 non-performance based SARs having a weighted average exercise price of $55.09 per share. The weighted average grant date fair value of these SARs was $11.20 per share. These SARs will be settled in shares of common stock of the Company and are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. The non-performance based SARs granted during the quarter ended December 31, 2011 vest annually in one-third increments and become exercisable on the third anniversary of the date of grant. The weighted average grant date fair value of these non-performance based SARs granted during the quarter ended December 31, 2011 was estimated on the date of grant using the same accounting treatment that is applied for stock options.
-13-
Item 1. Financial Statements (Cont.)
There were no stock options granted during the quarter ended December 31, 2011. The Company did not recognize a tax benefit related to the exercise of stock options and/or performance based SARs for the calendar years ended December 31, 2011 and December 31, 2010 due to tax loss carryforwards. The Company expects to recognize tax benefits of $14.2 million and $18.1 million in Paid in Capital related to calendar 2011 and calendar 2010 stock option and/or performance based SAR exercises, respectively, in future years as the tax loss carryforward is utilized.
The Company granted 41,525 restricted share awards (non-vested stock as defined by the current accounting literature) during the quarter ended December 31, 2011. The weighted average fair value of such restricted shares was $55.09 per share. In addition, the Company granted 56,000 restricted stock units during the quarter ended December 31, 2011. The weighted average fair value of such restricted stock units was $48.77 per share. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.
New Authoritative Accounting and Financial Reporting Guidance. In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Companys second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Companys first quarter of fiscal 2013 and is not expected to have a significant impact on the Companys financial statements.
In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a qualitative assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Companys annual impairment test performed in fiscal 2013. While early adoption is permitted, the Company has not adopted the new provisions to date.
In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Companys first quarter of fiscal 2014 and is not expected to have a significant impact on the Companys financial statements.
-14-
Item 1. Financial Statements (Cont.)
Note 2 Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Companys assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Companys financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of December 31, 2011 and September 30, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
Recurring Fair Value Measures | At fair value as of December 31, 2011 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents Money Market Mutual Funds |
$ | 180,312 | $ | | $ | | $ | 180,312 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Over the Counter Swaps Gas |
| 106,115 | | 106,115 | ||||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
21,696 | | | 21,696 | ||||||||||||
Common Stock Financial Services Industry |
4,197 | | | 4,197 | ||||||||||||
Other Common Stock |
272 | | | 272 | ||||||||||||
Hedging Collateral Deposits |
25,118 | | | 25,118 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 231,595 | $ | 106,115 | $ | | $ | 337,710 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures ContractsGas |
$ | 3,516 | $ | | $ | | $ | 3,516 | ||||||||
Over the Counter Swaps Oil |
| | 54,773 | 54,773 | ||||||||||||
Over the Counter Swaps Gas |
| (10,079 | ) | | (10,079 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 3,516 | $ | (10,079 | ) | $ | 54,773 | $ | 48,210 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 228,079 | $ | 116,194 | $ | (54,773 | ) | $ | 289,500 | |||||||
|
|
|
|
|
|
|
|
-15-
Item 1. Financial Statements (Cont.)
Recurring Fair Value Measures | At fair value as of September 30, 2011 | |||||||||||||||
(Thousands of Dollars) |
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: |
||||||||||||||||
Cash Equivalents Money Market Mutual Funds |
$ | 32,444 | $ | | $ | | $ | 32,444 | ||||||||
Derivative Financial Instruments: |
||||||||||||||||
Over the Counter Swaps Gas |
| 75,113 | | 75,113 | ||||||||||||
Over the Counter Swaps Oil |
| | 972 | 972 | ||||||||||||
Other Investments: |
||||||||||||||||
Balanced Equity Mutual Fund |
19,882 | | | 19,882 | ||||||||||||
Common Stock Financial Services Industry |
4,478 | | | 4,478 | ||||||||||||
Other Common Stock |
226 | | | 226 | ||||||||||||
Hedging Collateral Deposits |
19,701 | | | 19,701 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 76,731 | $ | 75,113 | $ | 972 | $ | 152,816 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Liabilities: |
||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||
Commodity Futures Contracts Gas |
$ | 3,292 | $ | | $ | | $ | 3,292 | ||||||||
Over the Counter Swaps Oil |
| | 6,382 | 6,382 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 3,292 | $ | | $ | 6,382 | $ | 9,674 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Net Assets/(Liabilities) |
$ | 73,439 | $ | 75,113 | $ | (5,410 | ) | $ | 143,142 | |||||||
|
|
|
|
|
|
|
|
Derivative Financial Instruments
At December 31, 2011 and September 30, 2011, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Companys Energy Marketing segment. Hedging collateral deposits of $4.5 million (at December 31, 2011) and $5.5 million (at September 30, 2011), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at December 31, 2011 and September 30, 2011 consist of natural gas price swap agreements used in the Companys Exploration and Production and Energy Marketing segments. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The derivative financial instruments reported in Level 3 consist of all of the Companys Exploration and Production segments crude oil price swap agreements at December 31, 2011 and September 30, 2011. Hedging collateral deposits of $20.6 million and $14.2 million associated with these crude oil price swap agreements have been reported in Level 1 at December 31, 2011 and September 30, 2011, respectively. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). Based on an assessment of the counterparties credit risk, the fair market value of the price swap agreements reported as Level 2 assets has been reduced by $2.2 million at December 31, 2011 and the fair market value of the price swap agreements reported as Level 2 and Level 3 assets has been reduced by $2.0 million at September 30, 2011. Based on an assessment of the Companys credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities at December 31, 2011 has been reduced by $0.1 million and the fair market value of the price swap agreements reported as Level 3 liabilities has not been reduced at September 30, 2011. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.
-16-
Item 1. Financial Statements (Cont.)
The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters ended December 31, 2011 and 2010, respectively. For the quarters ended December 31, 2011 and December 31, 2010, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.
Fair Value Measurements Using Unobservable Inputs (Level 3)
Total Gains/Losses | ||||||||||||||||||||
(Dollars in thousands) |
October 1,
2011 |
Gains/Losses
Realized and Included in Earnings |
Gains/Losses
Unrealized and Included in Other Comprehensive Income |
Transfer
In/Out of Level 3 |
December 31,
2011 |
|||||||||||||||
Derivative Financial Instruments (2) |
$ | (5,410 | ) | $ | 12,612 | (1) | $ | (61,975 | ) | $ | | $ | (54,773 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2011. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Fair Value Measurements Using Unobservable Inputs (Level 3)
Total Gains/Losses | ||||||||||||||||||||
(Dollars in thousands) |
October 1,
2010 |
Gains/Losses
Realized and Included in Earnings |
Gains/Losses
Unrealized and Included in Other Comprehensive Income |
Transfer In/
Out of Level 3 |
December 31,
2010 |
|||||||||||||||
Derivative Financial Instruments (2) |
$ | (16,483 | ) | $ | 3,602 | (1) | $ | (24,526 | ) | $ | | $ | (37,407 | ) | ||||||
|
|
|
|
|
|
|
|
|
|
(1) |
Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended December 31, 2010. |
(2) |
Derivative Financial Instruments are shown on a net basis. |
Note 3 Financial Instruments
Long-Term Debt. The fair market value of the Companys debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Companys credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands):
December 31, 2011 | September 30, 2011 | |||||||||||||||
Carrying
Amount |
Fair Value |
Carrying
Amount |
Fair Value | |||||||||||||
Long-Term Debt |
$ | 1,399,000 | $ | 1,536,798 | $ | 1,049,000 | $ | 1,198,585 |
-17-
Item 1. Financial Statements (Cont.)
The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Companys Consolidated Balance Sheets approximate fair value.
Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to short-term maturities of those financial instruments.
Other Investments. Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.
Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $54.9 million and $54.8 million at December 31, 2011 and September 30, 2011, respectively. The fair value of the equity mutual fund was $21.7 million at December 31, 2011 and $19.9 million at September 30, 2011. The gross unrealized gain on this equity mutual fund was $0.3 million at December 31, 2011. The gross unrealized loss on the equity mutual fund was $0.7 million at September 30, 2011. The fair value of the stock of an insurance company was $4.2 million at December 31, 2011 and $4.5 million at September 30, 2011. The gross unrealized gain on this stock was $1.8 million at December 31, 2011 and $2.1 million at September 30, 2011. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses derivative instruments to manage commodity price risk in the Exploration and Production and Energy Marketing segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the majority of the Companys hedges does not typically exceed 3 years.
The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheets at December 31, 2011 and September 30, 2011 as shown in the table below.
Fair Values of Derivative Instruments | ||||||||||||
(Dollar Amounts in Thousands) | ||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||
Derivatives Designated as Hedging Instruments |
Consolidated
Balance Sheet Location |
Fair Value |
Consolidated
Balance Sheet Location |
Fair Value | ||||||||
Commodity Contracts at December 31, 2011 |
Fair Value of
Derivative Financial Instruments |
$ | 106,115 |
Fair Value of
Derivative Financial Instruments |
$ | 48,210 | ||||||
Commodity Contracts at September 30, 2011 |
Fair Value of
Derivative Financial Instruments |
$ | 76,085 |
Fair Value of
Derivative Financial Instruments |
$ | 9,674 |
-18-
Item 1. Financial Statements (Cont.)
The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheets at December 31, 2011 and September 30, 2011.
Derivatives Designated as Hedging |
Fair Values of Derivative Instruments (Dollar Amounts in Thousands) |
|||
Instruments |
Gross Asset Derivatives |
Gross Liability Derivatives |
||
Commodity Contracts at December 31, 2011 |
$ 122,870 | $ 64,965 | ||
Commodity Contracts at September 30, 2011 |
$ 90,253 | $ 23,842 |
Cash flow hedges
For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.
As of December 31, 2011, the Companys Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):
Commodity |
Units |
|
Natural Gas |
54.7 Bcf (all short positions) | |
Crude Oil |
2,331,000 Bbls (all short positions) |
As of December 31, 2011, the Companys Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):
Commodity |
Units |
|
Natural Gas |
8.3 Bcf (5.7 Bcf short positions (forecasted storage withdrawals) and 2.6 Bcf long positions (forecasted storage injections)) |
As of December 31, 2011, the Companys Exploration and Production segment had $58.1 million ($33.6 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $36.8 million ($21.2 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments for both the Exploration and Production and Energy Marketing segment.
-19-
Item 1. Financial Statements (Cont.)
As of December 31, 2011, the Companys Energy Marketing segment had $2.5 million ($1.5 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that all of the gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain pertaining to derivative financial instruments for both the Exploration and Production and Energy Marketing segment.
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for
the
Three Months Ended December 31, 2011 and 2010 (Thousands of Dollars) |
||||||||||||||||||||||||||||||||
Derivatives in
|
Amount of Derivative Gain
or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31, |
Location of
Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) |
Amount of Derivative
Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31, |
Location of
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) |
Derivative Gain or
(Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31, |
|||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||
Commodity
Contracts Exploration & Production segment |
$ | (3,923 | ) | $ | (26,781 | ) |
|
Operating
Revenue |
|
$ | 5,420 | $ | 9,007 |
|
Operating
Revenue |
|
$ | | $ | | ||||||||||||
Commodity
Contracts Energy Marketing segment |
$ | 6,078 | $ | (269 | ) |
|
Purchased
Gas |
|
$ | 6,444 | $ | 46 |
|
Operating
Revenue |
|
$ | | $ | | |||||||||||||
Commodity
Contracts Pipeline & Storage segment |
$ | | $ | (86 | ) |
|
Operating
Revenue |
|
$ | | $ | |
|
Operating
Revenue |
|
$ | | $ | | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
Total | $ | 2,155 | $ | (27,136 | ) | $ | 11,864 | $ | 9,053 | $ | | $ | | |||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
-20-
Item 1. Financial Statements (Cont.)
Fair value hedges
The Companys Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Companys financial statements. As of December 31, 2011, the Companys Energy Marketing segment had fair value hedges covering approximately 10.6 Bcf (8.8 Bcf of fixed price sales commitments (all long positions) and 1.8 Bcf of fixed price purchase commitments (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.
Consolidated Statement of Income |
Gain/(Loss) on Derivative |
Gain/(Loss) on Commitment |
||
Operating Revenues |
$(625,482) | $625,482 | ||
Purchased Gas |
$1,076,443 | $(1,076,443) |
Derivatives in
Fair Value Hedging Relationships Energy
|
Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income |
Amount of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2011 (In thousands) |
||
Commodity Contracts Hedge of fixed price sales commitments of natural gas |
Operating Revenues | $ (625) | ||
Commodity Contracts Hedge of fixed price purchase commitments of natural gas |
Purchased Gas | $ 1,076 | ||
|
||||
$ 451 | ||||
|
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Companys counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with eleven counterparties of which ten are in a net gain position. On average, the Company had $10.5 million of credit exposure per counterparty in a gain position at December 31, 2011. The maximum credit exposure per counterparty in a gain position at December 31, 2011 was $19.2 million. The Company had not received any collateral from these counterparties at December 31, 2011 since the Companys gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties credit ratings declined to levels at which the counterparties were required to post collateral.
As of December 31, 2011, eight of the eleven counterparties to the Companys outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Companys credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Companys credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of
-21-
Item 1. Financial Statements (Cont.)
credit or treasury debt instruments). If the Companys outstanding derivative instrument contracts were in a liability position (or if the current liability were larger) and/or the Companys credit rating declined, then additional hedging collateral deposits may be required. At December 31, 2011, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $70.9 million according to the Companys internal model (discussed in Note 2 Fair Value Measurements). At December 31, 2011, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $44.7 million according to the Companys internal model (discussed in Note 2 Fair Value Measurements). For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $20.6 million in hedging collateral deposits at December 31, 2011. This is discussed in Note 1 under Hedging Collateral Deposits.
For its exchange traded futures contracts which are in a liability position, the Company had posted $4.5 million in hedging collateral as of December 31, 2011. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.
The Companys requirement to post hedging collateral deposits is based on the fair value determined by the Companys counterparties, which may differ from the Companys assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.
Note 4Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):
Three Months Ended | ||||||||
December 31, | ||||||||
2011 | 2010 | |||||||
Current Income Taxes |
||||||||
Federal |
$ | (7 | ) | $ | | |||
State |
1,334 | 1,452 | ||||||
Deferred Income Taxes |
||||||||
Federal |
31,338 | 29,936 | ||||||
State |
8,060 | 6,664 | ||||||
|
|
|
|
|||||
40,725 | 38,052 | |||||||
Deferred Investment Tax Credit |
(145 | ) | (174 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 40,580 | $ | 37,878 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Other Income |
$ | (145 | ) | $ | (174 | ) | ||
Income Tax Expense |
40,725 | 38,052 | ||||||
|
|
|
|
|||||
Total Income Taxes |
$ | 40,580 | $ | 37,878 | ||||
|
|
|
|
-22-
Item 1. Financial Statements (Cont.)
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference (in thousands):
Three Months Ended | ||||||||
December 31, | ||||||||
2011 | 2010 | |||||||
U.S. Income Before Income Taxes |
$ | 101,279 | $ | 96,421 | ||||
|
|
|
|
|||||
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% |
$ | 35,448 | $ | 33,747 | ||||
Increase (Reduction) in Taxes Resulting from: |
||||||||
State Income Taxes |
6,106 | 5,275 | ||||||
Miscellaneous |
(974 | ) | (1,144 | ) | ||||
|
|
|
|
|||||
Total Income Taxes |
$ | 40,580 | $ | 37,878 | ||||
|
|
|
|
Significant components of the Companys deferred tax liabilities and assets are as follows (in thousands):
At December 31, 2011 | At September 30, 2011 | |||||||
Deferred Tax Liabilities: |
||||||||
Property, Plant and Equipment |
$ | 1,116,690 | $ | 1,062,255 | ||||
Pension and Other Post-Retirement Benefit Costs |
213,170 | 217,302 | ||||||
Other |
67,876 | 70,389 | ||||||
|
|
|
|
|||||
Total Deferred Tax Liabilities |
1,397,736 | 1,349,946 | ||||||
|
|
|
|
|||||
Deferred Tax Assets: |
||||||||
Pension and Other Post-Retirement Benefit Costs |
(262,571 | ) | (263,606 | ) | ||||
Tax Loss Carryforwards |
(83,199 | ) | (71,516 | ) | ||||
Other |
(75,082 | ) | (74,863 | ) | ||||
|
|
|
|
|||||
Total Deferred Tax Assets |
(420,852 | ) | (409,985 | ) | ||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 976,884 | $ | 939,961 | ||||
|
|
|
|
|||||
Presented as Follows: |
||||||||
Net Deferred Tax Liability/(Asset) Current |
$ | (14,921 | ) | $ | (15,423 | ) | ||
Net Deferred Tax Liability Non-Current |
991,805 | 955,384 | ||||||
|
|
|
|
|||||
Total Net Deferred Income Taxes |
$ | 976,884 | $ | 939,961 | ||||
|
|
|
|
As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Tax benefits of $14.2 million and $18.1 million for the periods ending December 31, 2011 and September 30, 2011, respectively, relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefits are realized.
-23-
Item 1. Financial Statements (Cont.)
Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $65.5 million at December 31, 2011 and September 30, 2011. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $145.5 million and $144.4 million at December 31, 2011 and September 30, 2011, respectively.
The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2011 in accordance with the Compliance Assurance Process (CAP). The CAP audit employs a real time review of the Companys books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2008 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Companys application to change its tax method of accounting for certain capitalized costs relating to its utility property. Local IRS examiners proposed to disallow most of the tax accounting method change recorded by the Company in fiscal 2009 and fiscal 2010. The Company has filed protests with the IRS Appeals Office disputing the local IRS findings.
The Company is also subject to various routine state income tax examinations. The Companys principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.
Note 5Capitalization
Common Stock. During the three months ended December 31, 2011, the Company issued 272,292 original issue shares of common stock as a result of stock option exercises and 41,525 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). In addition, the Company issued 31,474 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan. The Company also issued 4,050 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Companys 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors services during the three months ended December 31, 2011. Holders of stock options, SARs or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2011, 123,533 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
Current Portion of Long-Term Debt. There was no Current Portion of Long-Term Debt at December 31, 2011. Current Portion of Long-Term Debt at September 30, 2011 consisted of $150 million of 6.70% notes that matured in November 2011.
Long-Term Debt. On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Companys 6.70% notes in November 2011.
-24-
Item 1. Financial Statements (Cont.)
Note 6Commitments and Contingencies
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Companys policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.
The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design work plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of $14.3 million has been recorded.
At December 31, 2011, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $16.0 million to $20.2 million. The minimum estimated liability of $16.0 million, which includes the $14.3 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.
The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Companys present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
Note 7 Business Segment Information
The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production and Energy Marketing. The division of the Companys operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2011 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Companys 2011 Form 10-K. As for segment assets, the only significant changes from the segment assets disclosed in the 2011 Form 10-K involve the Exploration and Production segment as well as Corporate and Intersegment Eliminations. Total Exploration and Production segment assets have increased by $216.6 million while Corporate and Intersegment Eliminations assets have increased by $204.6 million.
-25-
Item 1. Financial Statements (Cont.)
Quarter Ended December 31, 2011 (Thousands)
Utility |
Pipeline and
Storage |
Exploration
and Production |
Energy
Marketing |
Total
Reportable Segments |
All Other |
Corporate and
Intersegment Eliminations |
Total
Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 208,810 | $ | 35,225 | $ | 135,974 | $ | 51,222 | $ | 431,231 | $ | 937 | $ | 255 | $ | 432,423 | ||||||||||||||||
Intersegment Revenues |
$ | 4,389 | $ | 21,064 | $ | | $ | 287 | $ | 25,740 | $ | 3,362 | $ | (29,102 | ) | $ | | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 19,353 | $ | 9,959 | $ | 30,315 | $ | 429 | $ | 60,056 | $ | 1,404 | $ | (761 | ) | $ | 60,699 |
Quarter Ended December 31, 2010 (Thousands)
Utility |
Pipeline and
Storage |
Exploration
and Production |
Energy
Marketing |
Total
Reportable Segments |
All Other |
Corporate and
Intersegment Eliminations |
Total
Consolidated |
|||||||||||||||||||||||||
Revenue from External Customers |
$ | 242,842 | $ | 33,513 | $ | 120,168 | $ | 53,652 | $ | 450,175 | $ | 549 | $ | 224 | $ | 450,948 | ||||||||||||||||
Intersegment Revenues |
$ | 4,570 | $ | 19,882 | $ | | $ | | $ | 24,452 | $ | 1,678 | $ | (26,130 | ) | $ | | |||||||||||||||
Segment Profit: |
||||||||||||||||||||||||||||||||
Net Income (Loss) |
$ | 22,990 | $ | 8,578 | $ | 27,373 | $ | 932 | $ | 59,873 | $ | (574 | ) | $ | (756 | ) | $ | 58,543 |
Note 8 Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Retirement Plan | Other Post-Retirement Benefits | |||||||||||||||
Three months ended December 31, | 2011 | 2010 | 2011 | 2010 | ||||||||||||
Service Cost |
$ | 3,551 | $ | 3,693 | $ | 1,004 | $ | 1,069 | ||||||||
Interest Cost |
10,381 | 10,669 | 5,329 | 5,471 | ||||||||||||
Expected Return on Plan Assets |
(14,925 | ) | (14,776 | ) | (7,243 | ) | (7,291 | ) | ||||||||
Amortization of Prior Service Cost |
67 | 147 | (534 | ) | (427 | ) | ||||||||||
Amortization of Transition Amount |
| | 3 | 135 | ||||||||||||
Amortization of Losses |
9,904 | 8,718 | 6,014 | 5,948 | ||||||||||||
Net Amortization and Deferral |
||||||||||||||||
For Regulatory Purposes (Including Volumetric Adjustments) (1) |
(1,802 | ) | (1,793 | ) | 2,132 | 1,921 | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net Periodic Benefit Cost |
$ | 7,176 | $ | 6,658 | $ | 6,705 | $ | 6,826 | ||||||||
|
|
|
|
|
|
|
|
(1) |
The Companys policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months. |
-26-
Item 1. Financial Statements (Concl.)
Employer Contributions. During the three months ended December 31, 2011, the Company contributed $22.5 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $5.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2012, the Company expects to contribute between $16.0 and $27.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2012, the Company expects to contribute between $14.0 and $15.0 million to its VEBA trusts and 401(h) accounts.
-27-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
[Please note that this overview is a high-level summary
of items that are discussed in greater detail in subsequent sections of this report.]
The Company is a diversified energy holding company that owns a number of subsidiary operating companies, and reports financial results in four reportable business segments. For the quarter ended December 31, 2011 compared to the quarter ended December 31, 2010, the Company experienced an increase in earnings of $2.2 million, primarily due to higher earnings in the Exploration and Production segment and the Pipeline and Storage segment, as well as in the All Other category. Lower earnings in the Utility and Energy Marketing segments partly offset these increases. For further discussion of the Companys earnings, refer to the Results of Operations section below.
The Marcellus Shale is a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. Due to the depth at which this formation is found, drilling and completion costs, including the drilling and completion of horizontal wells with hydraulic fracturing, are very expensive. However, independent geological studies have indicated that this formation could yield natural gas reserves measured in the trillions of cubic feet. The Company controls the natural gas interests associated with approximately 745,000 net acres within the Marcellus Shale area, with a majority of the interests held in fee, carrying no royalty and no lease expirations. The Companys reserve base has grown substantially from development in the Marcellus Shale. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 331 Bcf at September 30, 2010 to 607 Bcf at September 30, 2011. With this in mind, and with a natural desire to realize the value of these assets in a responsible and orderly fashion, the Company has spent significant amounts of capital in this region. For the quarter ended December 31, 2011, the Company spent $172.0 million towards the development of the Marcellus Shale.
Coincident with the development of its Marcellus Shale acreage, the Companys Pipeline and Storage segment is building pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. One such project, Empires Tioga County Extension Project, was placed in service in November 2011. Supply Corporations planned Northern Access expansion project is also considered significant. Just like the Tioga County Extension Project, it is designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. During the past two years, Empire and Supply Corporation experienced a decline in the volumes of natural gas received at the Canada/United States border at the Niagara River to be shipped across their systems. The historical price advantage for gas sold at the Niagara import points has declined as production in the Canadian producing regions has declined or been diverted to other demand areas, and as production from new shale plays has increased in the United States. This factor has been causing shippers to seek alternative gas supplies and consequently alternative transportation routes. Empires Tioga County Extension Project is currently providing one such alternative transportation route and Supply Corporations Northern Access expansion project is designed to provide another alternative transportation route. These projects, which are discussed more completely in the Investing Cash Flow section that follows, have or will involve significant capital expenditures.
From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs for all of the above projects by using cash from operations. In addition, the Companys December 2011 issuance of $500.0 million of 4.90% notes due in December 2021 has enhanced its liquidity position to meet these needs. On January 6, 2012, the Company entered into an Amended and Restated Credit Agreement that replaces the Companys $300.0 million committed credit facility with a similar committed credit facility totaling $750.0 million that extends to January 6, 2017.
-28-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
The possibility of environmental risks associated with a well completion technology referred to as hydraulic fracturing continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Companys experience, one that the Company believes has little negative impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. For example, New York State had a moratorium in place that prevented hydraulic fracturing of new horizontal wells in the Marcellus Shale. The moratorium ended in July 2011 and the DEC has issued its recommendations for shale development and production. However, the recommendations have not gone into effect to date. Due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the final outcome of the DECs recommendations are not expected to have a significant impact on the Companys plans for Marcellus Shale development. Please refer to the Risk Factors section of the Form 10-K for the year ended September 30, 2011 for further discussion.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to Critical Accounting Estimates in Item 7 of the Companys 2011 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.
Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Companys oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the ceiling) is compared with the book value of the Companys oil and gas properties at the balance sheet date. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At December 31, 2011, the ceiling exceeded the book value of the oil and gas properties by approximately $360.3 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2011, based on posted Midway Sunset prices was $103.62 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2011, based on the quoted Henry Hub spot price for natural gas, was $4.12 per MMBtu. (Note Because actual pricing of the Companys various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended December 31, 2011.) If natural gas average prices used in the ceiling test calculation at December 31, 2011 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Companys oil and gas properties by approximately $187.9 million. If crude oil average prices used in the ceiling test calculation at December 31, 2011 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Companys oil and gas properties by approximately $315.3 million. If both natural gas and crude oil average prices used in the ceiling test calculation at December 31, 2011 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Companys oil and gas properties by approximately $142.9 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to Oil and Gas Exploration and Development Costs under Critical Accounting Estimates in Item 7 of the Companys 2011 Form 10-K.
-29-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
RESULTS OF OPERATIONS
Earnings
The Companys earnings were $60.7 million for the quarter ended December 31, 2011 compared with earnings of $58.5 million for the quarter ended December 31, 2010. The increase in earnings of $2.2 million is primarily a result of higher earnings in the Exploration and Production segment, the Pipeline and Storage segment and the All Other category. Lower earnings in the Utility and Energy Marketing segments partially offset these increases.
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.
Earnings (Loss) by Segment
Three Months Ended December 31 (Thousands) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Utility |
$ | 19,353 | $ | 22,990 | $ | (3,637 | ) | |||||
Pipeline and Storage |
9,959 | 8,578 | 1,381 | |||||||||
Exploration and Production |
30,315 | 27,373 | 2,942 | |||||||||
Energy Marketing |
429 | 932 | (503 | ) | ||||||||
|
|
|
|
|
|
|||||||
Total Reportable Segments |
60,056 | 59,873 | 183 | |||||||||
All Other |
1,404 | (574 | ) | 1,978 | ||||||||
Corporate |
(761 | ) | (756 | ) | (5 | ) | ||||||
|
|
|
|
|
|
|||||||
Total Consolidated |
$ | 60,699 | $ | 58,543 | $ | 2,156 | ||||||
|
|
|
|
|
|
Utility
Utility Operating Revenues
Three Months Ended December 31 (Thousands) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Retail Sales Revenues: |
||||||||||||
Residential |
$ | 148,263 | $ | 177,189 | $ | (28,926 | ) | |||||
Commercial |
17,645 | 22,545 | (4,900 | ) | ||||||||
Industrial |
1,022 | 1,244 | (222 | ) | ||||||||
|
|
|
|
|
|
|||||||
166,930 | 200,978 | (34,048 | ) | |||||||||
|
|
|
|
|
|
|||||||
Transportation |
34,965 | 35,412 | (447 | ) | ||||||||
Off-System Sales |
9,145 | 8,889 | 256 | |||||||||
Other |
2,159 | 2,133 | 26 | |||||||||
|
|
|
|
|
|
|||||||
$ | 213,199 | $ | 247,412 | $ | (34,213 | ) | ||||||
|
|
|
|
|
|
Utility Throughput
Three Months Ended December 31 (MMcf) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Retail Sales: |
||||||||||||
Residential |
14,549 | 17,160 | (2,611 | ) | ||||||||
Commercial |
1,994 | 2,469 | (475 | ) | ||||||||
Industrial |
101 | 146 | (45 | ) | ||||||||
|
|
|
|
|
|
|||||||
16,644 | 19,775 | (3,131 | ) | |||||||||
|
|
|
|
|
|
|||||||
Transportation |
16,928 | 18,110 | (1,182 | ) | ||||||||
Off-System Sales |
2,745 | 1,863 | 882 | |||||||||
|
|
|
|
|
|
|||||||
36,317 | 39,748 | (3,431 | ) | |||||||||
|
|
|
|
|
|
-30-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Degree Days
Three Months Ended December 31 |
Percent
Colder (Warmer) Than |
|||||||||||||||||||
Normal | 2011 | 2010 | Normal (1) | Prior Year (1) | ||||||||||||||||
Buffalo |
2,260 | 1,848 | 2,332 | (18.2 | ) | (20.8 | ) | |||||||||||||
Erie |
2,081 | 1,721 | 2,160 | (17.3 | ) | (20.3 | ) |
(1) |
Percents compare actual 2011 degree days to normal degree days and actual 2011 degree days to actual 2010 degree days. |
2011 Compared with 2010
Operating revenues for the Utility segment decreased $34.2 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. This decrease largely resulted from a $34.0 million decrease in retail gas sales revenues. The decrease in retail gas sales revenues was primarily due to warmer weather combined with the recovery of lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from lower volumes sold combined with a lower cost of purchased gas. The Utility segments average cost of purchased gas, including the cost of transportation and storage, was $5.78 per Mcf for the three months ended December 31, 2011, a decrease of 5% from the average cost of $6.06 per Mcf for the three months ended December 31, 2010.
The increase in off-system sales revenues was largely due to an increase in off-system sales volume. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins. The decrease in transportation revenues of $0.4 million was primarily due to a 1.2 Bcf decrease in transportation throughput, largely the result of warmer weather. The decrease in transportation revenues was partially offset by the migration of customers from retail sales to transportation service.
The Utility segments earnings for the quarter ended December 31, 2011 were $19.4 million, a decrease of $3.6 million when compared with earnings of $23.0 million for the quarter ended December 31, 2010. The decrease in earnings is largely attributable to warmer weather ($2.3 million) and various routine regulatory adjustments ($0.9 million). In addition, earnings were negatively impacted by higher operating expenses of $0.3 million (largely the result of higher personnel costs and outside services). These decreases were partially offset by the positive earnings impact of lower interest expense ($0.4 million), which was largely due to lower interest on deferred gas costs.
The impact of weather on the Utility segments New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segments New York customers. For the quarter ended December 31, 2011, the WNC preserved earnings of approximately $1.4 million, as the weather was warmer than normal. For the quarter ended December 31, 2010, the WNC reduced earnings by $0.1 million, as it was colder than normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
Three Months Ended December 31 (Thousands) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Firm Transportation |
$ | 39,132 | $ | 34,950 | $ | 4,182 | ||||||
Interruptible Transportation |
402 | 314 | 88 | |||||||||
|
|
|
|
|
|
|||||||
39,534 | 35,264 | 4,270 | ||||||||||
|
|
|
|
|
|
|||||||
Firm Storage Service |
16,498 | 16,603 | (105 | ) | ||||||||
Interruptible Storage Service |
| 17 | (17 | ) | ||||||||
Other |
257 | 1,511 | (1,254 | ) | ||||||||
|
|
|
|
|
|
|||||||
$ | 56,289 | $ | 53,395 | $ | 2,894 | |||||||
|
|
|
|
|
|
-31-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Pipeline and Storage Throughput
Three Months Ended December 31 (MMcf) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Firm Transportation |
83,608 | 89,249 | (5,641 | ) | ||||||||
Interruptible Transportation |
808 | 125 | 683 | |||||||||
|
|
|
|
|
|
|||||||
84,416 | 89,374 | (4,958 | ) | |||||||||
|
|
|
|
|
|
2011 Compared with 2010
Operating revenues for the Pipeline and Storage segment increased $2.9 million in the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. The increase was primarily due to an increase in transportation revenues of $4.3 million, largely due to new contracts for transportation service on Supply Corporations Line N Expansion Project, which was placed in service in October 2011, and Empires Tioga County Extension Project, which was placed in service in November 2011. Both projects provide pipeline capacity for Marcellus Shale production and are discussed in the Investing Cash Flow section that follows. The increase in transportation revenues was partially offset by a decrease in efficiency gas revenues of $1.2 million (reported as a part of other revenue in the table above) resulting from lower natural gas prices and an adjustment to reduce the carrying value of Supply Corporations efficiency gas inventory to market value during the quarter ended December 31, 2011. Under Supply Corporations tariff with shippers, Supply Corporation is allowed to retain a set percentage of shipper-supplied gas as compressor fuel and for other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as inventory. That inventory is later sold to buyers on the open market. The excess gas that is retained as inventory, as well as any gains resulting from the sale of such inventory, represent efficiency gas revenue to Supply Corporation.
Volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire. While transportation volume decreased by 5.0 Bcf largely due to warmer weather, there was little impact on revenues due to Supply Corporation and Empires straight fixed-variable rate design.
The Pipeline and Storage segments earnings for the quarter ended December 31, 2011 were $10.0 million, an increase of $1.4 million when compared with earnings of $8.6 million for the quarter ended December 31, 2010. The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $2.8 million, as discussed above, combined with an increase in the allowance for funds used during construction (equity component) of $0.8 million primarily due to construction during the current quarter on Supply Corporations Line N Expansion Project and Line N 2012 Expansion Project and Empires Tioga County Extension Project. These earnings increases were partially offset by the earnings impact associated with lower efficiency gas revenues ($0.8 million), as discussed above, higher depreciation expense ($0.7 million) and higher operating expenses ($0.6 million). The increase in depreciation expense is primarily the result of additional projects that were placed in service in the last year. The increase in operating expenses can be attributed primarily to higher pension expense and additional costs associated with compliance with federal/state mandates and Supply Corporations current rate case.
-32-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Exploration and Production
Exploration and Production Operating Revenues
Three Months Ended December 31 (Thousands) | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Gas (after Hedging) |
$ | 66,512 | $ | 58,009 | $ | 8,503 | ||||||
Oil (after Hedging) |
65,671 | 58,692 | 6,979 | |||||||||
Gas Processing Plant |
6,961 | 6,683 | 278 | |||||||||
Other |
(31 | ) | (114 | ) | 83 | |||||||
Intrasegment Elimination (1) |
(3,139 | ) | (3,102 | ) | (37 | ) | ||||||
|
|
|
|
|
|
|||||||
$ | 135,974 | $ | 120,168 | $ | 15,806 | |||||||
|
|
|
|
|
|
(1) |
Represents the elimination of certain West Coast gas production revenue included in Gas (after Hedging) in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plants Purchased Gas expense. |
Production Volumes
Three Months Ended December 31 | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Gas Production (MMcf) |
||||||||||||
Appalachia |
13,111 | 8,082 | 5,029 | |||||||||
West Coast |
817 | 935 | (118 | ) | ||||||||
Gulf Coast |
| 2,013 | (2,013 | ) | ||||||||
|
|
|
|
|
|
|||||||
Total Production |
13,928 | 11,030 | 2,898 | |||||||||
|
|
|
|
|
|
|||||||
Oil Production (Mbbl) |
||||||||||||
Appalachia |
10 | 10 | | |||||||||
West Coast |
709 | 654 | 55 | |||||||||
Gulf Coast |
| 106 | (106 | ) | ||||||||
|
|
|
|
|
|
|||||||
Total Production |
719 | 770 | (51 | ) | ||||||||
|
|
|
|
|
|
Average Prices
Three Months Ended December 31 | 2011 | 2010 |
Increase
(Decrease) |
|||||||||
Average Gas Price/Mcf |
||||||||||||
Appalachia |
$ | 3.39 | $ | 4.03 | $ | (0.64 | ) | |||||
West Coast |
$ | 4.95 | $ | 3.92 | $ | 1.03 | ||||||
Gulf Coast |
N/M | $ | 4.55 | N/M | ||||||||
Weighted Average |
$ | 3.48 | $ | 4.11 | $ | (0.63 | ) | |||||
Weighted Average After Hedging |
$ | 4.78 | $ | 5.26 | $ | (0.48 | ) | |||||
Average Oil Price/Bbl |
||||||||||||
Appalachia |
$ | 88.16 | $ | 81.40 | $ | 6.76 | ||||||
West Coast |
$ | 109.23 | $ | 80.45 | $ | 28.78 | ||||||
Gulf Coast |
N/M | $ | 83.97 | N/M | ||||||||
Weighted Average |
$ | 108.93 | $ | 80.95 | $ | 27.98 | ||||||
Weighted Average After Hedging |
$ | 91.38 | $ | 76.24 | $ | 15.14 |
2011 Compared with 2010
Operating revenues for the Exploration and Production segment increased $15.8 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. Gas production revenue after hedging increased $8.5 million primarily due to production increases in the Appalachian division, partially offset by decreases in Gulf Coast production. The increase in Appalachian
-33-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
production was primarily due to increased development within the Marcellus Shale formation, primarily in Tioga County, Pennsylvania. The decrease in Gulf Coast gas production resulted from the sale of the Exploration and Production segments offshore oil and natural gas properties in April 2011. Increases in natural gas production were partially offset by a $0.48 per Mcf decrease in the weighted average price of gas after hedging. Oil production revenue after hedging increased $7.0 million due to an increase in the weighted average price of oil after hedging ($15.14 per Bbl). This increase was partially offset by a decrease in production as a result of the aforementioned sale of Gulf Coast offshore properties.
The Exploration and Production segments earnings for the quarter ended December 31, 2011 were $30.3 million, an increase of $2.9 million when compared to earnings of $27.4 million for the quarter ended December 31, 2010. Higher natural gas production in the Appalachian region, higher crude oil prices in the West Coast region, and higher crude oil production in the West Coast region increased earnings by $17.1 million, $7.6 million, and $2.6 million, respectively. Lower interest expense ($0.6 million) due to lower average interest rates further contributed to the earnings increase. Lower natural gas and crude oil revenues from the Gulf Coast region ($12.1 million) due to the sale of the offshore oil and natural gas properties partially offset the earnings increase. In addition, lower natural gas prices in the Appalachian and West Coast regions ($5.2 million) further decreased earnings. Earnings were further reduced by higher depletion expense ($5.1 million), higher general, administrative and other operating expenses ($1.4 million), higher income tax expense ($0.9 million), and higher lease operating expenses ($0.8 million). The increase in depletion expense is primarily due to an increase in production and depletable base (largely due to increased capital spending in the Appalachian region, specifically related to the development of Marcellus Shale properties). The increase in lease operating expenses is largely attributable to a higher number of producing properties and higher transportation costs in the Appalachian region combined with higher steam fuel costs in the West Coast region. This was partially offset by the elimination of lease operating expenses in the Gulf Coast region. The increase in income taxes is attributable to higher state income taxes. Higher personnel costs are largely responsible for the increase in general, administrative and other operating expenses.
Energy Marketing
Energy Marketing Operating Revenues
Three Months Ended December 31 (Thousands) | 2011 | 2010 | Decrease | |||||||||
Natural Gas (after Hedging) |
$ | 51,498 | $ | 53,639 | $ | (2,141 | ) | |||||
Other |
11 | 13 | (2 | ) | ||||||||
|
|
|
|
|
|
|||||||
$ | 51,509 | $ | 53,652 | $ | (2,143 | ) | ||||||
|
|
|
|
|
|
Energy Marketing Volume
Three Months Ended December 31 | 2011 | 2010 | Decrease | |||||||||
Natural Gas (MMcf) |
10,312 | 10,746 | (434 | ) |
2011 Compared with 2010
Operating revenues for the Energy Marketing segment decreased $2.1 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. The decrease primarily reflects a decline in gas sales revenue due largely to a decrease in volume sold. Warmer weather is primarily responsible for the decrease in volume. The decrease in volume also reflects a decrease in volume sold to low-margin wholesale customers. Such transactions had the effect of decreasing revenue and volume sold with minimal impact to earnings.
-34-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
The Energy Marketing segments earnings for the quarter ended December 31, 2011 were $0.4 million, a decrease of $0.5 million when compared with earnings of $0.9 million for the quarter ended December 31, 2010. This decrease was largely attributable to a decline in margin of $0.4 million and higher operating costs of $0.1 million. The decrease in margin was primarily due to lower average margins per Mcf as well as lower volume sold to retail customers.
Corporate and All Other
2011 Compared with 2010
Corporate and All Other operations recorded net income of $0.6 million for the quarter ended December 31, 2011 compared with a loss of $1.3 million for the quarter ended December 31, 2010. The increase in earnings was largely due to higher gathering and processing revenues of $1.0 million, a reduction in losses from unconsolidated subsidiaries of $0.7 million, lower interest expense of $0.7 million and higher revenues from sales of standing timber of $0.4 million, partially offset by lower interest income of $0.5 million. The higher gathering and processing revenues are due to Midstream Corporations increase in gathering operations for Marcellus Shale gas in Tioga County, Pennsylvania. The loss from unconsolidated subsidiaries of $0.7 million that occurred during the quarter ended December 31, 2010 was largely due to lower renewable energy credit revenue recorded by Seneca Energy and Model City. This did not recur during the quarter ended December 31, 2011 as Seneca Energy and Model City were sold in February 2011. The decrease in interest expense was due to lower interest rates on borrowings. In November 2011, $150 million of 6.70% notes matured. In December 2011, the Company issued $500 million of notes at 4.90%. The decrease in interest income was due to lower interest collected from the Companys Exploration and Production segment as a result of lower interest rates on borrowings discussed above.
Other Income
Other income increased $1.4 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. The increase is primarily attributed to a reduction in losses from unconsolidated subsidiaries of $1.0 million. It also reflects a $0.8 million increase in allowance for funds used during construction in the Pipeline and Storage segment. These factors were partially offset by a $0.4 million gain on the sale of Horizon Energy Development for the quarter ended December 31, 2010, which did not recur during the quarter ended December 31, 2011.
Interest Expense on Long-Term Debt
Interest on long-term debt decreased $1.6 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. This decrease is primarily the result of lower average interest rates coupled with a slightly lower average amount of long-term debt outstanding. The Company repaid $150 million of 6.70% notes that matured in November 2011. In December 2011, the Company issued $500.0 million of 4.90% notes due in December 2021.
Other Interest Expense
Other interest expense decreased $0.6 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. The decrease is mainly due to lower interest expense on regulatory deferrals (primarily interest on deferred gas costs) in the Utility segment.
-35-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
CAPITAL RESOURCES AND LIQUIDITY
The Companys primary sources of cash during the three-month period ended December 31, 2011 consisted of proceeds from the issuance of long-term debt and cash provided by operating activities. The Companys primary source of cash during the three-month period ended December 31, 2010 consisted of cash provided by operating activities. This source of cash was supplemented by short-term borrowings for the quarter ended December 31, 2010. During the three months ended December 31, 2011 and December 31, 2010, the common stock used to fulfill the requirements of the Companys 401(k) plans was obtained via open market purchases. In April 2011, the Company began issuing original issue shares for the Direct Stock Purchase and Dividend Reinvestment Plan.
Operating Cash Flow
Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization and deferred income taxes.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segments New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.
Because of the seasonal nature of the heating business in the Utility and Energy Marketing segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.
The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption Other Accruals and Current Liabilities. Such reserve is reduced as the inventory is replenished.
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $79.2 million for the three months ended December 31, 2011, a decrease of $8.3 million when compared with the $87.5 million provided by operating activities for the three months ended December 31, 2010. The decrease in cash provided by operating activities is primarily due to an increase in cash used in operations in the Energy Marketing segment and lower cash provided by operations in the Utility segment, both of which were partially offset by an increase in cash provided by operations in the Exploration and Production segment. The variation in the Energy Marketing segment can be attributed to lower customer advances due to low gas prices combined with hedging collateral account fluctuations. The decrease in the Utility segment can be attributed to the timing of gas cost recovery. The increase in the Exploration and Production segment reflects higher cash receipts from oil and natural gas production in the West Coast and Appalachian regions combined with hedging collateral account fluctuations, which both offset the loss of cash flow from the Companys former oil and natural gas properties in the Gulf of Mexico.
-36-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Investing Cash Flow
Expenditures for Long-Lived Assets
The Companys expenditures for long-lived assets totaled $279.0 million for the three months ended December 31, 2011 and $200.9 million for the three months ended December 31, 2010. The table below presents these expenditures:
Total Expenditures for Long-Lived Assets
Three Months Ended December 31, (Millions) |
2011 | 2010 | Increase | |||||||||
Utility: |
||||||||||||
Capital Expenditures |
$ | 11.3 | $ | 10.9 | $ | 0.4 | ||||||
Pipeline and Storage: |
||||||||||||
Capital Expenditures |
44.2 | (1)(2) | 9.2 | (3) | 35.0 | |||||||
Exploration and Production: |
||||||||||||
Capital Expenditures |
191.9 | (1)(2) | 179.8 | (3)(4) | 12.1 | |||||||
All Other: |
||||||||||||
Capital Expenditures |
31.6 | (1)(2) | 1.0 | 30.6 | ||||||||
|
|
|
|
|
|
|||||||
$ | 279.0 | $ | 200.9 | $ | 78.1 | |||||||
|
|
|
|
|
|
(1) |
Capital expenditures for the Exploration and Production segment include $88.1 million of accrued capital expenditures at December 31, 2011, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment include $15.8 million of accrued capital expenditures at December 31, 2011. In addition, capital expenditures for the All Other category include $14.5 million of accrued capital expenditures at December 31, 2011. These amounts have been excluded from the Consolidated Statement of Cash Flows at December 31, 2011 since they represent non-cash investing activities at that date. |
(2) |
Capital expenditures for the Exploration and Production segment for the three months ended December 31, 2011 exclude $63.5 million of capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment for the three months ended December 31, 2011 exclude $7.3 million of capital expenditures. Capital expenditures for the All Other category for the three months ended December 31, 2011 exclude $1.4 million of capital expenditures. These amounts were accrued at September 30, 2011 and paid during the three months ended December 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since they represented non-cash investing activities at that date. These amounts have been included in the Consolidated Statement of Cash Flows at December 31, 2011. |
(3) |
Capital expenditures include $60.7 million of accrued capital expenditures for the Exploration and Production segment at December 31, 2010, the majority of which was in the Appalachian region. In addition, capital expenditures for the Pipeline and Storage segment include $2.0 million of accrued capital expenditures at December 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at December 31, 2010 since they represented non-cash investing activities at that date. |
(4) |
Capital expenditures for the Exploration and Production segment for the three months ended December 31, 2010 excludes $55.5 million of capital expenditures, the majority of which was in the Appalachian region. This amount was accrued at September 30, 2010 and paid during the three months ended December 31, 2010. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. The amount was included in the Consolidated Statement of Cash Flows at December 31, 2010. |
Utility
The majority of the Utility capital expenditures for the three months ended December 31, 2011 and December 31, 2010 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
-37-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures for the three months ended December 31, 2011 were related to the construction of Empires Tioga County Extension Project, and Supply Corporations Line N 2012 Expansion Project and Northern Access expansion project, as discussed below. The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2011 include $17.4 million spent on the Tioga County Extension Project, $6.6 million spent on the Line N 2012 Expansion Project, and $2.5 million spent on the Northern Access expansion project. The Pipeline and Storage capital expenditures for the three months ended December 31, 2011 also include additions, improvements, and replacements to this segments transmission and gas storage systems. The majority of the Pipeline and Storage capital expenditures for the three months ended December 31, 2010 were related to additions, improvements, and replacements to this segments transmission and gas storage systems.
In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia specifically in the Marcellus Shale producing area Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of December 31, 2011, the total amount reserved for the Pipeline and Storage segments preliminary survey and investigation costs was $7.2 million.
Supply Corporation and Empire are moving forward with several projects designed to move anticipated Marcellus production gas to other interstate pipelines and to markets beyond the Supply Corporation and Empire pipeline systems.
Supply Corporation has a precedent agreement with Statoil Natural Gas LLC (Statoil) to provide 320,000 Dth/day of firm transportation capacity for a 20-year term in conjunction with its Northern Access expansion project, and has executed the transportation service agreement. This capacity will provide Statoil with a firm transportation path from the Tennessee Gas Pipeline (TGP) 300 Line at Ellisburg to the TransCanada Pipeline at Niagara. This path is attractive because it provides a route for Marcellus shale gas, principally along the TGP 300 Line in northern Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Supply Corporation filed an application for FERC authorization of the project on March 7, 2011, and received its Certificate on October 20, 2011. The project facilities involve approximately 9,500 horsepower of additional compression at Supply Corporations existing Ellisburg Station and a new approximately 5,000 horsepower compressor station in East Aurora, New York, along with other system enhancements including enhancements to the jointly owned Niagara Spur Loop Line. Service is expected to begin in November 2012. The cost estimate for the Northern Access expansion is $62 million. As of December 31, 2011, approximately $4.9 million has been spent on the Northern Access expansion project, all of which has been capitalized as Construction Work in Progress.
Supply Corporation has begun service under two service agreements, which total 160,000 Dth/day of firm transportation capacity in its Line N Expansion Project. This project allows Marcellus production located in the vicinity of Line N to flow south and access markets at Texas Easterns Holbrook Station (TETCO Holbrook) in southwestern Pennsylvania. The FERC issued the NGA Section 7(c) certificate on December 16, 2010, and the project was placed into service on October 19, 2011.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Completed cost for the Line N Expansion Project is expected to be approximately $21 million. As of December 31, 2011, approximately $18.9 million has been spent on the Line N Expansion Project, all of which is included in Property, Plant and Equipment on the balance sheet at December 31, 2011.
Supply Corporation has also executed two precedent agreements for a total of 158,000 Dth/day of additional capacity on Line N to TETCO Holbrook for service beginning November 2012 (Line N 2012 Expansion Project). On July 8, 2011, Supply Corporation filed for FERC authorization to construct the Line N 2012 Expansion Project which consists of an additional 20,620 horsepower of compression at its Buffalo Compressor Station, and the replacement of 4.85 miles of 20 pipe with 24 pipe, to enhance the integrity and reliability of its system and to create the additional capacity. The preliminary cost estimate for the Line N 2012 Expansion Project is approximately $30.0 million for the incremental capacity plus approximately $5.8 million allocated to system replacement. As of December 31, 2011, approximately $9.0 million has been spent on the Line N 2012 Expansion Project, all of which has been capitalized as Construction Work in Progress.
In addition, Supply Corporation continues to actively pursue its largest planned expansion, the West-to-East (W2E) pipeline project, which is designed to transport locally produced Marcellus natural gas supplies to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates that the development of the W2E project will occur in phases. As currently envisioned, the initial phases of W2E, referred to as the W2E Overbeck to Leidy project, are designed to transport at least 425,000 Dth/day, and involves construction of a new 82-mile pipeline through Elk, Cameron, Clinton, Clearfield and Jefferson Counties to the Leidy Hub, from Marcellus and other producing areas along over 300 miles of Supply Corporations existing pipeline system. The W2E Overbeck to Leidy project also includes a total of approximately 25,000 horsepower of compression at two separate stations. On March 31, 2010, the FERC granted Supply Corporations request for a pre-filing environmental review of the W2E Overbeck to Leidy project, and Supply Corporation is in the process of preparing an NGA Section 7(c) application. The capital cost of the W2E Overbeck to Leidy project is estimated to be $290 million. The project may be built in phases depending on the development of Marcellus production along the corridor, with the first facilities available for service in late 2013 or late 2014. As of December 31, 2011, approximately $5.5 million has been spent to study the W2E Overbeck to Leidy project, which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2011.
On August 4, 2011, Supply Corporation concluded an Open Season to increase its capability to move gas north on its Line N system and deliver gas to Tennessee Gas Pipeline at Mercer, Pennsylvania, a pooling point recently established at their Station 219 (Mercer Expansion Project). Supply Corporation is in discussions with an anchor shipper that would take all 150,000 Dth/day of the capacity on the project. Service is expected to begin in 2014 and the estimated cost is $25 million to $30 million. As of December 31, 2011, less than $0.1 million has been spent to study the Mercer Expansion Project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2011.
Empire has begun service under two service agreements which total 350,000 Dth/day of incremental firm transportation capacity in its Tioga County Extension Project. This project transports Marcellus production from new interconnections at the southern terminus of a 15-mile extension of its Empire Connector line, in Tioga County, Pennsylvania. Completed cost for the Tioga County Extension Project is expected to be approximately $54 million, of which approximately $49.2 million has been spent through December 31, 2011. This project enables shippers to deliver their natural gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with the TransCanada Pipeline at the Niagara River at Chippawa, and with utility and power generation markets along its path, as well as to the new interconnection with TGPs 200 Line (Zone 5) in Ontario County, New York. On August 26, 2010, Empire filed an NGA Section 7(c) application to the FERC for approval of the project and the FERC issued the certificate on May 19, 2011. Empire accepted the certificate, received a FERC Notice to Proceed and on July 7, 2011 commenced construction. These facilities were placed fully in service on November 22, 2011. All costs associated with the project are included in Property, Plant and Equipment on the balance sheet at December 31, 2011.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
On December 17, 2010, Empire concluded an Open Season for up to 260,000 Dth/day of additional capacity from Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line, as well as additional short-haul capacity to Millennium Pipeline at Corning (Central Tioga County Extension). Empire is in discussions with an anchor shipper for a significant portion of the proposed capacity, with service commencing in late 2013 or mid-2014, and is studying the facility design that would be necessary to provide the requested service. The Central Tioga County Extension project may involve up to 25,000 horsepower of compression at up to three new stations and a 25 mile 24 pipeline extension, at a preliminary cost estimate of $135 million. As of December 31, 2011, approximately $0.2 million has been spent to study the Central Tioga County Extension project, which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2011.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months ended December 31, 2011 were primarily well drilling and completion expenditures and included approximately $181.2 million for the Appalachian region (including $172.0 million in the Marcellus Shale area) and $10.7 million for the West Coast region. These amounts included approximately $55.7 million spent to develop proved undeveloped reserves.
The Exploration and Production segment capital expenditures for the three months ended December 31, 2010 were primarily well drilling and completion expenditures and included approximately $174.3 million for the Appalachian region (including $173.0 million in the Marcellus Shale area), $2.7 million for the West Coast region and $1.1 million for the Gulf Coast region (former offshore oil and natural gas properties in the Gulf of Mexico). These amounts included approximately $57.0 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region included the Companys acquisition of oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately $24.1 million in November 2010. The Company funded this transaction with cash from operations.
For all of fiscal 2012, the Company expects to spend $760.0 million on Exploration and Production segment capital expenditures. Previously reported 2012 estimated capital expenditures for the Exploration and Production segment were $858.5 million. In the Appalachian region, estimated capital expenditures will decrease from $808.5 million to $710.0 million. Estimated capital expenditures in the West Coast region will remain at the previously reported $50.0 million. The Company had previously reported that it anticipates drilling 100 to 125 net horizontal wells in the Marcellus Shale during 2012. The Company now anticipates drilling 60 to 90 net horizontal wells in the Marcellus Shale during 2012. The decrease in estimated capital expenditures noted above is a result of the current low price environment for natural gas.
All Other
The majority of the All Other categorys capital expenditures for the three months ended December 31, 2011 were primarily for the construction of Midstream Corporations Trout Run Gathering System, as discussed below. The majority of the All Other categorys capital expenditures for the three months ended December 31, 2010 were primarily for the expansion of Midstream Corporations Covington gathering system in Tioga County, Pennsylvania as well as for the construction of Midstream Corporations Trout Run Gathering System.
NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, is developing a gathering system in Lycoming County, Pennsylvania. The project, called the Trout Run Gathering System, is anticipated to be placed in service in March 2012. The system will consist of approximately 26 miles of backbone and in-field gathering system at a cost of approximately $70 million. As of December 31, 2011, the Company has spent approximately $42.0 million in costs related to this project, all of which has been capitalized as Construction Work in Progress.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Midstream Corporation is planning to construct a gathering system in McKean County, Pennsylvania. The project, called the Mt. Jewett Gathering System, is anticipated to be placed in service in the fall of 2012. The gathering system will cost approximately $22 million. As of December 31, 2011, the Company has spent approximately $1.1 million in costs related to this project, all of which has been capitalized as Construction Work in Progress.
Project Funding
The Company has been financing the Pipeline and Storage segment projects and the Midstream Corporation projects mentioned above, as well as the Exploration and Production segment capital expenditures with cash from operations. Going forward, while the Company expects to use cash from operations as the first means of financing these projects, it is expected that the Company will increase its use of short-term borrowings during fiscal 2012. Natural gas and crude oil prices combined with production from existing wells will be a significant factor in determining how much of the capital expenditures are funded with cash from operations. The Company also issued additional long-term debt in December 2011 to enhance its liquidity position.
The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Companys other business segments depends, to a large degree, upon market conditions.
Financing Cash Flow
Consolidated short-term debt decreased $20.0 million during the three months ended December 31, 2011. The maximum amount of short-term debt outstanding during the three months ended December 31, 2011 was $327.8 million. The Company used its $500.0 million long-term debt issuance in December 2011 to substantially reduce its short-term debt. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At December 31, 2011, the Company had outstanding commercial paper of $20.0 million and no outstanding short-term notes payable to banks.
As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which totaled $385.0 million at December 31, 2011, are revocable at the option of the financial institutions and are reviewed on an annual basis. Subsequent to December 31, 2011, and following an increase in the amount of the Companys syndicated committed credit facility, as described below, the amount of the Companys uncommitted lines of credit decreased to $335.0 million. The Company anticipates that its uncommitted lines of credit generally will be renewed at amounts near current levels, or substantially replaced by similar lines.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
The total amount available to be issued under the Companys commercial paper program is $300.0 million. At December 31, 2011, the commercial paper program was backed by a syndicated committed credit facility totaling $300.0 million, which commitment extended through September 30, 2013. Under the committed credit facility, the Company agreed that its debt to capitalization ratio would not exceed .65 at the last day of any fiscal quarter through September 30, 2013. At December 31, 2011, the Companys debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would have permitted an additional $2.14 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Companys debt to capitalization ratio exceeded .65. On January 6, 2012, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaces the Companys $300.0 million committed credit facility with a similar committed credit facility totaling $750.0 million. The new facility extends to January 6, 2017.
If a downgrade in any of the Companys credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.
Under the Companys existing indenture covenants, at December 31, 2011, the Company would have been permitted to issue up to a maximum of $1.46 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Companys present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Companys ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.
The Companys 1974 indenture pursuant to which $99.0 million (or 7.1%) of the Companys long-term debt (as of December 31, 2011) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
The Companys $750.0 million committed credit facility, like the $300.0 million facility it replaced, also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of December 31, 2011, the Company did not have any debt outstanding under the committed credit facility.
The Companys embedded cost of long-term debt was 6.17% at December 31, 2011 and 6.85% at December 31, 2010.
There was no Current Portion of Long-Term Debt at December 31, 2011. The Company repaid $150 million of 6.70% notes that matured on November 21, 2011, which had been classified as Current Portion of Long-Term Debt at September 30, 2011.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Companys 6.70% notes in November 2011.
The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Companys consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $33.5 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases.
OTHER MATTERS
In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Companys present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
During the three months ended December 31, 2011, the Company contributed $22.5 million to its Retirement Plan and $5.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2012, the Company expects to contribute between $16.0 and $27.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2012, the Company expects to contribute between $14.0 and $15.0 million to its VEBA trusts and 401(h) accounts.
Market Risk Sensitive Instruments
On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives will not become effective until federal agencies (including the Commodity Futures Trading Commission (CFTC), various banking regulators and the SEC) adopt rules to implement the law. For purposes of the Dodd-Frank Act, the Company believes it will be categorized as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge commercial risk. Nevertheless, the rules that are being developed could have a significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required,
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
concern remains that swap dealers and major swap participants will pass along their increased capital and margin costs through higher prices and reductions in thresholds for posting margin. In addition, while the Company expects to be exempt from the Dodd-Frank Acts requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-cleared swap that is available as a cleared swap may be greater. The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.
In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net liabilities relate to crude oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Companys internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. Given the high level of historical correlation between NYMEX prices and prices at this sales location, the Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement.
The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net liabilities (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities. The Level 3 Net Liabilities amount to $54.8 million at December 31, 2011 and represent 18.9% of the Total Net Assets shown in Part I, Item 1 at Note 2 Fair Value Measurements at December 31, 2011.
The increase in the net fair value liability of the Level 3 positions from October 1, 2011 to December 31, 2011, as shown in Part I, Item 1 at Note 2, was attributable to an increase in the commodity price of crude oil relative to the swap price during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at December 31, 2011.
The fair value of all of the Companys Net Derivative Assets was reduced by $2.2 million based upon the Companys assessment of counterparty credit risk (for the Companys derivative assets) and the Companys credit risk (for the Companys derivative liabilities). The Company applied default probabilities to the anticipated cash flows that it was expecting to receive and pay to its counterparties to calculate the credit reserve.
For a complete discussion of market risk sensitive instruments, refer to Market Risk Sensitive Instruments in Item 7 of the Companys 2011 Form 10-K. There have been no subsequent material changes to the Companys exposure to market risk sensitive instruments.
Rate and Regulatory Matters
Utility Operation
Delivery rates for both the New York and Pennsylvania divisions are regulated by the states respective public utility commissions and are changed only when approved through a procedure known as a rate case. Currently neither division has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected through a separately-stated supply charge on the customer bill.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
New York Jurisdiction
Customer delivery rates charged by Distribution Corporations New York division were established in a rate order issued on December 21, 2007 by the NYPSC. The rate order approved a revenue increase of $1.8 million annually, together with a surcharge that would collect up to $10.8 million to cover expenses for implementation of an efficiency and conservation incentive program. The rate order further provided for a return on equity of 9.1%. In connection with the efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism decouples revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and is applied to customer bills annually, beginning March 1st.
On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contended, among other things, that the NYPSC improperly disallowed recovery of certain environmental clean-up costs. Following further appeals, on March 29, 2011, the Court of Appeals, the states highest court, issued a judgment and opinion in favor of Distribution Corporation. The matter was remanded to the NYPSC to be implemented consistent with the decision of the court.
Pennsylvania Jurisdiction
Distribution Corporations current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.
Pipeline and Storage
Supply Corporation filed a general rate case with the FERC on October 31, 2011, proposing rate increases to be effective December 1, 2011. The proposed rates reflect a cost of service of $199.3 million, a rate base of $441.7 million, and a proposed cost of equity of 13.5% per year. The FERC has accepted the filed rates, and has suspended the effective date of the proposed rate increases until May 1, 2012, when the increased rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect at October 31, 2011 but are less than the rates put into effect subject to refund on May 1, 2012, Supply Corporation will be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at October 31, 2011, the refund obligation will be limited to the difference between the rates in effect at October 31, 2011 and the rates put into effect subject to refund on May 1, 2012, with interest at the FERC-approved rate. To the extent the final FERC-approved rates are below those in effect at October 31, 2011, there is no refund for that rate differential. The final FERC-approved rates would be charged to customers only prospectively, from the date they go into effect.
Empires facilities known as the Empire Connector project were placed into service on December 10, 2008. As of that date, Empire became an interstate pipeline subject to FERC regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order issuing Empire its Certificate of Public Convenience and Necessity requires Empire to file a cost and revenue study at the FERC following three years of actual operation as an interstate pipeline, in conjunction with which Empire will either justify Empires existing recourse rates or propose alternative rates. Empire will file this cost and revenue study before the end of March 2012.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Companys policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.
The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design work plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of $14.3 million has been recorded.
At December 31, 2011, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $16.0 million to $20.2 million. The minimum estimated liability of $16.0 million, which includes the $14.3 million discussed above, has been recorded on the Consolidated Balance Sheet at December 31, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.
Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Pursuant to an EPA determination, effective January 2011 projects proposing new stationary sources of significant greenhouse gas emissions or major modifications of existing facilities are required under the federal Clean Air Act to obtain permits covering such emissions. The EPA is also considering other regulatory options to regulate greenhouse gas emissions from the energy industry. In April 2011, the U.S. Senate rejected bills aimed at curbing the authority of the EPA to regulate greenhouse gas emissions. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Companys cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. International, federal, state or regional climate change and greenhouse gas measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. Climate change and greenhouse gas initiatives, and incentives to conserve energy or use alternative energy sources, could also reduce demand for oil and natural gas. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
New Authoritative Accounting and Financial Reporting Guidance
In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Companys second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.
In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Companys first quarter of fiscal 2013 and is not expected to have a significant impact on the Companys financial statements.
In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a qualitative assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Companys annual impairment test performed in fiscal 2013. While early adoption is permitted, the Company has not adopted the new provisions to date.
In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Companys first quarter of fiscal 2014 and is not expected to have a significant impact on the Companys financial statements.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words anticipates, estimates, expects, forecasts, intends, plans, predicts, projects, believes, seeks, will, may, and similar expressions, are forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
results or outcomes to differ materially from those expressed in the forward-looking statements. The Companys expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that managements expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
1. | Factors affecting the Companys ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; |
2. | Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; |
3. | Changes in the price of natural gas or oil; |
4. | Uncertainty of oil and gas reserve estimates; |
5. | Significant differences between the Companys projected and actual production levels for natural gas or oil; |
6. | Impairments under the SECs full cost ceiling test for natural gas and oil reserves; |
7. | Changes in the availability, price or accounting treatment of derivative financial instruments; |
8. | Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; |
9. | Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; |
10. | Financial and economic conditions, including the availability of credit, and occurrences affecting the Companys ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Companys credit ratings and changes in interest rates and other capital market conditions; |
11. | Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers ability to pay for, the Companys products and services; |
12. | The creditworthiness or performance of the Companys key suppliers, customers and counterparties; |
13. | Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; |
14. | Changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; |
15. | Other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; |
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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Concl.)
16. | Significant differences between the Companys projected and actual capital expenditures and operating expenses; |
17. | Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Companys pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; |
18. | Changes in demographic patterns and weather conditions; |
19. | The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; |
20. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or |
21. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Industry and Market Information
The industry and market data used or referenced in this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Some industry and market data may also be based on good faith estimates, which are derived from the Companys review of internal information, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While the Company believes that each of these studies and publications is reliable, the Company has not independently verified such data and makes no representation as to the accuracy of such information. Forecasts in particular may prove to be inaccurate, especially over long periods of time. Similarly, while the Company believes its internal information is reliable, such information has not been verified by any independent sources, and the Company makes no assurances that any predictions contained herein will prove to be accurate.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Refer to the Market Risk Sensitive Instruments section in Item 2 MD&A.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The term disclosure controls and procedures is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the companys management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Companys management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Companys disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Companys Chief Executive Officer and Principal Financial Officer concluded that the Companys disclosure controls and procedures were effective as of December 31, 2011.
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Item 4. Controls and Procedures (Concl.)
Changes in Internal Control Over Financial Reporting
There were no changes in the Companys internal control over financial reporting that occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Companys internal control over financial reporting.
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 6 Commitments and Contingencies, and Part I, Item 2MD&A of this report under the heading Other Matters Environmental Matters.
In addition to these matters, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Companys present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.
The risk factors in Item 1A of the Companys 2011 Form 10-K have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same captions in the 2011 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2011 Form 10-K.
The Companys need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its regulated segments, there are many governmental regulations that have an impact on almost every aspect of the Companys businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Companys costs or affect its business in ways that the Company cannot predict.
In the Companys Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.
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Item 1A. Risk Factors (Cont.)
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from further customer migration to marketer service (unbundling) can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.
Both the NYPSC and the PaPUC have instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a revenue decoupling mechanism that renders Distribution Corporations New York division financially indifferent to the effects of conservation. In Pennsylvania, although a generic statewide proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.
In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.
The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca Resources, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporations and Empires rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporations or Empires earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Companys other subsidiaries are subject to the FERCs penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulators such as the National Energy Board and the Ontario Energy Board could affect the viability and profitability of Supply Corporation and Empire projects designed to transport gas from New York into Ontario.
In January 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act. The legislation increases civil penalties for pipeline safety violations and addresses matters such as pipeline damage prevention, automatic and remote-controlled shut-off valves, excess flow valves, pipeline integrity management, documentation and testing of maximum allowable operating pressure, and reporting of pipeline accidents. The legislation requires the Pipeline and Hazardous Materials Safety Administration (PHMSA) to issue or revise certain regulations and to conduct various reviews, studies and evaluations. In addition, PHMSA in August 2011 issued an Advance Notice of Proposed Rulemaking regarding pipeline safety. As described in the notice, PHMSA is considering
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Item 1A. Risk Factors (Cont.)
regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. Unrelated to these safety initiatives, the EPA in April 2010 issued an Advance Notice of Proposed Rulemaking reassessing its regulations governing the use and distribution in commerce of PCBs. The EPA projects that it may issue a Notice of Proposed Rulemaking by December 2012. If as a result of new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Companys financial condition, results of operations, and cash flows would be adversely affected.
The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.
In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Companys Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Companys expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Companys ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground. The Companys Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas.
Under applicable accounting rules currently in effect, the Companys hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines into which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Companys hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Companys natural gas and crude oil production, and losses would occur to the extent that market prices for the Companys natural gas and crude oil production exceed hedge prices.
Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX by futures commission merchants. Under NYMEX rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission merchants, or misappropriation or mishandling of clients funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.
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Item 1A. Risk Factors (Concl.)
It is the Companys policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Companys actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.
The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives will not become effective until federal agencies (including the Commodity Futures Trading Commission (CFTC), various banking regulators and the SEC) adopt rules to implement the law. For purposes of the Dodd-Frank Act, we believe that the Company will be categorized as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge commercial risk. Nevertheless, the rules that are being developed could have a significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required, concern remains that swap dealers and major swap participants will pass along their increased capital and margin costs through higher prices and reductions in thresholds for posting margin. In addition, while the Company expects to be exempt from the Dodd-Frank Acts requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-cleared swap that is available as a cleared swap may be greater.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On October 3, 2011, the Company issued a total of 4,050 unregistered shares of Company common stock to the nine non-employee directors of the Company then serving on the Board of Directors of the Company, 450 shares to each such director. All of these unregistered shares were issued under the Companys 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors services during the quarter ended December 31, 2011. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities
Period |
Total Number of
Shares Purchased (a) |
Average Price
Paid per Share |
Total Number of
Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs |
Maximum Number
of Shares that May Yet Be Purchased Under Share Repurchase Plans or Programs (b) |
||||||||||||
Oct. 1-31, 2011 |
6,522 | $ | 55.52 | | 6,971,019 | |||||||||||
Nov. 1-30, 2011 |
33,960 | $ | 59.20 | | 6,971,019 | |||||||||||
Dec. 1-31, 2011 |
101,778 | $ | 57.11 | | 6,971,019 | |||||||||||
Total |
142,260 | $ | 57.53 | | 6,971,019 |
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds (Concl.)
(a) |
Represents (i) shares of common stock of the Company purchased on the open market with Company matching contributions for the accounts of participants in the Companys 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options, SARs or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended December 31, 2011, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 142,260 shares purchased other than through a publicly announced share repurchase program, 18,727 were purchased for the Companys 401(k) plans and 123,533 were purchased as a result of shares tendered to the Company by holders of stock options, SARs or shares of restricted stock. |
(b) |
In September 2008, the Companys Board of Directors authorized the repurchase of eight million shares of the Companys common stock. The Company, however, stopped repurchasing shares after September 17, 2008. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future. |
(a) | Exhibits |
Exhibit Number |
Description of Exhibit |
|
| Officers Certificate establishing 4.90% Notes due 2021, dated December 1, 2011 (incorporated by reference to Exhibit 4.4, Form 8-K dated December 1, 2011) | |
10.1 | Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program. | |
10.2 | Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 1997 Award and Option Plan. | |
10.3 | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective December 7, 2011. | |
12 |
Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended December 31, 2011 and the Fiscal Years Ended September 30, 2008 through 2011. |
|
31.1 | Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act. | |
31.2 | Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act. | |
32 | Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
99 |
National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended December 31, 2011 and 2010. |
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Item 6. Exhibits (Concl.)
101 | Interactive data files pursuant to Regulation S-T: (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three months ended December 31, 2011 and 2010, (ii) the Consolidated Balance Sheets at December 31, 2011 and September 30, 2011, (iii) the Consolidated Statements of Cash Flows for the three months ended December 31, 2011 and 2010, (iv) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2011 and 2010 and (v) the Notes to Condensed Consolidated Financial Statements. |
| Incorporated herein by reference as indicated. |
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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
NATIONAL FUEL GAS COMPANY (Registrant) |
/s/ D. P. Bauer |
D. P. Bauer Treasurer and Principal Financial Officer |
/s/ K. M. Camiolo |
K. M. Camiolo Controller and Principal Accounting Officer |
Date: February 3, 2012
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Exhibit 10.1
Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program
Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program
On December 19, 2011, the Compensation Committee adopted specific written performance goals for fiscal year 2012 under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program (AARCIP) for David F. Smith, Ronald J. Tanski, Matthew D. Cabell, Anna Marie Cellino and John R. Pustulka. Mr. Smith is Chairman of the Board and Chief Executive Officer of the Company. Mr. Tanski is President and Chief Operating Officer of the Company. Mr. Cabell is President of Seneca Resources Corporation, the Companys exploration and production subsidiary, and Senior Vice President of the Company. Mrs. Cellino is President of National Fuel Gas Distribution Corporation, the Companys utility subsidiary. Mr. Pustulka is President of National Fuel Gas Supply Corporation, one of the Companys pipeline and storage subsidiaries.
These executives will earn cash compensation in fiscal 2011 under the AARCIP depending upon their performance relative to their goals. Compensation amounts pursuant to these arrangements can range up to 200% of salary for Mr. Smith, up to 160% of salary for Mr. Tanski and up to 140% of salary for Mr. Cabell, Mrs. Cellino and Mr. Pustulka. Target compensation is 100% of salary for Mr. Smith, 80% of salary for Mr. Tanski and 70% of salary for Mr. Cabell, Mrs. Cellino and Mr. Pustulka. The Compensation Committee may approve other compensation or awards at its discretion.
The goals for Mr. Smith relate to Company earnings per share (weighted as 25% of the formula), earnings per share of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 25% of the formula), oil and natural gas production volume and production rate (multiple goals weighted in the aggregate as 35% of the formula), safety and environmental compliance (multiple goals weighted in the aggregate as 10% of the formula), and the Companys investor relations program (weighted as 5% of the formula).
The goals for Mr. Tanski relate to Company earnings per share (weighted as 25% of the formula), earnings per share of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 25% of the formula), oil and natural gas production volume (weighted as 15% of the formula), management of the capital expenditure budgets of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 15% of the formula), growth of the Companys pipeline and storage subsidiaries and gathering and processing business (weighted as 5% of the formula), safety (weighted as 5% of the formula), effectiveness of the Companys utility subsidiary in obtaining customer assistance under the Home Energy Assistance Program (weighted as 5% of the formula), and the Companys investor relations program (weighted as 5% of the formula).
The goals for Mr. Cabell relate to Company earnings per share (weighted as 15% of the formula), earnings per share of the Companys exploration and production subsidiary (weighted as 15% of the formula), oil and natural gas production volume and production rate (multiple goals weighted in the aggregate as 30% of the formula), oil and natural gas reserve replacement (weighted as 20% of the formula), finding and development costs (weighted as 10% of the formula), lease operating expenses and general and administrative expenses (weighted as 5% of the formula), and environmental/safety compliance (weighted as 5% of the formula).
The goals for Mrs. Cellino relate to Company earnings per share (weighted as 25% of the formula), earnings per share of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 25% of the formula), safety (multiple goals weighted in the aggregate as 15% of the formula), customer service standards of the Companys utility subsidiary (weighted as 10% of the formula), meter reading of the Companys utility subsidiary (weighted as 10% of the formula), management of the capital expenditure budget of the Companys utility subsidiary (weighted as 5% of the formula), and effectiveness of the Companys utility subsidiary in obtaining customer assistance under the Home Energy Assistance Program (multiple goals weighted in the aggregate as 10% of the formula).
The goals for Mr. Pustulka relate to Company earnings per share (weighted as 25% of the formula), earnings per share of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 25% of the formula), oil and natural gas production rate (weighted as 10% of the formula), safety (weighted as 10% of the formula), fuel consumption and operational efficiency of one of the Companys pipeline and storage subsidiaries (weighted as 10% of the formula), management of the capital expenditure budgets of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 10% of the formula), and revenue of the Companys pipeline and storage subsidiaries (weighted as 10% of the formula).
National Fuel Gas Company Executive Annual Cash Incentive Program
On December 19, 2011, the Compensation Committee adopted specific written performance goals for fiscal year 2012 under the National Fuel Gas Company Executive Annual Cash Incentive Program (EACIP) for David P. Bauer, Treasurer and Principal Financial Officer of the Company. Mr. Bauer will earn cash compensation in fiscal 2012 under the EACIP depending upon his performance relative to his goals. The compensation amount pursuant to this arrangement can range up to 90% of salary, and target compensation is 45% of salary. The Compensation Committee may approve other compensation or awards at its discretion.
The goals for Mr. Bauer relate to Company earnings per share (weighted as 25% of the formula), earnings per share of the Companys pipeline and storage subsidiaries and utility subsidiary (weighted as 25% of the formula), the Companys investor relations program (multiple goals weighted in the aggregate as 20% of the formula), internal control compliance (weighted as 5% of the formula), and individual performance as otherwise subjectively determined (weighted as 25% of the formula).
Exhibit 10.2
[date]
[Name]
[Address]
[Address]
Dear [Name]:
I am pleased to inform you that on [date] the Compensation Committee (Committee) of the Board of Directors of National Fuel Gas Company (the Company) granted to you (the Grantee) a stock appreciation right, under the National Fuel Gas Company 1997 Award and Option Plan, as amended (the Plan), in respect of an aggregate of [number] shares of the Companys Common Stock, $1.00 par value (the Common Stock).
Your new stock appreciation right is described in the balance of this letter agreement (Award Notice). The Plan and the Committees Administrative Rules (Rules) govern the operation of the Plan, as well as the terms and conditions of your stock appreciation right granted under the Plan, and are incorporated herein by reference.
1. | Base Price, Vesting Schedule and Date Exercisable |
The base price (Base Price) of your stock appreciation right is [price] per share (which is the Fair Market Value of the Common Stock on the date of grant). Except as otherwise specified in the Plan or this Award Notice, and except as determined by the Committee, your stock appreciation right shall vest in three installments on the first, second and third anniversaries of the date of grant, and shall become exercisable in whole or in part on the third anniversary of the date of grant, as detailed in the following schedule:
Incremental Number of Shares Subject to SAR |
Vesting Date |
Date Exercisable |
||
[number] |
[first anniversary of date of grant] | [third anniversary of date of grant] | ||
[number] |
[second anniversary of date of grant] | [third anniversary of date of grant] |
[Name]
Page 2
[Date]
[number] |
[third anniversary of date of grant] |
[third anniversary of date of grant] |
Once this stock appreciation right has become exercisable, it may be exercised in whole at any time and in part from time to time until the date of termination of the Grantees rights hereunder; provided, that in no event shall this stock appreciation right be exercisable in whole or in part after [tenth anniversary of date of grant]. The exercise of this stock appreciation right is not conditioned upon attainment of performance goals.
2. | Restriction on Exercise |
Notwithstanding any other provision hereof, this stock appreciation right shall not be exercised if at such time such exercise or the delivery of certificates representing shares of Common Stock purchased pursuant hereto shall constitute a violation of any rule of the Company, any provision of any applicable Federal or State statute, rule or regulation, or any rule or regulation of any securities exchange on which the Common Stock may be listed.
3. | Payment Upon Exercise |
This stock appreciation right may be exercised with respect to all or any part of the shares of Common Stock then subject to such exercise pursuant to whatever procedures may be adopted from time to time by the Company. Upon the exercise of this stock appreciation right, in whole or in part, the Grantee shall be entitled to receive from the Company a number of shares of Stock equal in value to the excess of the Fair Market Value (on the date of exercise) of one share of Stock over the Base Price, multiplied by the number of shares in respect of which the stock appreciation right is being exercised. The number of shares to be issued shall be calculated on the basis of the Fair Market Value of the shares on the date of exercise, with any fractional share being payable in cash based on the Fair Market Value on the date of exercise.
4. | Termination of Employment |
In the event your employment with the Company or its Subsidiaries terminates, then, depending upon the circumstances of the termination, this stock appreciation right may become exercisable prior to [third anniversary of date of grant], may remain exercisable after your termination date, or may be terminated, as set forth in the Plan and the Rules.
5. | Adjustments in Common Stock |
In the event of a Common Stock dividend, Common Stock split, merger, consolidation, reorganization, recapitalization or other change in the corporate structure, appropriate adjustments shall be made by the Board or the Compensation Committee of the Board in the number of shares, class or classes of securities and the base price per share applicable in respect to the stock appreciation rights subject to this Agreement. The Board or the Compensation Committee shall, in its discretion, determine the manner in which any adjustment pursuant to the immediately preceding sentence shall be effected, with the purpose and intent of avoiding any diminution or infringement of the Grantees rights hereunder by reason of any of the events referenced in such sentence.
[Name]
Page 3
[Date]
6. | Non-Transferability of Stock Appreciation Right |
The Grantee has no right to assign or transfer this stock appreciation right, except by will, by the laws of descent and distribution, or as otherwise permitted in the Plan or the Rules. During the lifetime of the Grantee this stock appreciation right may be exercised only by him or her (unless otherwise determined by the Board or the Committee).
7. | Authority of Committee |
The Committee has the authority to interpret the Plan and all stock appreciation rights granted thereunder, to establish rules and regulations relating to the Plan and to make all other determinations it believes necessary or advisable for the administration of the Plan. The scope of the Committees authority is more fully described in the Plan. All determinations and actions of the Committee are final, conclusive and binding on you.
8. | Miscellaneous |
(a) This stock appreciation right (i) shall be binding upon and inure to the benefit of the Company (and its successors and assigns) and you (and your heirs, legal representatives and estate), and (ii) shall be governed by the laws of the State of New York, and any applicable laws of the United States. No contract or right of employment shall be implied by this stock appreciation right.
(b) This stock appreciation right may be unilaterally amended or modified by the Committee, as permitted by the Plan or the Rules, to the extent it deems appropriate, but may not be amended or modified without your consent if such amendment or modification is adverse to you. Except as otherwise provided in the preceding sentence, this stock appreciation right may not be amended or modified, nor may any term or condition, or breach of any term or condition, be waived, except in writing signed by the person or persons sought to be bound by such amendment, modification or waiver. Any waiver of any term or condition or breach thereof shall not be a waiver of any other term or condition, or of the same term or condition for the future, or of any subsequent breach.
(c) If this stock appreciation right is assumed or a new stock appreciation right is substituted therefor in any corporate reorganization (including, but not limited to, any transaction of the type referred to in Section 424(a) of the Internal Revenue Code of 1986, as amended), employment by such assuming or substituting company or by a parent company or a subsidiary thereof shall be considered for all purposes of this stock appreciation right to be employment by the Company.
(d) In consideration of the Grantees privilege to participate in the Plan, the Grantee agrees (i) not to disclose any trade secrets of, or other confidential/restricted information of the Company to any unauthorized party, (ii) not to make any unauthorized
[Name]
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use of such trade secrets or confidential or restricted information during his or her employment with the Company or its Subsidiaries or after such employment is terminated, and (iii) not to solicit any then current employees of the Company or any other subsidiaries of the Company to join the Grantee at his or her new place of employment after his or her employment with the Company or its Subsidiaries is terminated.
(e) This Award Notice, together with the Plan and the Rules, constitutes the entire agreement between the parties with respect to the subject matter hereof. You hereby acknowledge that you have been provided with a copy of the Plan and the Rules, and understand the terms and conditions of these documents and of this Award Notice. In the event of any conflict between this Award Notice and the terms of the Plan and the Rules, the Plan and the Rules will govern and control.
(f) In the event of the invalidity of any part or provision of this agreement, such invalidity shall not affect the enforceability of any other part or provision hereof.
9. | Tax Withholding |
The Grantee agrees that upon exercise of the stock appreciation right evidenced hereby, in whole or in part, any and all applicable income, employment or other tax withholding shall be satisfied at the minimum required level using shares of Common Stock otherwise deliverable upon exercise of such stock appreciation right. The number of shares to be withheld shall be determined by the Company in accordance with the policies and procedures in effect from time to time under the Plan applicable with respect to stock withholding.
10. | Securities Law Requirements |
The Company shall not be required to issue shares upon the exercise of this stock appreciation right unless and until (a) such shares have been duly listed upon each stock exchange on which the Companys Stock is then registered and (b) a registration statement under the Securities Act of 1933 with respect to such shares is then effective. The Board may require the Grantee to furnish to the Company, prior to the issuance of any shares of Common Stock in connection with the exercise of this stock appreciation right, an agreement, in such form as the Board may from time to time deem appropriate, in which the Grantee represents that the shares acquired by him upon such exercise are being acquired for investment and not with a view to the sale or distribution thereof.
11. | Stock Appreciation Right Subject to Plan and Rules |
This stock appreciation right shall be subject to all the terms and provisions of the Plan and the Rules and the Grantee shall abide by and be bound by such terms and provisions and all rules, regulations and determinations of the Board or the Committee now or hereafter made in connection with the administration of the Plan. Capitalized terms not otherwise defined herein shall have the meanings set forth for such terms in the Plan or the Rules.
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12. | American Jobs Creation Act |
In addition to amendments permitted by Section 8(b) above, amendments to this Agreement may be made by the Company, without the Grantees consent, in order to ensure compliance with the American Jobs Creation Act of 2004. And, further, amendments may be made to the Plan to ensure such compliance, which amendments may impact this Agreement.
If the foregoing is acceptable to you, kindly acknowledge your acceptance by signing both originals of this letter and returning one to [Company Secretary].
Very truly yours, | ||
NATIONAL FUEL GAS COMPANY | ||
By: | ||
[Name] | ||
[Title] |
ACCEPTED AND AGREED TO
this day of ,
|
Grantee
Exhibit 10.3
Administrative Rules
of the
Compensation Committee
of the
Board of Directors
of
National Fuel Gas Company
As amended and restated
effective December 7, 2011
TABLE OF CONTENTS
I. | Meetings | 1 | ||||||||||||
II. | Quorum and Voting; Delegation | 2 | ||||||||||||
III. | Grants and Awards Under the Plans | 2 | ||||||||||||
A. | General Rules Regarding Awards Under the 1997 and 2010 Plans | 3 | ||||||||||||
1. | Making of An Award | 3 | ||||||||||||
2. | Contemporaneous Awards | 3 | ||||||||||||
3. | Stock-Based Awards | 3 | ||||||||||||
a. | Source | 3 | ||||||||||||
b. | Cash Dividends and Cash Dividend Equivalents | 3 | ||||||||||||
i. | Stock Based Awards Other Than Restricted Stock | 3 | ||||||||||||
ii. | Restricted Stock Awards | 4 | ||||||||||||
c. | Payment | 4 | ||||||||||||
4. | Withholding Taxes | 4 | ||||||||||||
5. | Deferral of Payment | 5 | ||||||||||||
B. | Stock Options Under the 1997 and 2010 Plans | 5 | ||||||||||||
1. | Designation | 5 | ||||||||||||
2. | Price | 6 | ||||||||||||
3. | Exercise Period/Duration | 6 | ||||||||||||
a. | Non-Qualified Stock Options Under the 1997 and 2010 Plans | 6 | ||||||||||||
b. | Incentive Stock Options Under the 1997 Plan | 6 | ||||||||||||
c. | Suspension of Rights to Exercise | 7 | ||||||||||||
d. | Delegation of Authority | 7 | ||||||||||||
4. | Death or Other Termination of Employment | 8 | ||||||||||||
a. | Definitions | 8 | ||||||||||||
b. | Non-Qualified Stock Options Under the 1997 and 2010 Plans | 8 | ||||||||||||
c. | Extension of Incentive Stock Options Under the1997 and 2010 Plans | 10 | ||||||||||||
5. | Mechanics of Exercise | 11 | ||||||||||||
6. | Reload Options | 11 | ||||||||||||
C. | SARs Under the 1997 or 2010 Plan | 11 |
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D. | Restricted Stock and Restricted Stock Units Under the 1997 and 2010 Plans | 12 | ||||||||
1. | Restrictions on Transferability; Vesting | 12 | ||||||||
2. | Mechanics of Grant | 12 | ||||||||
IV. | Procedures For Exercising Stock Options and SARs | 13 | ||||||||
A. | Authority and Scope | 13 | ||||||||
B. | Notice of Exercise | 13 | ||||||||
1. | Form and Delivery | 13 | ||||||||
2. | Exercise Date | 13 | ||||||||
C. | Payment of Exercise Price | 14 | ||||||||
1. | Cash Payment | 14 | ||||||||
2. | Payment with Existing Company Stock | 14 | ||||||||
3. | Additional Time to Pay Exercise Price | 15 | ||||||||
4. | Cashless Exercise | 16 | ||||||||
D. | Restrictions Relating to Possession of Material Nonpublic Information | 17 |
iii
ADMINISTRATIVE
RULES OF THE
COMPENSATION COMMITTEE
OF THE
BOARD OF DIRECTORS
OF
NATIONAL FUEL GAS COMPANY
As amended and restated
effective December 7, 2011
I. | MEETINGS |
Each meeting (Meeting) of the Compensation Committee (Committee) of the Board of Directors of National Fuel Gas Company (Company) shall be held as indicated in a notice made in accordance with these rules. Notice of each Meeting, stating the place, date and hour thereof, shall be given to each member of the Committee (Member) by e-mailing, faxing, telephoning or personally delivering the same to him at least one day before the meeting, if there is no reason to believe it was not received, or by mailing the same to him at least five days before the Meeting, in all cases to the Members last known address or addresses as the same appears upon the records of the Company. All such notices shall be effective when sent, including the leaving of a message recorded at, or spoken to any individual answering, the Members designated telephone number(s). The attendance of any Member at a Meeting without protesting prior to the end of the Meeting the lack of notice of such meeting shall constitute a waiver of notice by that Member.
Any one or more Members of the Committee may participate in a Meeting by means of a conference telephone or similar equipment. Participation by such means shall constitute presence in person at a Meeting.
The Committee may also take action by unanimous written consent.
II. | QUORUM AND VOTING; DELEGATION |
At all Meetings, a quorum shall be required for the transaction of business and shall consist of a majority of the entire Committee. The majority vote of the Members at a Meeting at which a quorum is present shall decide any question that may come before the meeting.
Consistently with limitations imposed by the Plans (as defined below), the Committee may delegate in these rules or by resolution any or all of its authority to the Chief Executive Officer, to the Secretary and to any other officer of the Company (individually, Delegate), so long as the Delegate has no potential conflict of interest which would cause him or her not to exercise his or her good faith independent business judgment in respect of a delegated matter. Subject to such limitations, the Committee hereby delegates the power to implement its decisions to appropriate officers of the Company.
III. | GRANTS AND AWARDS UNDER THE PLANS |
The following rules and regulations shall apply with respect to grants and awards of stock options, stock appreciation rights (SARs), shares of restricted stock (Restricted Stock) and restricted stock units (Restricted Stock Units) under the Companys 1997 Award and Option Plan (1997 Plan) or the Companys 2010 Equity Compensation Plan (2010 Plan) (as amended, each individually a Plan; together the Plans).
Any capitalized term not defined in these rules shall have the same meaning as in the applicable Plan. The following rules are intended to supplement the Plans and, to the extent that any rule is determined to be inconsistent with any Plan, the Plan shall control.
These rules may be amended by the Committee at any time and from time to time. Except to the extent otherwise specified in the particular Award Notice or at the time these rules are amended, any grant or award under the Plans shall be subject to these rules as in effect on the date of the grant or award.
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A. | GENERAL RULES REGARDING AWARDS UNDER THE 1997 AND 2010 PLANS |
1. | Making of An Award |
An Award within the meaning of these rules occurs upon the grant by the Committee of any stock option, SAR, Restricted Stock or Restricted Stock Unit. An Award Notice within the meaning of these rules means a written notice from the Company to a Participant (including a notice provided to the recipient in an electronic form or by a link to cite of the notice) that sets forth the terms and conditions of an Award in addition to those conditions established in the applicable Plan and by the Committees exercise of its administrative powers.
2. | Contemporaneous Awards |
Unless the Committee shall otherwise expressly provide at the time of grant, an Award of one type granted contemporaneously with an Award of any other type shall be treated as having been granted in combination, and not in the alternative, with the Award of the other type.
3. | Stock-based Awards |
a. Source. Stock-based Awards, to the extent actually paid in Common Stock, shall reduce treasury shares (if any) first and thereafter authorized but unissued shares.
b. Cash Dividends and Cash Dividend Equivalents.
(i) Stock-Based Awards Other Than Restricted Stock. No stock-based Award other than Restricted Stock carries with it the entitlement to receive cash
3
dividends or cash dividend equivalents until such stock-based Award is exercised (in the case of a stock option or stock-settled SAR) or earned. If a stock-based Award is exercised or earned prior to or on the record date for determination of stockholders entitled to receive a cash dividend, then such stock-based Award or the securities resulting from the exercise thereof, as the case may be, shall be entitled to receive such cash dividend (or, if the shares related thereto have not been issued as of the record date, to receive a dividend equivalent in respect thereof).
(ii) Restricted Stock Awards. Notwithstanding clause (i) of this paragraph (b) or Section 24 of the 1997 Plan or Section 14(e) of the 2010 Plan, dividends shall be payable with respect to each outstanding Award of Restricted Stock whether or not the restrictions in such Award have been satisfied or have lapsed.
c. Payment. Payment of stock-based Awards shall be made with Common Stock.
4. | Withholding Taxes |
At the time a Participant is taxable with respect to stock options, SARs, Restricted Stock or Restricted Stock Units granted under the Plans, or the exercise or surrender of the same, the Company (or, if applicable, an employer other than the Company) shall have the right to withhold from amounts payable to the Participant under the Plan or from other compensation payable to the Participant in its sole discretion, or require the Participant to pay to it, an amount sufficient to satisfy all federal, state and/or local (including foreign) withholding tax requirements. A Participant may, subject to Section IV(D) below, pay such tax withholding amounts in whole or in part by requesting that the Company withhold such amounts of taxes from the amounts owed to the Participant, or by delivering as payment to the Company shares of Common Stock to be canceled having a Fair Market Value less than or equal to the amount of
4
such required withholding taxes (with the remainder payable in cash); provided, however, that to the extent that such withholding is satisfied by the Companys withholding and/or canceling any shares of Common Stock, in no event may the Fair Market Value of the Common Stock withheld and/or canceled exceed the amount required to be withheld at law.
5. | Deferral of Payment |
The Committee intends to permit Participants to elect, at such time or times as the Committee shall permit, to defer the receipt of payment of Awards that are payable in cash; provided, however, that (1) under the then applicable income tax rules the Participant is not in constructive receipt of, and subject to income tax on, the payment prior to its actual receipt, (2) such deferral does not result in any of the Plans being subject to the Employee Retirement Income Security Act of 1974, as amended, (3) if the Participant is an Executive Officer (i.e., is subject to Section 16 of the Securities Exchange Act of 1934, including a retired officer who is, at the relevant time, a director), such election shall comply with Rule 16b-3 promulgated pursuant to the Securities Exchange Act of 1934, as then in effect, and (4) such election would not result in the imposition of an additional tax under Section 409A of the Code on the Participant. The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the Committees authority to establish the time or times at which deferral elections may be permitted in respect of any Award.
B. | STOCK OPTIONS UNDER THE 1997 AND 2010 PLANS |
1. | Designation |
The Award Notice setting forth the terms and conditions of a grant of a stock option shall indicate the applicable Plan under which the stock option is granted and
5
whether the stock option is an incentive stock option (within the meaning of Section 422 of the Code, an ISO) or a non-qualified stock option (NSO). The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the authority to prepare, execute and deliver Award Notices consistent with actions taken by the Committee. The Committee hereby directs that any action taken by the Committee granting stock options without specifying whether the stock options are ISOs be interpreted as follows:
a. an award of stock options under the 1997 Plan or the 2010 Plan shall be deemed to be awards of NSOs only; and
b. an award of stock options after December 12, 2006 under the 1997 Plan shall be deemed to be NSOs regardless of the language of the award.
2. | Price |
The price at which Common Stock may be purchased upon exercise of a stock option (the exercise price) shall be the Fair Market Value of the Common Stock on the date of the Award.
3. | Exercise Period/Duration |
a. Non-Qualified Stock Options Under the 1997 and 2010 Plans. Except as may otherwise be expressly provided in the Plan or in Section III(B)(4) of these rules, a non-qualified stock option granted under the 1997 Plan or the 2010 Plan first may be exercised twelve months after the date of grant.
b. Incentive Stock Options Under the 1997 and 2010 Plans. Except as may otherwise be expressly provided in the Plan, an ISO granted under the 1997 Plan or the 2010 Plan first may be exercised twelve months after the date of grant, or, if earlier, on the date of the optionees death.
6
c. Suspension of rights to exercise. The Committee may, among other things, suspend or limit the right of any Participant to exercise stock options during any period:
(i) for which counsel for the Company advises in writing that such stock option exercises would violate federal or state securities laws or other applicable laws, rules, regulations, judgments, or orders; or
(ii) during which management is investigating an allegation that the Participant has engaged in any act which would permit the Committee to forfeit the Participants stock options pursuant to Section 18 of the 1997 Plan or Section 14(c) of the 2010 Plan.
d. Delegation of Authority. The Committee hereby delegates to the Chief Executive Officer, President, Treasurer, Secretary and General Counsel of the Company, and each of them, the Committees authority to suspend Participants rights to exercise stock options during the periods described in Section III(B)(3)(c) above. Management shall report to the Committee at each Committee meeting any suspension actions taken or ongoing since the previous meeting, and the Committee shall adopt a resolution ratifying, continuing and/or discontinuing each such suspension.
7
4. | Death or Other Termination of Employment |
a. Definitions. For purposes of these rules, the following terms shall have the following meanings:
(i) For purposes of the 1997 Plan, Disability shall mean that the Participant is eligible to receive disability benefits under Article 3 of The National Fuel Gas Company Retirement Plan (Retirement Plan), as from time to time amended, or that the Participant would be eligible to receive such benefits if he or she were a participant in the Retirement Plan.
(ii) Subsidiary shall mean a corporation or other business entity in which the Company directly or indirectly has an ownership interest of fifty percent (50%) or more.
b. Non-Qualified Stock Options Under the 1997 Plan. If termination of employment occurs by reason of death, each NSO awarded under the 1997 Plan shall, to the extent not then exercisable, become immediately and fully exercisable, and shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less. If termination of employment occurs by reason of voluntary resignation (including retirement) at or after age 60, each NSO awarded under the 1997 Plan shall, to the extent not then exercisable, become exercisable in accordance with the terms of the 1997 Plan, and shall remain exercisable until the earlier of the fifth anniversary of such termination or the expiration of the balance of its term. If termination of employment occurs by reason of Disability, (i) each NSO awarded under the 1997 Plan that is then exercisable shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less, (ii) each NSO awarded under the 1997 Plan on or after December 7, 2011 that is not then
8
exercisable shall become immediately and fully exercisable, and shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less, and (iii) each NSO awarded under the 1997 Plan prior to December 7, 2011 that is not then exercisable shall terminate in accordance with the terms of the 1997 Plan. If termination of employment occurs by reason of divestiture by the Company of one or more Subsidiaries or other business segments, divisions or operations in a transaction that does not otherwise qualify as a Change in Control or Change in Ownership as those terms are defined in the 1997 Plan, (i) each NSO awarded under the 1997 Plan that is then exercisable shall remain exercisable for five years from such termination or the balance of its unexpired term, whichever is less, (ii) each NSO awarded under the 1997 Plan on or after December 7, 2011 that is not then exercisable shall become immediately and fully exercisable, and shall remain exercisable for three years from such termination or the balance of its unexpired term, whichever is less, and (iii) each NSO awarded under the 1997 Plan prior to December 7, 2011 that is not then exercisable shall terminate in accordance with the terms of the 1997 Plan. If termination of employment occurs by reason of discharge by the Company for cause, or voluntary resignation of the Participant prior to age 60, each NSO awarded under the 1997 Plan shall lapse unless extended by the Committee in its discretion. If termination of employment occurs for any other reason, each NSO awarded under the 1997 Plan that is exercisable at the time of termination of employment or becomes exercisable pursuant to the terms of the 1997 Plan shall remain exercisable for five years from such termination (or such greater period as the Committee deems appropriate) or the balance of its unexpired term, whichever is less.
9
c. Extension of Incentive Stock Options Under the 1997 Plan. The Committee hereby determines that:
(i) With respect to any Participant, if termination of employment occurs by reason of death, Disability or voluntary resignation (including retirement) at or after age 60, an officer of the Company other than such Participant shall, within thirty days of such termination, offer in writing to extend the period during which any ISO granted to such optionee under the 1997 Plan may be exercised, to the date which is the earlier of five years from such termination of employment or the date on which the ISO would have otherwise expired absent such termination of employment.
(ii) If termination of such Participants employment occurs for any other reason, an officer of the Company other than such Participant, if the Committee so authorizes, shall, within thirty days of such termination, offer to extend the period during which any ISO granted to such optionee under the 1997 Plan may be exercised to the date specified in the offer, which shall not be later than the earlier of five years from such termination of employment or the date on which the ISO would have otherwise expired absent such termination of employment.
(iii) The written offer shall notify the optionee, or the optionees estate or the person to whom the optionees rights under the ISO are transferred by will or the laws of descent and distribution, of the right to accept the offer by consenting to the extension, in writing, within thirty days of the offer. If such consent is timely received the ISO may be exercised during the period specified in the offer, but not later than the expiration of the exercise period specified in the Award Notice.
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5. | Mechanics of Exercise |
To exercise a stock option, the Participant shall provide a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which stock options are being exercised, how the exercise price is to be paid and any other appropriate information. Appropriate delivery of a signed notice of exercise binds the Participant to pay the exercise price. Part IV of these rules contains procedures for exercising stock options.
6. | Reload Options |
No optionee shall be issued a new stock option automatically upon exercise of a stock option. However, if the Award Notice provides for the issuance of such new stock option, the new stock option shall have an exercise price equal to the Fair Market Value of the Common Stock on the date the new stock option is issued and shall otherwise be subject, as nearly as possible, to the same terms and conditions as the exercised stock option.
C. | SARs UNDER THE 1997 OR 2010 PLAN |
The base price or grant price of a SAR shall be the Fair Market Value of the Common Stock on the date of the grant of the SAR. Each SAR shall otherwise be subject to the terms and conditions imposed (i) by the Award Notice upon the SAR, (ii) by the applicable Plan, and (iii) by these rules upon SARs and NSOs, as applicable . A SAR shall be outstanding and exercisable during the entire exercise period otherwise applicable to an NSO if the NSO had been granted on the same day as the SAR (as adjusted in accordance with Section III(B)(4) above in the event of death or other termination of employment).
To exercise a SAR, the Participant shall deliver a signed exercise notice to an appropriate officer or other designee of the Company, which notice shall indicate which SARs are being exercised, and any other appropriate information. Part IV of these rules contains
11
procedures for exercising SARs. Any SAR not already exercised shall be deemed to be exercised at the close of business on the scheduled expiration date of such SAR, if at such time the SAR by its terms remains exercisable and, if so exercised, would result in a payment to the holder of such SAR. If upon any such deemed exercise the payment to the holder of such SAR is to be made in shares of Common Stock, the holder of such SAR shall be deemed to have elected to pay the minimum required tax withholding in shares of Common Stock.
D. | RESTRICTED STOCK AND RESTRICTED STOCK UNITS UNDER THE 1997 AND 2010 PLANS |
1. | Restrictions on Transferability; Vesting |
The restrictions on transferability and vesting and all other terms and conditions of Restricted Stock and Restricted Stock Units granted under either the 1997 Plan or the 2010 Plan shall be specified in the Award Notice. Except as otherwise provided in the applicable Plan, all shares of Restricted Stock and all Restricted Stock Units shall be subject to the Participants continued employment with the Company or a Subsidiary until vesting. The Committee may accelerate the vesting of Restricted Stock or Restricted Stock Units on its own motion as it deems appropriate and in the best interests of the Company.
2. | Mechanics of Grant |
The Committee hereby delegates to appropriate officers of the Company the authority to establish and revise appropriate procedures with respect to the issuance of certificates representing Restricted Stock and the payment of dividends thereon.
12
IV. | PROCEDURES FOR EXERCISING STOCK OPTIONS AND SARS |
A. | AUTHORITY AND SCOPE |
Notwithstanding any provision of any award letter issued before 1998, these are the exercise procedures for ISOs, NSOs and SARs issued under the 1997 Plan, the 2010 Plan, and (unless the Compensation Committee specifically orders otherwise) any other compensation plan which in the future is adopted by the Company.
B. | NOTICE OF EXERCISE |
1. | Form and Delivery |
A Participant holding stock options or SARs granted under any of the Plans elects to exercise stock options or SARs by delivering (by personal delivery, fax or e-mail) to the office of the Companys Secretary or Assistant Secretary a Notice of Exercise. A Notice of Exercise is a writing signed by the Participant indicating that the Participant thereby elects to exercise the stock options or SARs identified in the Notice (including the quantity and either the stock option exercise price or the SAR base price), and describing the method by which the Participant will pay the exercise price of the stock options (since there is no exercise price payment due in connection with the exercise of a SAR). Appropriate delivery of a Notice of Exercise binds the Participant to pay the exercise price. Optional forms of Notice of Exercise are attached to these rules (see Exhibit A).
2. | Exercise Date |
The effective date of a Notice of Exercise is the Exercise Date. An exercise will be effective as of the date the Notice of Exercise is received by the office of the Secretary or Assistant Secretary; provided, however , that:
(i) a Notice of Exercise received on a trading day before trading opens that day on the New York Stock Exchange may validly designate the Exercise Date to be the preceding trading day;
13
(ii) a Notice of Exercise may validly designate the Exercise Date to be any date later than the date the Notice of Exercise is received; and
(iii) if the exercise of a stock option is accomplished through a cashless exercise as described in Section IV(C)(4) below, the Exercise Date shall be the date the broker sells Company stock into the market regarding that exercise.
C. | PAYMENT OF EXERCISE PRICE |
1. | Cash Payment |
To pay the exercise price of a stock option in cash, a Participant must deliver to the Secretary or Assistant Secretary payment in full, in cash or by check payable in immediately available U.S. funds to the Company, within three business days after the Exercise Date (except as additional time may be allowed under Section IV(C)(3) below). For purposes of these rules, the term business day shall mean any day other than a Saturday, Sunday, federal holiday or day on which the Companys principal office is closed for business. Subject to Section IV(D) below, payment of the exercise price may be partly in cash and partly in Company stock as described in Section IV(C)(2) below, or may be accomplished through a cashless exercise as described in Section IV(C)(4) below.
2. | Payment with Existing Company Stock |
To pay the exercise price in shares of Company stock already owned by a Participant, the Participant must surrender to the Company shares having a total Fair Market Value (as of the Exercise Date) of at least the total exercise price, or pay any shortfall in cash. The Participant must, within three business days after the Exercise Date (except as additional time may be allowed under Section IV(C)(3) below) do one or both of the following:
a. | regarding shares in the Companys Direct Registration System, comply with the Companys procedures (including signature guarantee requirements) for transferring book-entry shares to the Company; or |
14
b. | regarding shares that are evidenced by a paper stock certificate, deliver the certificate to the Secretary or Assistant Secretary. Each certificate delivered must have a guaranteed signature either on the back or on a stock power to be attached. The recommended procedure for mailing certificates is to mail the certificate and signed stock power separately. |
3. | Additional Time to Pay Exercise Price |
If, at any time the Participants payment of the exercise price would otherwise be required pursuant to Section IV(C)(1) or (2) above, a Participant is either
a. traveling away from his or her usual place of Company employment, or
b. disabled, as defined in the applicable Plan or these rules, then, to the extent permitted by applicable law, the Participant may pay the exercise price on or before the first business day after the Participants return to his or her usual place of NFG employment, but no later than the tenth business day after the Exercise Date. However, the President, Chief Executive Officer, Treasurer or General Counsel of the Company shall have the authority to grant such additional time to pay the exercise price as is reasonably necessary to accommodate the travel or disability of the Participant.
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4. | Cashless Exercise |
The broker-assisted method of exercising stock options described in this Section IV(C)(4) (cashless exercise) requires no cash outlay by the Participant. A Participant wishing to do a cashless exercise must first establish a trading account with a registered securities broker-dealer. Establishing that trading account will likely include the Participants commitment to pay the broker as described in their agreement. Upon request by a Participant, the Secretary or Assistant Secretary will provide information that may help the Participant find a broker who has previously done cashless exercises with the Company and/or may be willing to do so at a discounted commission rate. The Participant must provide the Secretary or Assistant Secretary with the Participants brokers name, firm, address, telephone and fax numbers.
To do a cashless exercise, the Participant must deliver a Notice of Exercise as described in Section IV(B)(1), and notify the Participants broker to proceed with the exercise and to notify the Company of the date the stock is sold. The Participants broker will sell Company stock for the Participants account and pay to the Company the exercise price, plus any necessary tax withholding. The Company will have share certificates delivered to the Participants broker within three business days after the Exercise Date, unless the Company elects to retain the certificates pending receipt of the exercise price. The Participant will be required to pay the Participants broker according to the agreement between them, typically a few days interest on the exercise price plus a commission on the shares sold.
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D. | RESTRICTIONS RELATING TO POSSESSION OF MATERIAL NON-PUBLIC INFORMATION |
Notwithstanding anything to the contrary provided above in these rules, a Participant may not, while in possession of material nonpublic information relating to the Company, or while subject to any quarterly or other blackout period imposed under the Companys Policy on Insider Trading in National Fuel Gas Company Securities, (i) pay the exercise price of a stock option with Company stock, (ii) pay tax withholding in connection with the exercise or vesting of any Award by having Company stock withheld and/or canceled, (iii) exercise SARs, or (iv) effect a cashless exercise of stock options. For a Participant subject to a quarterly or other blackout period, these prohibited transactions include any transaction the effective date of which occurs within the blackout period.
The restrictions set forth in this Section IV(D) shall not apply to any deemed exercise of SARs or deemed payment of tax withholding in connection therewith pursuant to a Plan or these rules, or to any transaction effected pursuant to an instruction, contract or written plan that meets the requirements of Rule 10b5-1(c) under the Securities Exchange Act of 1934, which provides a defense against insider trading liability. An instruction, contract or written plan relating to any transactions set forth in this Section IV(D) and intended by a Participant to comply with Rule 10b5-1 (such as a written 10b5-1 plan on a form provided by a stockbroker) must meet the requirements of Rule 10b5-1(c) and should be pre-approved by the NFG Legal Department before the Participant enters into any transactions under that instruction, contract or written plan.
17
EXHIBIT 12
NATIONAL FUEL GAS COMPANY
COMPUTATION OF RATIO OF
EARNINGS TO FIXED CHARGES
UNAUDITED
(1) | Investment Tax Credit is included in Other Income. |
(2) | Rentals shown above represent the portion of all rentals (other than delay rentals) deemed representative of the interest factor. |
(3) | Fiscal 2009 includes an impairment of an investment in a partnership of $1,804. |
EXHIBIT 31.1
CERTIFICATION
I, D. F. Smith, certify that:
1. I have reviewed this quarterly report on Form 10-Q of National Fuel Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: February 3, 2012
/s/ D. F. Smith |
D. F. Smith Chairman of the Board and Chief Executive Officer |
EXHIBIT 31.2
CERTIFICATION
I, D. P. Bauer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of National Fuel Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: February 3, 2012
/s/ D. P. Bauer |
D. P. Bauer Treasurer and Principal Financial Officer |
EXHIBIT 32
NATIONAL FUEL GAS COMPANY
Certification Pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
Each of the undersigned, D. F. SMITH, Chairman of the Board and Chief Executive Officer and D. P. BAUER, the Treasurer and Principal Financial Officer of NATIONAL FUEL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:
1. | The Companys Quarterly Report on Form 10-Q for the quarter ended December 31, 2011 (the Report) fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934, as amended; and |
2. | Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
IN WITNESS WHEREOF, each of the undersigned has executed this statement this 3rd day of February, 2012.
/s/ D. F. Smith |
Chairman of the Board and Chief Executive Officer |
/s/ D. P. Bauer |
Treasurer and Principal Financial Officer |
Exhibit 99
NATIONAL FUEL GAS
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Twelve Months Ended
December 31 |
||||||||
2011 | 2010 | |||||||
(Thousands of Dollars) | ||||||||
INCOME |
||||||||
Operating Revenues |
$ | 1,760,317 | $ | 1,757,316 | ||||
|
|
|
|
|||||
Operating Expenses |
||||||||
Purchased Gas |
597,887 | 650,180 | ||||||
Operation and Maintenance |
403,128 | 398,249 | ||||||
Property, Franchise and Other Taxes |
81,396 | 76,938 | ||||||
Depreciation, Depletion and Amortization |
235,761 | 199,724 | ||||||
|
|
|
|
|||||
1,318,172 | 1,325,091 | |||||||
|
|
|
|
|||||
Operating Income |
442,145 | 432,225 | ||||||
Other Income (Expense): |
||||||||
Gain on Sale of Unconsolidated Subsidiaries |
50,879 | | ||||||
Interest Income |
3,137 | 3,459 | ||||||
Other Income |
7,390 | 5,262 | ||||||
Interest Expense on Long-Term Debt |
(72,017 | ) | (85,319 | ) | ||||
Other Interest Expense |
(3,923 | ) | (6,780 | ) | ||||
|
|
|
|
|||||
Income from Continuing Operations Before Income Taxes |
427,611 | 348,847 | ||||||
Income Tax Expense |
167,054 | 135,395 | ||||||
|
|
|
|
|||||
Income from Continuing Operations |
260,557 | 213,452 | ||||||
Income from Discontinued Operations |
| 6,506 | ||||||
|
|
|
|
|||||
Net Income Available for Common Stock |
$ | 260,557 | $ | 219,958 | ||||
|
|
|
|
|||||
Earnings Per Common Share: |
||||||||
Basic: |
||||||||
Income from Continuing Operations |
$ | 3.15 | $ | 2.61 | ||||
Income from Discontinued Operations |
| 0.08 | ||||||
|
|
|
|
|||||
Net Income Available for Common Stock |
$ | 3.15 | $ | 2.69 | ||||
|
|
|
|
|||||
Diluted: |
||||||||
Income from Continuing Operations |
$ | 3.11 | $ | 2.57 | ||||
Income from Discontinued Operations |
| 0.08 | ||||||
|
|
|
|
|||||
Net Income Available for Common Stock |
$ | 3.11 | $ | 2.65 | ||||
|
|
|
|
|||||
Weighted Average Common Shares Outstanding: |
||||||||
Used in Basic Calculation |
82,677,232 | 81,786,524 | ||||||
|
|
|
|
|||||
Used in Diluted Calculation |
83,726,544 | 82,989,108 | ||||||
|
|
|
|