e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2009
OR
|
|
|
o |
|
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 þ NO o
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 o NO o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or 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 þ | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). YES o NO þ
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 July 31, 2009: 80,234,282 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 |
|
|
|
Data-Track
|
|
Data-Track Account Services, Inc. |
|
|
|
Distribution Corporation
|
|
National Fuel Gas Distribution Corporation |
|
|
|
Empire
|
|
Empire Pipeline, Inc. |
|
|
|
ESNE
|
|
Energy Systems North East, LLC |
|
|
|
Highland
|
|
Highland Forest Resources, Inc. |
|
|
|
Horizon
|
|
Horizon Energy Development, Inc. |
|
|
|
Horizon LFG
|
|
Horizon LFG, Inc. |
|
|
|
Horizon Power
|
|
Horizon Power, Inc. |
|
|
|
Leidy Hub
|
|
Leidy Hub, 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 |
|
|
|
SECI
|
|
Seneca Energy Canada Inc. |
|
|
|
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 |
|
|
|
NYDEC
|
|
New York State Department of Environmental Conservation |
|
|
|
NYPSC
|
|
State of New York Public Service Commission |
|
|
|
PaPUC
|
|
Pennsylvania Public Utility Commission |
|
|
|
SEC
|
|
Securities and Exchange Commission |
|
|
|
Other
|
|
|
|
|
|
2008 Form 10-K
|
|
The Companys Annual Report on Form 10-K for the year ended
September 30, 2008, as amended |
|
|
|
ARB 51
|
|
Accounting Research Bulletin No. 51, Consolidated Financial Statements |
|
|
|
Bbl
|
|
Barrel (of oil) |
|
|
|
Bcf
|
|
Billion cubic feet (of natural gas) |
|
|
|
Board foot
|
|
A measure of lumber and/or timber equal to 12 inches in length by 12
inches in width by one inch in thickness. |
|
|
|
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 reserves and to provide |
|
|
facilities for extracting, treating, gathering and storing the oil and gas. |
|
|
|
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 |
-2-
|
|
|
GLOSSARY OF TERMS (Cont.) |
|
|
|
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. |
|
|
|
FIN
|
|
FASB Interpretation Number |
|
|
|
FIN 48
|
|
FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes
an interpretation of SFAS 109 |
|
|
|
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 |
|
|
|
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) |
|
|
|
NYMEX
|
|
New York Mercantile Exchange. An exchange which maintains a futures
market for crude oil and natural gas. |
|
|
|
Proved developed reserves
|
|
Reserves that can be expected to be recovered through existing wells
with existing equipment and operating methods. |
|
|
|
Proved undeveloped
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. |
|
|
|
Restructuring
|
|
Generally referring to partial deregulation of the pipeline and/or utility
industries by a statutory or regulatory process. Restructuring of
federally regulated natural gas pipelines has 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. |
|
|
|
S&P
|
|
Standard & Poors Ratings Service |
|
|
|
SAR
|
|
Stock-settled stock appreciation right |
|
|
|
SFAS
|
|
Statement of Financial Accounting Standards |
|
|
|
SFAS 87
|
|
Statement of Financial Accounting Standards No. 87, Employers
Accounting for Pensions |
|
|
|
SFAS 88
|
|
Statement of Financial Accounting Standards No. 88, Employers
Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits |
|
|
|
SFAS 106
|
|
Statement of Financial Accounting Standards No. 106, Employers
Accounting for Postretirement Benefits Other Than Pensions |
|
|
|
SFAS 109
|
|
Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes |
-3-
|
|
|
GLOSSARY OF TERMS (Concl.) |
|
|
|
SFAS 123R
|
|
Statement of Financial Accounting Standards No. 123R, Share-Based
Payment |
|
|
|
SFAS 131
|
|
Statement of Financial Accounting Standards No. 131, Disclosures about
Segments of an Enterprise and Related Information |
|
|
|
SFAS 132R
|
|
Statement of Financial Accounting Standards No. 132R, Employers
Disclosures about Pensions and Other Postretirement Benefits |
|
|
|
SFAS 133
|
|
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities |
|
|
|
SFAS 141R
|
|
Statement of Financial Accounting Standards No. 141R, Business
Combinations |
|
|
|
SFAS 157
|
|
Statement of Financial Accounting Standards No. 157, Fair Value
Measurements |
|
|
|
SFAS 158
|
|
Statement of Financial Accounting Standards No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans, an Amendment of SFAS 87, 88, 106, and 132R |
|
|
|
SFAS 160
|
|
Statement of Financial Accounting Standards No. 160, Noncontrolling
Interests in Consolidated Financial Statements, an Amendment of
ARB 51 |
|
|
|
SFAS 161
|
|
Statement of Financial Accounting Standards No. 161, Disclosures about
Derivative Instruments and Hedging Activities, an Amendment of
SFAS 133 |
|
|
|
SFAS 165
|
|
Statement of Financial Accounting Standards No. 165, Subsequent
Events |
|
|
|
SFAS 168
|
|
Statement of Financial Accounting Standards No. 168, The FASB
Accounting Standards Codification TM and the Hierarchy of Generally
Accepted Accounting Principles a Replacement of FASB Statement
No. 162 |
|
|
|
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-
INDEX
|
|
|
|
|
|
|
Page |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 - 7 |
|
|
|
|
8 - 9 |
|
|
|
|
10 |
|
|
|
|
11 |
|
|
|
|
12 - 31 |
|
|
|
|
32 - 55 |
|
|
|
|
55 |
|
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55 |
|
|
|
|
55 - 57 |
|
|
|
|
57 - 58 |
|
Item 3. Defaults Upon Senior Securities |
|
|
|
|
Item 4. Submission of Matters to a Vote of Security Holders |
|
|
|
|
Item 5. Other Information |
|
|
|
|
|
|
|
58 |
|
|
|
|
59 |
|
|
|
|
|
|
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 2 MD&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, 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-
Part I. Financial Information
Item 1. Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
June 30, |
(Thousands of Dollars, Except Per Common Share Amounts) |
|
2009 |
|
2008 |
|
|
|
INCOME |
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
367,111 |
|
|
$ |
548,382 |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
Purchased Gas |
|
|
126,969 |
|
|
|
272,893 |
|
Operation and Maintenance |
|
|
90,821 |
|
|
|
102,602 |
|
Property, Franchise and Other Taxes |
|
|
17,576 |
|
|
|
19,135 |
|
Depreciation, Depletion and Amortization |
|
|
43,659 |
|
|
|
42,804 |
|
|
|
|
|
279,025 |
|
|
|
437,434 |
|
|
Operating Income |
|
|
88,086 |
|
|
|
110,948 |
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries |
|
|
627 |
|
|
|
1,561 |
|
Interest Income |
|
|
1,460 |
|
|
|
3,086 |
|
Other Income |
|
|
664 |
|
|
|
1,649 |
|
Interest Expense on Long-Term Debt |
|
|
(21,756 |
) |
|
|
(19,468 |
) |
Other Interest Expense |
|
|
(2,539 |
) |
|
|
(1,199 |
) |
|
Income Before Income Taxes |
|
|
66,542 |
|
|
|
96,577 |
|
Income Tax Expense |
|
|
23,638 |
|
|
|
36,722 |
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
|
42,904 |
|
|
|
59,855 |
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS |
|
|
|
|
|
|
|
|
Balance at April 1 |
|
|
932,119 |
|
|
|
1,008,084 |
|
|
|
|
|
975,023 |
|
|
|
1,067,939 |
|
Share Repurchases |
|
|
|
|
|
|
(17,083 |
) |
Dividends on Common Stock
(2009 $0.335 per share; 2008 $0.325 per share) |
|
|
(26,761 |
) |
|
|
(26,479 |
) |
|
Balance at June 30 |
|
$ |
948,262 |
|
|
$ |
1,024,377 |
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share: |
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
0.54 |
|
|
$ |
0.74 |
|
|
Diluted: |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
0.53 |
|
|
$ |
0.72 |
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Used in Basic Calculation |
|
|
79,551,195 |
|
|
|
81,342,788 |
|
|
Used in Diluted Calculation |
|
|
80,391,402 |
|
|
|
83,712,193 |
|
|
See Notes to Condensed Consolidated Financial Statements
-6-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
June 30, |
(Thousands of Dollars, Except Per Common Share Amounts) |
|
2009 |
|
2008 |
|
|
|
INCOME |
|
|
|
|
|
|
|
|
Operating Revenues |
|
$ |
1,778,919 |
|
|
$ |
2,002,503 |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses |
|
|
|
|
|
|
|
|
Purchased Gas |
|
|
941,171 |
|
|
|
1,082,340 |
|
Operation and Maintenance |
|
|
310,605 |
|
|
|
325,642 |
|
Property, Franchise and Other Taxes |
|
|
56,709 |
|
|
|
58,206 |
|
Depreciation, Depletion and Amortization |
|
|
127,715 |
|
|
|
129,337 |
|
Impairment of Oil and Gas Producing Properties |
|
|
182,811 |
|
|
|
|
|
|
|
|
|
1,619,011 |
|
|
|
1,595,525 |
|
|
Operating Income |
|
|
159,908 |
|
|
|
406,978 |
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
Income from Unconsolidated Subsidiaries |
|
|
915 |
|
|
|
4,866 |
|
Interest Income |
|
|
4,358 |
|
|
|
8,356 |
|
Other Income |
|
|
6,459 |
|
|
|
4,982 |
|
Interest Expense on Long-Term Debt |
|
|
(57,357 |
) |
|
|
(52,045 |
) |
Other Interest Expense |
|
|
(5,013 |
) |
|
|
(4,209 |
) |
|
Income Before Income Taxes |
|
|
109,270 |
|
|
|
368,928 |
|
Income Tax Expense |
|
|
35,560 |
|
|
|
143,465 |
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
|
73,710 |
|
|
|
225,463 |
|
|
|
|
|
|
|
|
|
|
|
EARNINGS REINVESTED IN THE BUSINESS |
|
|
|
|
|
|
|
|
Balance at October 1 |
|
|
953,799 |
|
|
|
983,776 |
|
|
|
|
|
1,027,509 |
|
|
|
1,209,239 |
|
Share Repurchases |
|
|
|
|
|
|
(106,647 |
) |
Cumulative Effect of the Adoption of FIN 48 |
|
|
|
|
|
|
(406 |
) |
Adoption of SFAS 158 Measurement Date Provision |
|
|
(804 |
) |
|
|
|
|
Dividends on Common Stock
(2009 $0.985 per share; 2008 $0.945 per share) |
|
|
(78,443 |
) |
|
|
(77,809 |
) |
|
Balance at June 30 |
|
$ |
948,262 |
|
|
$ |
1,024,377 |
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share: |
|
|
|
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
0.93 |
|
|
$ |
2.72 |
|
|
Diluted: |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
0.92 |
|
|
$ |
2.65 |
|
|
Weighted Average Common Shares Outstanding: |
|
|
|
|
|
|
|
|
Used in Basic Calculation |
|
|
79,450,838 |
|
|
|
82,789,748 |
|
|
Used in Diluted Calculation |
|
|
80,248,787 |
|
|
|
85,000,381 |
|
|
See Notes to Condensed Consolidated Financial Statements
-7-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
September 30, |
(Thousands of Dollars) |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
5,078,088 |
|
|
$ |
4,873,969 |
|
Less Accumulated Depreciation, Depletion
and Amortization |
|
|
2,010,584 |
|
|
|
1,719,869 |
|
|
|
|
|
3,067,504 |
|
|
|
3,154,100 |
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments |
|
|
433,230 |
|
|
|
68,239 |
|
Cash Held in Escrow |
|
|
2,000 |
|
|
|
|
|
Hedging Collateral Deposits |
|
|
6,359 |
|
|
|
1 |
|
Receivables Net of Allowance for Uncollectible Accounts of
$45,209 and $33,117, Respectively |
|
|
200,594 |
|
|
|
185,397 |
|
Unbilled Utility Revenue |
|
|
14,568 |
|
|
|
24,364 |
|
Gas Stored Underground |
|
|
27,721 |
|
|
|
87,294 |
|
Materials and Supplies at average cost |
|
|
24,768 |
|
|
|
31,317 |
|
Unrecovered Purchased Gas Costs |
|
|
1,900 |
|
|
|
37,708 |
|
Other Current Assets |
|
|
32,477 |
|
|
|
65,158 |
|
Deferred Income Taxes |
|
|
33,009 |
|
|
|
|
|
|
|
|
|
776,626 |
|
|
|
499,478 |
|
|
|
|
|
|
|
|
|
|
|
Other Assets |
|
|
|
|
|
|
|
|
Recoverable Future Taxes |
|
|
83,543 |
|
|
|
82,506 |
|
Unamortized Debt Expense |
|
|
15,345 |
|
|
|
13,978 |
|
Other Regulatory Assets |
|
|
196,278 |
|
|
|
189,587 |
|
Deferred Charges |
|
|
1,790 |
|
|
|
4,417 |
|
Other Investments |
|
|
73,174 |
|
|
|
80,640 |
|
Investments in Unconsolidated Subsidiaries |
|
|
15,094 |
|
|
|
16,279 |
|
Goodwill |
|
|
5,476 |
|
|
|
5,476 |
|
Intangible Assets |
|
|
24,627 |
|
|
|
26,174 |
|
Prepaid Post-Retirement Benefit Costs |
|
|
21,738 |
|
|
|
21,034 |
|
Fair Value of Derivative Financial Instruments |
|
|
66,193 |
|
|
|
28,786 |
|
Other |
|
|
7,914 |
|
|
|
7,732 |
|
|
|
|
|
511,172 |
|
|
|
476,609 |
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
4,355,302 |
|
|
$ |
4,130,187 |
|
|
See Notes to Condensed Consolidated Financial Statements
-8-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
September 30, |
|
|
2009 |
|
2008 |
|
|
|
(Thousands of Dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITALIZATION AND LIABILITIES |
|
|
|
|
|
|
|
|
Capitalization: |
|
|
|
|
|
|
|
|
Comprehensive Shareholders Equity |
|
|
|
|
|
|
|
|
Common Stock, $1 Par Value
Authorized 200,000,000 Shares; Issued
and Outstanding 79,881,482 Shares and
79,120,544 Shares, Respectively |
|
$ |
79,881 |
|
|
$ |
79,121 |
|
Paid in Capital |
|
|
589,295 |
|
|
|
567,716 |
|
Earnings Reinvested in the Business |
|
|
948,262 |
|
|
|
953,799 |
|
|
Total Common Shareholder Equity Before
Items of Other Comprehensive Income |
|
|
1,617,438 |
|
|
|
1,600,636 |
|
Accumulated Other Comprehensive Income |
|
|
17,234 |
|
|
|
2,963 |
|
|
Total Comprehensive Shareholders Equity |
|
|
1,634,672 |
|
|
|
1,603,599 |
|
Long-Term Debt, Net of Current Portion |
|
|
1,249,000 |
|
|
|
999,000 |
|
|
Total Capitalization |
|
|
2,883,672 |
|
|
|
2,602,599 |
|
|
|
|
|
|
|
|
|
|
|
Current and Accrued Liabilities |
|
|
|
|
|
|
|
|
Notes Payable to Banks and Commercial Paper |
|
|
|
|
|
|
|
|
Current Portion of Long-Term Debt |
|
|
|
|
|
|
100,000 |
|
Accounts Payable |
|
|
69,762 |
|
|
|
142,520 |
|
Amounts Payable to Customers |
|
|
45,772 |
|
|
|
2,753 |
|
Dividends Payable |
|
|
26,761 |
|
|
|
25,714 |
|
Interest Payable on Long-Term Debt |
|
|
18,722 |
|
|
|
22,114 |
|
Customer Advances |
|
|
3,229 |
|
|
|
33,017 |
|
Other Accruals and Current Liabilities |
|
|
198,057 |
|
|
|
45,220 |
|
Deferred Income Taxes |
|
|
|
|
|
|
1,871 |
|
Fair Value of Derivative Financial Instruments |
|
|
1,815 |
|
|
|
1,362 |
|
|
|
|
|
364,118 |
|
|
|
374,571 |
|
|
|
|
|
|
|
|
|
|
|
Deferred Credits |
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
589,380 |
|
|
|
634,372 |
|
Taxes Refundable to Customers |
|
|
18,459 |
|
|
|
18,449 |
|
Unamortized Investment Tax Credit |
|
|
4,165 |
|
|
|
4,691 |
|
Cost of Removal Regulatory Liability |
|
|
107,245 |
|
|
|
103,100 |
|
Other Regulatory Liabilities |
|
|
115,617 |
|
|
|
91,933 |
|
Pension and Other Post-Retirement Liabilities |
|
|
61,404 |
|
|
|
78,909 |
|
Asset Retirement Obligations |
|
|
86,559 |
|
|
|
93,247 |
|
Other Deferred Credits |
|
|
124,683 |
|
|
|
128,316 |
|
|
|
|
|
1,107,512 |
|
|
|
1,153,017 |
|
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Capitalization and Liabilities |
|
$ |
4,355,302 |
|
|
$ |
4,130,187 |
|
|
See Notes to Condensed Consolidated Financial Statements
-9-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statement of Cash Flows
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
June 30, |
(Thousands of Dollars) |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
73,710 |
|
|
$ |
225,463 |
|
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |
|
|
|
|
|
|
|
|
Impairment of Oil and Gas Producing Properties |
|
|
182,811 |
|
|
|
|
|
Depreciation, Depletion and Amortization |
|
|
127,715 |
|
|
|
129,337 |
|
Deferred Income Taxes |
|
|
(85,494 |
) |
|
|
27,603 |
|
Income from Unconsolidated Subsidiaries, Net of
Cash Distributions |
|
|
180 |
|
|
|
1,340 |
|
Impairment of Investment in Partnership |
|
|
1,804 |
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
(5,927 |
) |
|
|
(16,275 |
) |
Other |
|
|
9,365 |
|
|
|
(1,120 |
) |
Change in: |
|
|
|
|
|
|
|
|
Hedging Collateral Deposits |
|
|
(6,358 |
) |
|
|
(26,712 |
) |
Receivables and Unbilled Utility Revenue |
|
|
(5,520 |
) |
|
|
(129,102 |
) |
Gas Stored Underground and Materials and Supplies |
|
|
71,491 |
|
|
|
14,819 |
|
Unrecovered Purchased Gas Costs |
|
|
35,808 |
|
|
|
9,089 |
|
Prepayments and Other Current Assets |
|
|
37,904 |
|
|
|
17,370 |
|
Accounts Payable |
|
|
(82,146 |
) |
|
|
53,081 |
|
Amounts Payable to Customers |
|
|
43,019 |
|
|
|
2,455 |
|
Customer Advances |
|
|
(29,788 |
) |
|
|
(22,863 |
) |
Other Accruals and Current Liabilities |
|
|
166,217 |
|
|
|
94,031 |
|
Other Assets |
|
|
(8,517 |
) |
|
|
19,178 |
|
Other Liabilities |
|
|
(14,453 |
) |
|
|
17,373 |
|
|
Net Cash Provided by Operating Activities |
|
|
511,821 |
|
|
|
415,067 |
|
|
|
|
|
|
|
|
|
|
|
INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
(237,126 |
) |
|
|
(264,728 |
) |
Investment in Partnership |
|
|
(800 |
) |
|
|
|
|
Cash Held in Escrow |
|
|
(2,000 |
) |
|
|
58,397 |
|
Net Proceeds from Sale of Oil and Gas Producing Properties |
|
|
3,701 |
|
|
|
5,675 |
|
Other |
|
|
(1,674 |
) |
|
|
(3,414 |
) |
|
Net Cash Used in Investing Activities |
|
|
(237,899 |
) |
|
|
(204,070 |
) |
|
|
|
|
|
|
|
|
|
|
FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
Excess Tax Benefits Associated with Stock-Based
Compensation Awards |
|
|
5,927 |
|
|
|
16,275 |
|
Shares Repurchased under Repurchase Plan |
|
|
|
|
|
|
(129,592 |
) |
Net Proceeds from Issuance of Long-Term Debt |
|
|
247,780 |
|
|
|
296,655 |
|
Reduction of Long-Term Debt |
|
|
(100,000 |
) |
|
|
(200,024 |
) |
Dividends Paid on Common Stock |
|
|
(77,398 |
) |
|
|
(77,204 |
) |
Net Proceeds from Issuance of Common Stock |
|
|
14,760 |
|
|
|
17,285 |
|
|
Net Cash Provided by (Used in) Financing Activities |
|
|
91,069 |
|
|
|
(76,605 |
) |
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Temporary Cash Investments |
|
|
364,991 |
|
|
|
134,392 |
|
Cash and Temporary Cash Investments at October 1 |
|
|
68,239 |
|
|
|
124,806 |
|
|
|
|
|
|
|
|
|
|
|
Cash and Temporary Cash Investments at June 30 |
|
$ |
433,230 |
|
|
$ |
259,198 |
|
|
See Notes to Condensed Consolidated Financial Statements
-10-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
June 30, |
(Thousands of Dollars) |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
42,904 |
|
|
$ |
59,855 |
|
|
Other Comprehensive Loss, Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
(42 |
) |
|
|
2 |
|
Unrealized Gain (Loss) on Securities Available for Sale
Arising During the Period |
|
|
3,775 |
|
|
|
(1,603 |
) |
Unrealized Loss on Derivative Financial Instruments
Arising During the Period |
|
|
(24,446 |
) |
|
|
(139,684 |
) |
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income |
|
|
(24,853 |
) |
|
|
33,082 |
|
|
Other Comprehensive Loss, Before Tax |
|
|
(45,566 |
) |
|
|
(108,203 |
) |
|
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Securities Available for Sale Arising During the Period |
|
|
1,429 |
|
|
|
(608 |
) |
Income Tax Benefit Related to Unrealized Loss
on Derivative Financial Instruments Arising During the Period |
|
|
(9,950 |
) |
|
|
(57,136 |
) |
Reclassification Adjustment for Income Tax (Expense) Benefit on
Realized (Gains) Losses from Derivative Financial Instruments
in Net Income |
|
|
(10,108 |
) |
|
|
13,546 |
|
|
Income Taxes Net |
|
|
(18,629 |
) |
|
|
(44,198 |
) |
|
Other Comprehensive Loss |
|
|
(26,937 |
) |
|
|
(64,005 |
) |
|
Comprehensive Income (Loss) |
|
$ |
15,967 |
|
|
$ |
(4,150 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
June 30, |
(Thousands of Dollars) |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Available for Common Stock |
|
$ |
73,710 |
|
|
$ |
225,463 |
|
|
Other Comprehensive Income (Loss), Before Tax: |
|
|
|
|
|
|
|
|
Foreign Currency Translation Adjustment |
|
|
(1 |
) |
|
|
(72 |
) |
Unrealized Loss on Securities Available for Sale
Arising During the Period |
|
|
(9,202 |
) |
|
|
(4,817 |
) |
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period |
|
|
127,357 |
|
|
|
(208,256 |
) |
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income |
|
|
(93,260 |
) |
|
|
45,242 |
|
|
Other Comprehensive Income (Loss), Before Tax |
|
|
24,894 |
|
|
|
(167,903 |
) |
|
Income Tax Benefit Related to Unrealized Loss
on Securities Available for Sale Arising During the Period |
|
|
(3,475 |
) |
|
|
(1,429 |
) |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
on Derivative Financial Instruments Arising During the Period |
|
|
51,576 |
|
|
|
(85,300 |
) |
Reclassification Adjustment for Income Tax (Expense) Benefit on
Realized (Gains) Losses on Derivative Financial Instruments
in Net Income |
|
|
(37,478 |
) |
|
|
18,495 |
|
|
Income Taxes Net |
|
|
10,623 |
|
|
|
(68,234 |
) |
|
Other Comprehensive Income (Loss) |
|
|
14,271 |
|
|
|
(99,669 |
) |
|
Comprehensive Income |
|
$ |
87,981 |
|
|
$ |
125,794 |
|
|
See Notes to Condensed Consolidated Financial Statements
-11-
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 Summary of Significant Accounting Policies
Principles of Consolidation. The Company consolidates its majority owned entities. The equity
method is used to account for minority owned entities. 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.
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, 2008, 2007 and 2006 that
are included in the Companys 2008 Form 10-K. The consolidated financial statements for the year
ended September 30, 2009 will be audited by the Companys independent registered public accounting
firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2009 should not be taken as a prediction of
earnings for the entire fiscal year ending September 30, 2009. 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 debt instruments purchased with a maturity of generally
three months or less to be cash equivalents.
At June 30, 2009, the Company accrued $9.4 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 June 30, 2009 since it represents a
non-cash investing activity at that date.
At September 30, 2008, the Company accrued $16.8 million of capital expenditures related to
the construction of the Empire Connector project. This amount was excluded from the Consolidated
Statement of Cash Flows at September 30, 2008 since it represented a non-cash investing activity at
that date. These capital expenditures were paid during the quarter ended December 31, 2008 and
have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30,
2009.
Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by
the Company to serve as collateral for open hedging positions. At June 30, 2009, the Company had
hedging collateral deposits of $6.4 million related to its exchange-traded futures contracts. It
is the Companys policy to not offset hedging collateral deposits paid or received against the
derivative financial instruments liability or asset balances.
Cash Held in Escrow. On July 20, 2009, the Company announced that in its Exploration and
Production segment, Seneca had purchased Ivanhoe Energys United States oil and gas operations for
approximately $39.2 million, of which $2 million was placed in escrow as a deposit for the
acquisition as of June 30, 2009.
-12-
Item 1. Financial Statements (Cont.)
On August 31, 2007, the Company received approximately $232.1 million of proceeds from the
sale of SECI, of which $58.0 million was placed in escrow pending receipt of a tax clearance
certificate from the Canadian government. The escrow account was a Canadian dollar denominated
account. On a U.S. dollar basis, the value of this account was $62.0 million at September 30,
2007. In December 2007, the Canadian government issued the tax clearance certificate, thereby
releasing the proceeds from restriction as of December 31, 2007. To hedge against foreign currency
exchange risk related to the cash being held in escrow, the Company held a forward contract to sell
Canadian dollars. For presentation purposes on the Consolidated Statement of Cash Flows, for the
nine months ended June 30, 2008, the Cash Held in Escrow line item within Investing Activities
reflects the net proceeds to the Company (received on January 8, 2008) after adjusting for the
impact of the foreign currency hedge.
Gas Stored Underground Current. 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 $116.5 million at June 30, 2009, 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. 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 current market 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. 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. The
Companys capitalized costs exceeded the full cost ceiling for the Companys oil and gas properties
at December 31, 2008. As such, the Company recognized a pre-tax impairment of $182.8 million at
December 31, 2008. Deferred income taxes of $74.6 million were recorded associated with this
impairment.
-13-
Item 1. Financial Statements (Cont.)
Accumulated Other Comprehensive Income. The components of Accumulated Other Comprehensive Income,
net of related tax effect, are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2009 |
|
|
At September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
Funded Status of the Pension and
Other Post-Retirement Benefit Plans |
|
$ |
(19,741 |
) |
|
$ |
(19,741 |
) |
Cumulative Foreign Currency
Translation Adjustment |
|
|
(72 |
) |
|
|
(71 |
) |
Net Unrealized Gain on Derivative
Financial Instruments |
|
|
35,948 |
|
|
|
15,949 |
|
Net Unrealized Gain on Securities
Available for Sale |
|
|
1,099 |
|
|
|
6,826 |
|
|
|
|
|
|
|
|
Accumulated Other Comprehensive
Income |
|
$ |
17,234 |
|
|
$ |
2,963 |
|
|
|
|
|
|
|
|
Earnings Per Common Share. Basic earnings per common share is computed by dividing 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 and stock-settled SARs. The diluted weighted average
shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution
as a result of these stock options and stock-settled SARs as determined using the Treasury Stock
Method. Stock options and stock-settled SARs that are antidilutive are excluded from the
calculation of diluted earnings per common share. For both the quarter and nine months ended June
30, 2009, there were 765,000 stock options excluded as being antidilutive. In addition, there were
365,000 stock-settled SARs excluded as being antidilutive for both the quarter and nine months
ended June 30, 2009. For the quarter and nine months ended June 30, 2008, there were 6,593 and
2,190 stock-settled SARs excluded as being antidilutive, respectively. There were no stock options
excluded as being antidilutive for the quarter and nine months ended June 30, 2008.
Share Repurchases. The Company considers all shares repurchased as cancelled shares restored to
the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases
are accounted for on the date the share repurchase is settled as an adjustment to common stock (at
par value) with the excess repurchase price allocated between paid in capital and retained
earnings.
Stock-Based Compensation. During the nine months ended June 30, 2009, the Company granted 610,000
performance-based stock-settled SARs having a weighted average exercise price of $29.88 per share.
The weighted average grant date fair value of these stock-settled SARs was $4.09 per share. There
were no stock-settled SARs granted during the quarter ended June 30, 2009. The accounting treatment
for such stock-settled SARs is the same under SFAS 123R as the accounting for stock options under
SFAS 123R. The stock-settled SARs granted during the nine months ended June 30, 2009 vest and
become exercisable annually in one-third increments, provided that a performance condition is met.
The performance condition for each fiscal year, generally stated, is an increase over the prior
fiscal year of at least five percent in certain oil and natural gas production of the Exploration
and Production segment. The weighted average grant date fair value of these stock-settled SARs
granted during the nine months ended June 30, 2009 was estimated on the date of grant using the
same accounting treatment that is applied for stock options under SFAS 123R, and assumes that the
performance conditions specified will be achieved. If such conditions are not met or it is not
considered probable that such conditions will be met, no compensation expense is recognized and any
previously recognized compensation expense is reversed.
There were no stock options or restricted share awards (non-vested stock as defined in SFAS
123R) granted during the quarter and nine months ended June 30, 2009.
-14-
Item 1. Financial Statements (Cont.)
New Accounting Pronouncements. In September 2006, the FASB issued SFAS 157, Fair Value
Measurements. SFAS 157 provides guidance for using fair value to measure assets and liabilities.
The pronouncement serves to clarify the extent to which companies measure assets and liabilities at
fair value, the information used to measure fair value, and the effect that fair-value measurements
have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or
liabilities to be measured at fair value. In accordance with FASB Staff Position FAS No. 157-2, on
October 1, 2008, the Company adopted SFAS 157 for financial assets and financial liabilities that
are recognized or disclosed at fair value on a recurring basis. The same FASB Staff Position
delays the effective date for nonfinancial assets and nonfinancial liabilities, except for items
that are recognized or disclosed at fair value on a recurring basis, until the Companys first
quarter of fiscal 2010. For further discussion of the impact of the adoption of SFAS 157 for
financial assets and financial liabilities, refer to Note 2 Fair Value Measurements. The Company
is currently evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and
nonfinancial liabilities will have on its consolidated financial statements. The Company has
identified Goodwill as being the major nonfinancial asset that may be impacted by the adoption of
SFAS 157. The Company does not believe there are any nonfinancial liabilities that will be
impacted by the adoption of SFAS 157.
In September 2006, the FASB issued SFAS 158, Employers Accounting for Defined Benefit
Pension and Other Postretirement Plans (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS
132R). SFAS 158 requires that companies recognize a net liability or asset to report the
underfunded or overfunded status of their defined benefit pension and other post-retirement benefit
plans on their balance sheets, as well as recognize changes in the funded status of a defined
benefit post-retirement plan in the year in which the changes occur through comprehensive income.
The pronouncement also specifies that a plans assets and obligations that determine its funded
status be measured as of the end of the Companys fiscal year, with limited exceptions. In
accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and
implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to
measure the plan assets and benefit obligations as of the Companys fiscal year-end date will be
fully adopted by the Company by the end of fiscal 2009. The Company has historically measured its
plan assets and benefit obligations using a June 30th measurement date. In anticipation of
changing to a September 30th measurement date, the Company will be recording fifteen months of
pension and other post-retirement benefit costs during fiscal 2009. In accordance with the
provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data.
Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension
and other post-retirement benefit costs for that period amounted to $5.1 million and have been
recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to
Other Regulatory Assets in the Companys Utility and Pipeline and Storage segments and a $1.3
million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further
discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Note 9
Retirement Plan and Other Post-Retirement Benefits.
In December 2007, the FASB issued SFAS 141R, Business Combinations. SFAS 141R will
significantly change the accounting for business combinations in a number of areas including the
treatment of contingent consideration, contingencies, acquisition costs, in process research and
development and restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset
valuation allowances and acquired income tax uncertainties in a business combination after the
measurement period will impact income tax expense. SFAS 141R is effective as of the Companys
first quarter of fiscal 2010.
In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated
Financial Statements, an Amendment of ARB 51. SFAS 160 will change the accounting and reporting
for minority interests, which will be recharacterized as noncontrolling interests (NCI) and
classified as a component of equity. This new consolidation method will significantly change the accounting
for transactions with minority interest holders. SFAS 160 is effective as of the Companys first
quarter of fiscal 2010. The Company currently does not have any NCI.
-15-
Item 1. Financial Statements (Cont.)
In March 2008, the FASB issued SFAS 161, Disclosures about Derivative Instruments and Hedging
Activities, an Amendment of SFAS 133. SFAS 161 requires entities to provide enhanced disclosures
related to an entitys derivative instruments and hedging activities in order to enable investors
to better understand how derivative instruments and hedging activities impact an entitys financial
reporting. The additional disclosures include how and why an entity uses derivative instruments,
how derivative instruments and related hedged items are accounted for under SFAS 133 and its
related interpretations, and how derivative instruments and related hedged items affect an entitys
financial position, financial performance, and cash flows. The Company adopted the disclosure
provisions of SFAS 161 during the quarter ended March 31, 2009. These disclosures may be found at
Note 3 Financial Instruments.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting.
The final rule modifies the SECs reporting and disclosure rules for oil and gas reserves and
aligns the full cost accounting rules with the revised disclosures. The most notable changes of
the final rule include the replacement of the single day period-end pricing to value oil and gas
reserves to a 12-month average of the first day of the month price for each month within the
reporting period. The final rule also permits voluntary disclosure of probable and possible
reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure
requirements are effective for the Companys Form 10-K for the period ended September 30, 2010.
Early adoption is not permitted. The Company is currently evaluating the impact that adoption of
these rules will have on its consolidated financial statements and MD&A disclosures.
Effective April 1, 2009, the Company adopted FASB Staff Position FAS 107-1 and APB 28-1,
Interim Disclosures about Fair Value of Financial Instruments. This FASB Staff Position amends
SFAS 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about
fair value of financial instruments for interim reporting periods of publicly traded companies as
well as in annual financial statements. Refer to Note 3 Financial Instruments under Long-Term
Debt for additional disclosures included in accordance with this FASB Staff Position.
Effective with this June 30, 2009 Form 10-Q, the Company adopted SFAS 165, Subsequent
Events. SFAS 165 establishes general standards of accounting for and disclosure of events that
occur after the balance sheet date but before financial statements are issued or are available to
be issued. Refer to Note 10 Subsequent Events for disclosures made as a result of the adoption
of SFAS 165.
In June 2009, the FASB issued SFAS 168, The FASB Accounting Standards CodificationTM
and the Hierarchy of Generally Accepted Accounting Principles a replacement of FASB
Statement No. 162. SFAS 168 establishes the FASB Accounting Standards CodificationTM
(the Codification) as the source of authoritative GAAP recognized by the FASB to be applied
by all nongovernmental entities in the preparation of financial statements in conformity with GAAP.
Rules and interpretive releases of the SEC under authority of federal securities law are also
sources of authoritative GAAP for SEC registrants. All other nongrandfathered, non-SEC accounting
literature not included in the Codification will become nonauthoritative. SFAS 168 is effective
for interim and annual periods ending after September 15, 2009. The Company will update its
disclosures to conform to the Codification in its annual report on Form 10-K for the year ending
September 30, 2009. There will be no impact on the Companys consolidated financial statements as
the Codification does not change or alter existing GAAP.
Note 2 Fair Value Measurements
Beginning in fiscal 2009, the Company adopted the provisions of SFAS 157, Fair Value
Measurements. SFAS 157 establishes a fair-value hierarchy, which 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
-16-
Item 1. Financial Statements (Cont.)
may affect the valuation of fair value assets and liabilities and their placement within the fair
value hierarchy levels. The adoption of SFAS 157 has not had a significant impact on the
consolidated financial statements.
The following table sets forth, by level within the fair value hierarchy, the Companys
financial assets and liabilities that were accounted for at fair value on a recurring basis as of
June 30, 2009. As required by SFAS 157, 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 June 30, 2009 |
(Dollars in thousands) |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Equivalents |
|
$ |
412,255 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
412,255 |
|
Derivative Financial Instruments |
|
|
|
|
|
|
31,647 |
|
|
|
34,546 |
|
|
|
66,193 |
|
Other Investments |
|
|
19,691 |
|
|
|
|
|
|
|
|
|
|
|
19,691 |
|
Hedging Collateral Deposits |
|
|
6,359 |
|
|
|
|
|
|
|
|
|
|
|
6,359 |
|
|
|
|
Total |
|
$ |
438,305 |
|
|
$ |
31,647 |
|
|
$ |
34,546 |
|
|
$ |
504,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments |
|
$ |
1,815 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,815 |
|
|
|
|
Total |
|
$ |
1,815 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,815 |
|
|
|
|
Cash Equivalents
The cash equivalents reported in Level 1 consist of SEC registered money market mutual funds.
Derivative Financial Instruments
The derivative financial instruments reported in Level 1 consist of NYMEX futures contracts.
The hedging collateral deposits associated with these futures contracts have been reported in Level
1 as well. The derivative financial instruments reported in Level 2 consist of natural gas swap
agreements used in the Companys Exploration and Production segment and natural gas swap agreements
used in the Energy Marketing segment. The fair value of these natural gas swap agreements is based
on an internal model that uses observable inputs. The fair market value of the price swap
agreements reported in Level 2 as assets has been reduced by $0.6 million based on an assessment of
counterparty credit risk. The derivative financial instruments reported in Level 3 consist of all
of the Exploration and Production segments crude oil swap agreements and some of its natural gas
swap agreements. The fair value of the crude oil and natural gas swap agreements is based on an
internal model that uses both observable and unobservable inputs. The fair market value of the
price swap agreements reported in Level 3 as assets has been reduced by $0.7 million based on an
assessment of counterparty credit risk. This credit reserve, as well as the credit reserve
established for the Level 2 swap agreement assets, was 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.
Other Investments
The other investments reported in Level 1 consist of publicly traded equity securities and a
publicly traded balanced equity mutual fund.
The table listed below provides a reconciliation of the beginning and ending net balances for
assets and liabilities measured at fair value and classified as Level 3.
-17-
Item 1. Financial Statements (Cont.)
Fair Value Measurements Using Unobservable Inputs (Level 3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gains/Losses |
|
|
|
|
|
|
|
|
|
|
Realized and Unrealized |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in Other |
|
|
|
|
|
|
October 1, |
|
Included in |
|
Comprehensive |
|
Transfer In/(Out) |
|
|
(Dollars in thousands) |
|
2008 |
|
Earnings |
|
Income |
|
of Level 3 |
|
June 30, 2009 |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments |
|
$ |
7,110 |
|
|
$ |
(37,339 |
)(1) |
|
$ |
73,267 |
|
|
$ |
(8,492 |
) |
|
$ |
34,546 |
|
Total |
|
$ |
7,110 |
|
|
$ |
(37,339 |
) |
|
$ |
73,267 |
|
|
$ |
(8,492 |
) |
|
$ |
34,546 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Financial Instruments |
|
$ |
(777 |
) |
|
$ |
(12,104 |
)(1) |
|
$ |
12,881 |
|
|
$ |
|
|
|
$ |
|
|
Total |
|
$ |
(777 |
) |
|
$ |
(12,104 |
) |
|
$ |
12,881 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
(1) |
|
Amounts are reported in Operating Revenues in the Consolidated Statement of Income
for the nine months ended June 30, 2009. |
Note 3 Financial Instruments
Long-Term Debt. In accordance with the Companys adoption of FASB Staff Position FAS 107-1 and APB
28-1 Disclosures about Fair Value of Financial Instruments, the fair value of the Companys
long-term debt, including current portion, and the carrying amount is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
September 30, 2008 |
|
|
Carrying |
|
|
|
|
|
Carrying |
|
|
|
|
Amount |
|
Fair Value |
|
Amount |
|
Fair Value |
Long-Term Debt |
|
$ |
1,249,000 |
|
|
$ |
1,285,890 |
|
|
$ |
1,099,000 |
|
|
$ |
1,027,098 |
|
At September 30, 2008, the fair market value of the Companys long-term debt was determined
based on quoted market prices of similar issues having the same remaining maturities, redemption
terms and credit rating. At June 30, 2009, the fair market value of the Companys debt, as
presented in the table above, was determined using a discounted cash flow model, which incorporates
the Companys credit risk in determining the yield, and subsequently, the fair market value of the
debt.
Other Investments. 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 $53.5 million at June 30, 2009 and
$53.6 million at September 30, 2008. The fair value of the equity mutual fund was $12.6 million at
June 30, 2009 and $12.4 million at September 30, 2008. The gross unrealized loss on this equity
mutual fund was $2.7 million at June 30, 2009 and $1.1 million at September 30, 2008. Although
this investment has been in an unrealized loss position for twelve months, management has the
intent and ability to hold the investment for a sufficient period of time for the asset to recover
in value. As such, management does not consider this investment to be other than temporarily
impaired. The fair value of the stock of an insurance company was $6.9 million at June 30, 2009
and $14.5 million at September 30, 2008. The gross unrealized gain on this stock was $4.5 million
at June 30, 2009 and $12.1 million at September 30, 2008. The insurance contracts and marketable equity securities are primarily informal funding
mechanisms for various benefit obligations the Company has to certain employees.
-18-
Item 1. Financial Statements (Cont.)
Derivative Financial Instruments. The Company is exposed to certain risks relating to its ongoing
business operations. The primary risk managed by using derivative instruments is 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,
and withdrawal of gas from storage to meet customer demand. The duration of the Companys hedges
do not typically exceed 3 years and the majority of the positions settle within one year.
In accordance with the adoption of SFAS 161, Disclosures about Derivative Instruments and
Hedging Activities, an Amendment of SFAS 133, the Company has presented its gross derivative
assets and liabilities in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Values of Derivative Instruments |
|
|
(Dollar Amounts in Thousands) |
Derivatives |
|
Asset Derivatives |
|
Liability Derivatives |
Designated as |
|
June 30, 2009 |
|
June 30, 2009 |
Hedging |
|
Consolidated |
|
|
|
|
|
Consolidated |
|
|
Instruments |
|
Balance |
|
|
|
|
|
Balance |
|
|
under |
|
Sheet |
|
|
|
|
|
Sheet |
|
|
SFAS 133 |
|
Location |
|
Fair Value |
|
Location |
|
Fair Value |
Commodity Contracts |
|
Fair Value of |
|
$ |
66,193 |
(1) |
|
Fair Value of |
|
$ |
1,815 |
(2) |
|
|
Derivative |
|
|
|
|
|
Derivative |
|
|
|
|
|
|
Financial |
|
|
|
|
|
Financial |
|
|
|
|
|
|
Instruments |
|
|
|
|
|
Instruments |
|
|
|
|
|
|
|
(1) |
|
Agrees to the sum of Level 2 and Level 3 Derivative Financial Instrument Assets shown in Note 2, Fair Value
Measurements. |
|
(2) |
|
Agrees to the Level 1 Derivative Financial Instrument Liabilities shown in Note 2, Fair Value Measurements. |
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 and reclassified into earnings in the same 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 June 30, 2009, 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
|
|
20.7 Bcf (all short positions) |
Crude Oil
|
|
2,199,000 Bbls (all short positions) |
-19-
Item 1. Financial Statements (Cont.)
As of June 30, 2009, 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
|
|
7.0 Bcf (5.5 Bcf short positions (forecasted storage withdrawals) and 1.5 Bcf
long positions (forecasted storage injections)) |
As of June 30, 2009, the Companys Exploration and Production segment had $63.6 million ($37.6
million after tax) of gains included in the accumulated other comprehensive income balance. It is
expected that $51.4 million ($30.4 million after tax) of these gains will be reclassified into
income within the next 12 months as the sales of the underlying commodities are expected to occur.
See Note 1, under Accumulated Other Comprehensive Income, for the after-tax gain pertaining to
derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1
includes both the Exploration and Production and Energy Marketing segments).
As of June 30, 2009, the Companys Energy Marketing segment had $2.8 million ($1.7 million
after tax) of losses included in the accumulated other comprehensive income balance. It is
expected that $2.8 million ($1.7 million after tax) of these losses will be reclassified into
income within the next 12 months as the sales and purchases of the underlying commodities occur.
See Note 1, under Accumulated Other Comprehensive Income, for the after-tax gain pertaining to
derivative financial instruments (Net Unrealized Gain on Derivative Financial Instruments in Note 1
includes both the Exploration and Production and Energy Marketing segments).
-20-
Item 1. Financial Statements (Cont.)
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2009 (Dollar Amounts in Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of |
|
|
|
|
|
|
Amount of |
|
|
|
|
|
|
|
|
|
|
Derivative Gain or |
|
|
|
|
|
|
Derivative Gain or |
|
|
|
|
|
|
|
|
|
|
(Loss) Recognized |
|
|
Location of |
|
|
(Loss) Reclassfied |
|
|
|
|
|
|
Derivative Gain or |
|
|
|
in Other |
|
|
Derivative Gain or |
|
|
from Accumulated |
|
|
Location of |
|
|
(Loss) Recognized |
|
|
|
Comprehensive |
|
|
(Loss) Reclassified |
|
|
Other Comprehensive |
|
|
Derivative Gain or |
|
|
in the Consolidated |
|
|
|
Income on the |
|
|
from Accumulated |
|
|
Income on the |
|
|
(Loss) Recognized |
|
|
Statement of Income |
|
|
|
Consolidated |
|
|
Other Comprehensive |
|
|
Consolidated |
|
|
in the Consolidated |
|
|
(Ineffective |
|
|
|
Statement of |
|
|
Income on the |
|
|
Balance Sheet into |
|
|
Statement of Income |
|
|
Portion and Amount |
|
|
|
Comprehensive |
|
|
Consolidated |
|
|
the Consolidated |
|
|
(Ineffective |
|
|
Excluded from |
|
Derivatives in SFAS |
|
Income (Effective |
|
|
Balance Sheet into |
|
|
Statement of Income |
|
|
Portion and Amount |
|
|
Effectiveness |
|
133 Cash Flow |
|
Portion) for the |
|
|
the Consolidated |
|
|
(Effective Portion) |
|
|
Excluded from |
|
|
Testing) for the |
|
Hedging |
|
Nine Months Ended |
|
|
Statement of Income |
|
|
for the Nine Months |
|
|
Effectiveness |
|
|
Nine Months Ended |
|
Relationships |
|
June 30, 2009 |
|
|
(Effective Portion) |
|
|
Ended June 30, 2009 |
|
|
Testing) |
|
|
June 30, 2009 |
|
Commodity Contracts
Exploration &
Production segment |
|
$ |
117,764 |
|
|
Operating Revenue |
|
$ |
71,324 |
|
|
Operating Revenue |
|
$ |
424 |
|
Commodity Contracts
Energy Marketing
segment |
|
$ |
9,410 |
|
|
Purchased Gas |
|
$ |
21,328 |
|
|
Operating Revenue |
|
$ |
|
|
Commodity Contracts
Pipeline &
Storage segment
(1) |
|
$ |
|
|
|
Operating Revenue |
|
$ |
1,290 |
|
|
Operating Revenue |
|
$ |
|
|
Commodity Contracts
All Other
(1) |
|
$ |
183 |
|
|
Purchased Gas |
|
$ |
(682 |
) |
|
Purchased Gas |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
127,357 |
|
|
|
|
|
|
$ |
93,260 |
|
|
|
|
|
|
$ |
424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
There were no open hedging positions at June 30, 2009. As such there is no mention of these positions in the preceding sections
of this footnote. |
Fair value hedges
The Companys Energy Marketing segment is the only segment which utilizes fair value hedges to
mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and
commitments related to the injection and withdrawal of storage gas. In order to hedge fixed
price sales commitments, the Company enters into long positions to mitigate the risk that after the
Company locks into fixed price sales agreements with its customers, the price of natural gas
increases (thereby passing up the opportunity for higher operating revenue). With fixed price
purchase commitments, the risk is that
-21-
Item 1. Financial Statements (Cont.)
after the Company locks into fixed price purchase deals with its suppliers, the price of natural
gas decreases (thereby passing up the opportunity for lower purchased gas expense). Fair value
hedges related to the injection and withdrawal of storage gas impact purchased gas expense. As of
June 30, 2009, the Companys Energy Marketing segment had fair value hedges covering approximately
13.4 Bcf (11.6 Bcf of fixed price sales commitments (all long positions), 1.3 Bcf of fixed price
purchase commitments (all short positions), and 0.5 Bcf of commitments related to the withdrawal of
storage gas (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 |
|
$ |
(1,395,680 |
) |
|
$ |
1,395,680 |
|
Purchased Gas |
|
$ |
(5,985,069 |
) |
|
$ |
5,985,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Derivative Gain or |
|
|
|
|
|
|
|
(Loss) Recognized in the |
|
|
|
Location of Derivative Gain |
|
|
Consolidated Statement of |
|
Derivatives in SFAS 133 |
|
or (Loss) Recognized in the |
|
|
Income for the Nine Months |
|
Fair Value Hedging |
|
Consolidated Statement of |
|
|
Ended June 30, 2009 |
|
Relationships |
|
Income |
|
|
(In Thousands) |
|
Commodity Contracts Energy
Marketing segment
(1) |
|
Operating Revenues |
|
$ |
(1,396 |
) |
Commodity Contracts Energy
Marketing segment
(2) |
|
Purchased Gas |
|
$ |
2,221 |
|
Commodity Contracts Energy
Marketing segment
(3) |
|
Purchased Gas |
|
$ |
(8,206 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(7,381 |
) |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents hedging of fixed price sales commitments of natural gas. |
|
(2) |
|
Represents hedging of fixed price purchase commitments of natural gas. |
|
(3) |
|
Represents hedging of storage withdrawal commitments of natural gas. |
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 ten
counterparties. The Company has $32.0 million of credit exposure with one counterparty. On
average, the Company has $3.8 million of credit exposure per counterparty with the other nine
counterparties (the Company has not received any collateral from these nine counterparties).
As of June 30, 2009, eight of the ten 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 (the lower of the S&P or Moodys Debt Rating), 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 credit or treasury debt instruments). If the
Companys outstanding derivative instrument contracts were in a liability position and the Companys credit rating declined,
then additional hedging collateral deposits would be required. At June 30, 2009, these credit-risk
related contingency features would not have been triggered since the Company had assets of $57.6
million related to derivative financial instruments with the eight counterparties.
-22-
Item 1. Financial Statements (Cont.)
For its exchange traded futures contracts, which are in a liability position, the Company had
paid $6.4 million in hedging collateral as of June 30, 2009. 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 (i.e. those positions that have been settled for cash)
and margin requirements. (This is discussed in Note 1 under Hedging Collateral Deposits.)
Note 4 Income Taxes
The components of federal, state and foreign income taxes included in the Consolidated
Statements of Income are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
June 30, |
|
|
2009 |
|
2008 |
Current Income Taxes |
|
|
|
|
|
|
|
|
Federal |
|
$ |
95,526 |
|
|
$ |
92,384 |
|
State |
|
|
25,528 |
|
|
|
23,388 |
|
Foreign |
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
Deferred Income Taxes |
|
|
|
|
|
|
|
|
Federal |
|
|
(67,051 |
) |
|
|
18,906 |
|
State |
|
|
(18,443 |
) |
|
|
8,697 |
|
|
|
|
|
|
|
35,560 |
|
|
|
143,465 |
|
Deferred Investment Tax Credit |
|
|
(523 |
) |
|
|
(523 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
35,037 |
|
|
$ |
142,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Other Income |
|
$ |
(523 |
) |
|
$ |
(523 |
) |
Income Tax Expense |
|
|
35,560 |
|
|
|
143,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
35,037 |
|
|
$ |
142,942 |
|
|
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
June 30, |
|
|
2009 |
|
2008 |
U.S. Income Before Income Taxes |
|
$ |
108,747 |
|
|
$ |
368,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Tax Expense, Computed at Federal
Statutory Rate of 35% |
|
$ |
38,061 |
|
|
$ |
128,942 |
|
|
|
|
|
|
|
|
|
|
Increase (Reduction) in Taxes Resulting From: |
|
|
|
|
|
|
|
|
State Income Taxes |
|
|
4,605 |
|
|
|
20,855 |
|
Domestic Production Activities Deduction |
|
|
(1,790 |
) |
|
|
(1,878 |
) |
Miscellaneous |
|
|
(5,839 |
) |
|
|
(4,977 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Income Taxes |
|
$ |
35,037 |
|
|
$ |
142,942 |
|
|
|
|
-23-
Item 1. Financial Statements (Cont.)
Significant components of the Companys deferred tax liabilities and assets are as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2009 |
|
At September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities: |
|
|
|
|
|
|
|
|
Property, Plant and Equipment |
|
$ |
628,785 |
|
|
$ |
673,313 |
|
Pension and Other Post-Retirement Benefit
Costs SFAS 158 |
|
|
44,345 |
|
|
|
43,340 |
|
Unrealized Hedging Gains |
|
|
25,564 |
|
|
|
14,936 |
|
Other |
|
|
25,238 |
|
|
|
40,455 |
|
|
|
|
Total Deferred Tax Liabilities |
|
|
723,932 |
|
|
|
772,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Tax Assets: |
|
|
|
|
|
|
|
|
Pension and Other Post-Retirement Benefit
Costs SFAS 158 |
|
|
(44,345 |
) |
|
|
(43,340 |
) |
Medicare Subsidy |
|
|
(29,084 |
) |
|
|
(23,709 |
) |
Other |
|
|
(94,132 |
) |
|
|
(68,752 |
) |
|
|
|
Total Deferred Tax Assets |
|
|
(167,561 |
) |
|
|
(135,801 |
) |
|
|
|
Total Net Deferred Income Taxes |
|
$ |
556,371 |
|
|
$ |
636,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Presented as Follows: |
|
|
|
|
|
|
|
|
Net Deferred Tax Liability/(Asset) Current |
|
$ |
(33,009 |
) |
|
$ |
1,871 |
|
Net Deferred Tax Liability Non-Current |
|
|
589,380 |
|
|
|
634,372 |
|
|
|
|
Total Net Deferred Income Taxes |
|
$ |
556,371 |
|
|
$ |
636,243 |
|
|
|
|
Regulatory liabilities representing the reduction of previously recorded deferred income taxes
with rate-regulated activities that are expected to be refundable to customers amounted to $18.5
million and $18.4 million at June 30, 2009 and September 30, 2008, respectively. 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 $83.5
million and $82.5 million at June 30, 2009 and September 30, 2008, 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 2009 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 2006
and later years, IRS examinations for fiscal 2008 and prior years have been completed and the
Company believes such years are effectively settled.
The Company is also subject to various routine state income tax examinations. The Companys
operating subsidiaries mainly operate 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.
As of June 30, 2009, the Company does not have any unrecognized tax benefits.
Note 5 Capitalization
Common Stock. During the nine months ended June 30, 2009, the Company issued 1,054,814 original
issue shares of common stock as a result of stock option exercises. The Company also issued 7,000
original issue shares of common stock to the seven non-employee directors of the Company who
receive compensation under the Companys Retainer Policy for Non-Employee Directors, as partial
consideration for the directors services during the nine months ended June 30, 2009.
Holders of stock options or
-24-
Item 1. Financial Statements (Cont.)
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 nine months ended June 30, 2009,
300,876 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.
Shareholder Rights Plan. In 1996, the Companys Board of Directors adopted a shareholder rights
plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an
Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as
an exhibit to the Form 8-K filed by the Company on December 4, 2008.
Pursuant to the Plan, the holders of the Companys common stock have one right (Right) for
each of their shares. Each Right is initially evidenced by the Companys common stock certificates
representing the outstanding shares of common stock.
The Rights have anti-takeover effects because they will cause substantial dilution of the
Companys common stock if a person attempts to acquire the Company on terms not approved by the
Board of Directors (an Acquiring Person).
The Rights become exercisable upon the occurrence of a Distribution Date as described below,
but after a Distribution Date Rights that are owned by an Acquiring Person will be null and void.
At any time following a Distribution Date, each holder of a Right may exercise its right to
receive, upon payment of an amount calculated under the Rights Agreement, common stock of the
Company (or, under certain circumstances, other securities or assets of the Company) having a value
equal to two times the amount paid to exercise the Right. However, the Rights are subject to
redemption or exchange by the Company prior to their exercise as described below.
A Distribution Date would occur upon the earlier of (i) ten days after the public announcement
that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the
Companys common stock or other voting stock (including Synthetic Long Positions as defined in the
Plan) having 10% or more of the total voting power of the Companys common stock and other voting
stock and (ii) ten days after the commencement or announcement by a person or group of an intention
to make a tender or exchange offer that would result in that person acquiring, or obtaining the
right to acquire, beneficial ownership of the Companys common stock or other voting stock having
10% or more of the total voting power of the Companys common stock and other voting stock.
In certain situations after a person or group has acquired beneficial ownership of 10% or more
of the total voting power of the Companys stock as described above, each holder of a Right will
have the right to exercise its Rights to receive, upon exercise of the right, common stock of the
acquiring company having a value equal to two times the amount paid to exercise the right. These
situations would arise if the Company is acquired in a merger or other business combination or if
50% or more of the Companys assets or earning power are sold or transferred.
At any time prior to the end of the business day on the tenth day following the Distribution
Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right,
payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Companys
full Board of Directors. Also, at any time following the Distribution Date, 75% of the Companys
full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate
of one share of common stock, or other property deemed to have the same value, per Right, subject
to certain adjustments.
Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy
the requirements of the Rights Agreement. The Rights will expire on July 31, 2018, unless earlier
than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration
date.
-25-
Item 1. Financial Statements (Cont.)
Long-Term Debt. In April 2009, the Company issued $250.0 million of 8.75% notes due in May 2019.
After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to
$247.8 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 to replenish cash that was used to pay the $100 million due
at the maturity of the Companys 6.0% medium-term notes on March 1, 2009.
Note 6 Commitments 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.
As disclosed in Note H of the Companys 2008 Form 10-K, the Company has agreed with the NYDEC
to remediate a former manufactured gas plant site located in New York. The Company has received
approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated
minimum liability for remediation of this site of $16.0 million.
At June 30, 2009, 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 $19.0 million to $23.2
million. The minimum estimated liability of $19.0 million, which includes the $16.0 million
discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2009. The Company
expects to recover its environmental clean-up costs from a combination of rate recovery and
deferred insurance proceeds that are currently recorded as a regulatory liability on the
Consolidated Balance Sheet.
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, or have a material adverse effect on the financial condition of the Company.
-26-
Item 1. Financial Statements (Cont.)
Note 7 Business Segment Information
In the Companys 2008 Form 10-K, the Company reported financial results for five business
segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing and Timber.
The division of the Companys operations into the reported segments is based upon a combination of
factors including differences in products and services, regulatory environment and geographic
factors. During the quarter ended December 31, 2008, management made the decision to eliminate the
Timber segment as a reportable segment based on the fact that the Timber operations do not meet any
of the quantitative thresholds specified by SFAS 131. Furthermore, from a qualitative standpoint,
managements focus has changed regarding the Timber operations. While the Timber segment will
continue to harvest hardwood timber and process lumber products that are used in high-end
furniture, cabinetry and flooring, management no longer considers the Timber operations to be
integral to the overall operations of the Company. As a result of this change in focus and the
fact that the Timber operations cannot be aggregated into one of the other four reportable business
segments, the Timber operations have been included in the All Other category in the disclosures
that follow. Prior year segment information shown below has been restated to reflect this change
in presentation. In addition, refer to the Companys Form 8-K filed on March 17, 2009 that updated
its historical business segment information contained in the Companys 2008 Form 10-K to reflect
the change in reportable segments.
The data presented in the tables below reflect the reportable segments and reconciliations to
consolidated amounts. As stated in the 2008 Form 10-K, the Company evaluates segment performance
based on income before discontinued operations, extraordinary items and cumulative effects of
changes in accounting (where 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, other than as noted above, nor in the basis of measuring segment profit or loss from
those used in the Companys 2008 Form 10-K.
-27-
Item 1. Financial Statements (Cont.)
Quarter Ended June 30, 2009 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
and |
|
and |
|
Energy |
|
Total Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
External Customers |
|
$ |
158,310 |
|
|
$ |
30,791 |
|
|
$ |
97,619 |
|
|
$ |
71,894 |
|
|
$ |
358,614 |
|
|
$ |
8,269 |
|
|
$ |
228 |
|
|
$ |
367,111 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
2,940 |
|
|
$ |
20,033 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
22,973 |
|
|
$ |
374 |
|
|
$ |
(23,347 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
5,396 |
|
|
$ |
9,221 |
|
|
$ |
27,083 |
|
|
$ |
1,331 |
|
|
$ |
43,031 |
|
|
$ |
(1,086 |
) |
|
$ |
959 |
|
|
$ |
42,904 |
|
Nine Months Ended June 30, 2009 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
and |
|
and |
|
Energy |
|
Total Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
External Customers |
|
$ |
1,009,962 |
|
|
$ |
105,904 |
|
|
$ |
281,410 |
|
|
$ |
350,445 |
|
|
$ |
1,747,721 |
|
|
$ |
30,523 |
|
|
$ |
675 |
|
|
$ |
1,778,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
13,339 |
|
|
$ |
62,026 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
75,365 |
|
|
$ |
3,890 |
|
|
$ |
(79,255 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
60,303 |
|
|
$ |
41,582 |
|
|
$ |
(38,366 |
) |
|
$ |
7,509 |
|
|
$ |
71,028 |
|
|
$ |
(46 |
) |
|
$ |
2,728 |
|
|
$ |
73,710 |
|
Quarter Ended June 30, 2008 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
and |
|
and |
|
Energy |
|
Total Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
External Customers |
|
$ |
217,339 |
|
|
$ |
32,054 |
|
|
$ |
126,154 |
|
|
$ |
162,129 |
|
|
$ |
537,676 |
|
|
$ |
10,509 |
|
|
$ |
197 |
|
|
$ |
548,382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
3,154 |
|
|
$ |
20,131 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
23,285 |
|
|
$ |
4,439 |
|
|
$ |
(27,724 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
7,848 |
|
|
$ |
12,534 |
|
|
$ |
39,791 |
|
|
$ |
478 |
|
|
$ |
60,651 |
|
|
$ |
(960 |
) |
|
$ |
164 |
|
|
$ |
59,855 |
|
Nine Months Ended June 30, 2008 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
and |
|
and |
|
Energy |
|
Total Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from
External Customers |
|
$ |
1,067,194 |
|
|
$ |
101,871 |
|
|
$ |
348,829 |
|
|
$ |
440,111 |
|
|
$ |
1,958,005 |
|
|
$ |
44,002 |
|
|
$ |
496 |
|
|
$ |
2,002,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment Revenues |
|
$ |
13,567 |
|
|
$ |
61,340 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
74,907 |
|
|
$ |
10,251 |
|
|
$ |
(85,158 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Profit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
62,228 |
|
|
$ |
40,931 |
|
|
$ |
108,385 |
|
|
$ |
7,079 |
|
|
$ |
218,623 |
|
|
$ |
7,351 |
|
|
$ |
(511 |
) |
|
$ |
225,463 |
|
At June 30, 2009 (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline |
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and |
|
|
|
|
|
|
|
|
And |
|
and |
|
Energy |
|
Total Reportable |
|
|
|
|
|
Intersegment |
|
Total |
|
|
Utility |
|
Storage |
|
Production |
|
Marketing |
|
Segments |
|
All Other |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment Assets |
|
$ |
1,775,953 |
|
|
$ |
1,003,362 |
|
|
$ |
1,257,131 |
|
|
$ |
61,653 |
|
|
$ |
4,098,099 |
|
|
$ |
208,069 |
|
|
$ |
49,134 |
|
|
$ |
4,355,302 |
|
-28-
Item 1. Financial Statements (Cont.)
Note 8 Intangible Assets
The components of the Companys intangible assets were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2009 |
|
|
At September 30, 2008 |
|
|
|
Gross |
|
|
|
|
|
|
Net |
|
|
Net |
|
|
|
Carrying |
|
|
Accumulated |
|
|
Carrying |
|
|
Carrying |
|
|
|
Amount |
|
|
Amortization |
|
|
Amount |
|
|
Amount |
|
|
|
|
|
|
|
|
Intangible Assets Subject to Amortization: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Transportation Contracts |
|
$ |
4,701 |
|
|
$ |
(2,531 |
) |
|
$ |
2,170 |
|
|
$ |
2,522 |
|
Long-Term Gas Purchase Contracts |
|
|
31,864 |
|
|
|
(9,407 |
) |
|
|
22,457 |
|
|
|
23,652 |
|
|
|
|
|
|
|
|
|
|
$ |
36,565 |
|
|
$ |
(11,938 |
) |
|
$ |
24,627 |
|
|
$ |
26,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate Amortization Expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2009 |
|
$ |
497 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008 |
|
$ |
666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2009 |
|
$ |
1,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, 2008 |
|
$ |
1,997 |
|
|
|
|
|
|
|
|
|
|
|
|
|
In October 2008, the Company completed the amortization of intangible assets related to two
long-term transportation contracts. As such, the gross carrying amount of intangible assets
subject to amortization was reduced from $8.6 million at September 30, 2008 to $4.7 million at June
30, 2009. Aside from this change, the only activity with regard to intangible assets subject to
amortization was amortization expense as shown in the table above. Amortization expense for the
long-term transportation contracts is estimated to be $0.1 million for the remainder of 2009 and
$0.4 million annually for 2010, 2011, 2012 and 2013. Amortization expense for the long-term gas
purchase contracts is estimated to be $0.4 million for the remainder of 2009 and $1.6 million
annually for 2010, 2011, 2012 and 2013.
Note 9 Retirement Plan and Other Post-Retirement Benefits
Components of Net Periodic Benefit Cost (in thousands):
Three months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Cost |
|
$ |
2,728 |
|
|
$ |
3,149 |
|
|
$ |
950 |
|
|
$ |
1,276 |
|
Interest Cost |
|
|
11,709 |
|
|
|
11,237 |
|
|
|
6,875 |
|
|
|
6,770 |
|
Expected Return on Plan Assets |
|
|
(14,489 |
) |
|
|
(13,750 |
) |
|
|
(7,904 |
) |
|
|
(8,428 |
) |
Amortization of Prior Service Cost |
|
|
183 |
|
|
|
202 |
|
|
|
(268 |
) |
|
|
1 |
|
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
566 |
|
|
|
1,782 |
|
Amortization of Losses |
|
|
1,419 |
|
|
|
2,766 |
|
|
|
2,318 |
|
|
|
732 |
|
Net Amortization and Deferral for
Regulatory Purposes (Including
Volumetric Adjustments) (1) |
|
|
2,255 |
|
|
|
783 |
|
|
|
3,878 |
|
|
|
4,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
3,805 |
|
|
$ |
4,387 |
|
|
$ |
6,415 |
|
|
$ |
6,487 |
|
|
|
|
|
|
-29-
Item 1. Financial Statements (Cont.)
Nine months ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement Plan |
|
Other Post-Retirement Benefits |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service Cost |
|
$ |
8,185 |
|
|
$ |
9,448 |
|
|
$ |
2,851 |
|
|
$ |
3,828 |
|
Interest Cost |
|
|
35,127 |
|
|
|
33,712 |
|
|
|
20,624 |
|
|
|
20,311 |
|
Expected Return on Plan Assets |
|
|
(43,468 |
) |
|
|
(41,250 |
) |
|
|
(23,711 |
) |
|
|
(25,286 |
) |
Amortization of Prior Service Cost |
|
|
548 |
|
|
|
606 |
|
|
|
(805 |
) |
|
|
3 |
|
Amortization of Transition Amount |
|
|
|
|
|
|
|
|
|
|
1,699 |
|
|
|
5,346 |
|
Amortization of Losses |
|
|
4,257 |
|
|
|
8,298 |
|
|
|
6,953 |
|
|
|
2,195 |
|
Net Amortization and Deferral for
Regulatory Purposes (Including
Volumetric Adjustments) (1) |
|
|
12,853 |
|
|
|
7,597 |
|
|
|
16,232 |
|
|
|
20,028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost |
|
$ |
17,502 |
|
|
$ |
18,411 |
|
|
$ |
23,843 |
|
|
$ |
26,425 |
|
|
|
|
|
|
|
|
|
(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. |
As indicated under New Accounting Pronouncements in Note 1 Summary of Significant
Accounting Policies, in accordance with the measurement date provisions of SFAS 158 that specifies
that a plans assets and obligations that determine its funded status be measured as of the end of
the Companys fiscal year, the Company will be recording fifteen months of pension and other
post-retirement benefit costs during fiscal 2009. As allowed by SFAS 158, these costs have been
calculated using June 30, 2008 measurement date data. Three of those months pertain to the period
of July 1, 2008 to September 30, 2008. The pension and other post-retirement benefit costs for
that period amounted to $3.8 million and have been recorded by the Company during the nine months
ended June 30, 2009 as a $3.4 million increase to Other Regulatory Assets in the Companys Utility
and Pipeline and Storage segments and a $0.4 million ($0.2 million after tax) adjustment to
earnings reinvested in the business. In addition, for the Companys non-qualified pension plan,
benefit costs of $1.3 million have been recorded by the Company during the nine months ended June
30, 2009 as a $0.4 million increase to Other Regulatory Assets in the Companys Utility segment and
a $0.9 million ($0.6 million after tax) adjustment to earnings reinvested in the business. The
requirement to measure the plan assets and benefit obligations as of the Companys fiscal year-end
date will be fully adopted by the Company by the end of fiscal 2009.
Employer Contributions. During the nine months ended June 30, 2009, the Company contributed $16.0
million to its retirement plan and $21.5 million to its VEBA trusts and 401(h) accounts for its
other post-retirement benefits. In the remainder of 2009, the Company does not expect to
contribute to its retirement plan. As a result of the recent downturn in the stock markets and
general economic conditions, it is expected that the Company will fund in the range of $20 million
to $40 million to the retirement plan subsequent to fiscal 2009. In the remainder of 2009, the
Company expects to contribute approximately $5.0 million to its VEBA trusts and 401(h) accounts.
Note 10 Subsequent Events
In accordance with SFAS 165, Subsequent Events, the Company has evaluated subsequent events
through August 7, 2009, which represents the filing date of this Form 10-Q with the SEC, in order
to ensure that this Form 10-Q includes appropriate disclosure of events both recognized in the
financial statements as of June 30, 2009, and events which occurred subsequent to June 30, 2009 but
were not recognized in the financial statements. As of August 7, 2009, there were no subsequent
events which required recognition or disclosure other than as set forth below.
-30-
Item 1. Financial Statements (Concl.)
On July 20, 2009, the Company announced that in its Exploration and Production segment, Seneca
had purchased Ivanhoe Energys United States oil and gas operations for approximately $39.2
million, of which $2 million was placed in escrow as a deposit for the acquisition as of June 30,
2009. As of June 2009, these assets produced approximately 645 (595 net) barrels per day of oil in
California and Texas. The purchase also included certain exploration acreage in California. This
acquisition adds to the Companys existing oil producing assets in the Midway Sunset Field in
California.
-31-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of
Operations
OVERVIEW
The Company is a diversified energy company consisting of four reportable business segments.
For the quarter ended June 30, 2009 compared to the quarter ended June 30, 2008, the Company
experienced a decrease in earnings of $17.0 million, primarily due to lower earnings in the
Exploration and Production segment. For the nine months ended June 30, 2009 compared to the nine
months ended June 30, 2008, the Company experienced a decrease in earnings of $151.8 million. The
earnings decrease for the nine-month period was driven largely by an impairment charge of $182.8
million ($108.2 million after tax) recorded in the Exploration and Production segment. 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. Such costs are subject
to a quarterly ceiling test prescribed by SEC Regulation S-X Rule 4-10 that determines a limit, or
ceiling, on the amount of property acquisition, exploration and development costs that can be
capitalized. At December 31, 2008, due to significant declines in crude oil and natural gas
commodity prices (Cushing, Oklahoma West Texas Intermediate oil reported spot price of $44.60 per
Bbl at December 31, 2008 versus a reported price of $100.70 per Bbl at September 30, 2008; Henry
Hub natural gas reported spot price of $5.63 per MMBtu at December 31, 2008 versus a reported price
of $7.12 per MMBtu at September 30, 2008), the book value of the Companys oil and gas properties
exceeded the ceiling, resulting in the impairment charge mentioned above. (Note Because actual
pricing of the Companys various producing properties varies depending on their location, the
actual various prices received for such production is utilized to calculate the ceiling, rather
than the Cushing oil and Henry Hub prices, which are only indicative of current prices.) At June
30, 2009, the quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $69.82 per
Bbl ($49.64 per Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.88 per
MMBtu ($3.63 per MMBtu at March 31, 2009). At June 30, 2009, the ceiling exceeded the book value
of the Companys oil and gas properties by approximately $247 million (and approximately $37
million at March 31, 2009). If natural gas prices used in the ceiling test calculation at June 30,
2009 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Companys
oil and gas properties by approximately $197 million. If crude oil prices used in the ceiling test
calculation at June 30, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book
value of the Companys oil and gas properties by approximately $196 million. If both natural gas
and crude oil prices used in the ceiling test calculation at June 30, 2009 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 $146 million. These calculated amounts are based solely on
price changes and do not take into account any other changes to the ceiling test calculation.
Despite the decrease in earnings discussed above, the Companys balance sheet consisted of a
capitalization structure of 57% equity and 43% debt at June 30, 2009. With its April 2009 issuance
of $250.0 million of 8.75% notes due in May 2019, management believes that it has enhanced its
liquidity position at a time when there is still uncertainty in the credit markets. In addition to
the proceeds from this debt issuance, the Company has been able to borrow short-term funds under
its credit lines and through the commercial paper market to fund working capital needs throughout
the first nine months of 2009. At June 30, 2009, the Company did not have any short-term
borrowings outstanding. However, the Company continues to maintain a number of individual
uncommitted or discretionary lines of credit with financial institutions for general corporate
purposes. These credit lines, which aggregate to $420.0 million, are revocable at the option of
the financial institutions and are reviewed on an annual basis. The Company anticipates that these
lines of credit will continue to be renewed, or replaced by similar lines. The total amount
available to be issued under the Companys commercial paper program is $300.0 million. The
commercial paper program is backed by a syndicated committed credit facility totaling $300.0
million, which commitment extends through September 30, 2010.
In the Companys Exploration and Production segment, there continues to be a strong focus on
exploring and developing the nearly one million acres of oil and gas rights in the Appalachian
region, including the 720,000 acres in the Marcellus Shale. However, the Company continues to look
for growth opportunities in other areas as well. In July 2009, the Exploration and Production
segment purchased Ivanhoe Energys United States oil and gas operations for approximately $39.2
million. This purchase complements this segments existing oil producing assets in the Midway
Sunset Field in California. This acquisition was funded with cash on hand.
-32-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
The Company, through Midstream Corporation, is pursuing the development of gathering systems
in Tioga County and Lycoming County in Pennsylvania. The project, called the Midstream Covington
Gathering Project, is to be constructed in three phases, with the first phase under construction
and anticipated to be placed in service by the fall of 2009. The second phase is anticipated to be
placed in service by the fall of 2010. The schedule for the final phase is being developed. When
all three phases are complete, the system will consist of approximately 30 miles of gathering
system pipeline at a cost of approximately $25 million to $30 million. Phase I is estimated to
cost approximately $15 million. As of June 30, 2009, the Company has spent approximately $2.8
million in costs on Phase I and Phase II related to this project. The Company has funded these
costs with cash on hand and anticipates that future costs will be funded with cash on hand as well.
CRITICAL ACCOUNTING ESTIMATES
For a complete discussion of critical accounting estimates, refer to Critical Accounting
Estimates in Item 7 of the Companys 2008 Form 10-K and Item 2 of the Companys December 31, 2008
and March 31, 2009 Form 10-Qs. There have been no material changes to those disclosures other than
as set forth below. The information presented below updates and should be read in conjunction with
the critical accounting estimates in those documents.
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 current market prices (the ceiling) is compared with the
book value of those reserves at the balance sheet date. If the book value of the reserves in any
country exceeds the ceiling, a non-cash charge must be recorded to reduce the book value of the
reserves to the calculated ceiling. As disclosed in the Companys 2008 Form 10-K, at September 30,
2008, the ceiling exceeded the book value of the Companys oil and gas properties by approximately
$500 million. Because of declines in commodity prices since September 30, 2008, the book value of
the Companys oil and gas properties exceeded the ceiling at December 31, 2008. The quoted
Cushing, Oklahoma spot price for West Texas Intermediate oil had declined from a reported price of
$100.70 per Bbl at September 30, 2008 to a reported price of $44.60 per Bbl at December 31, 2008.
The quoted Henry Hub spot price for natural gas had declined from a reported price of $7.12 per
MMBtu at September 30, 2008 to a reported price of $5.63 per MMBtu at December 31, 2008.
Consequently, the Company recorded an impairment charge of $182.8 million ($108.2 million
after-tax) during the quarter ended December 31, 2008. (Note Because actual pricing of the
Companys various producing properties varies depending on their location, the actual various
prices received for such production is utilized to calculate the ceiling, rather than the Cushing
oil and Henry Hub prices, which are only indicative of current prices.) At June 30, 2009, the
quoted Cushing, Oklahoma spot price for West Texas Intermediate oil was $69.82 per Bbl ($49.64 per
Bbl at March 31, 2009) and the quoted spot price for natural gas was $3.88 per MMBtu ($3.63 per
MMBtu at March 31, 2009). At June 30, 2009, the ceiling exceeded the book value of the Companys
oil and gas properties by approximately $247 million (and approximately $37 million at March 31,
2009). If natural gas prices used in the ceiling test calculation at June 30, 2009 had been $1 per
MMBtu lower, the ceiling would have exceeded the book value of the Companys oil and gas properties
by approximately $197 million. If crude oil prices used in the ceiling test calculation at June
30, 2009 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Companys
oil and gas properties by approximately $196 million. If both natural gas and crude oil prices
used in the ceiling test calculation at June 30, 2009 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 $146 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 2008 Form 10-K.
-33-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
RESULTS OF OPERATIONS
Earnings
The Companys earnings were $42.9 million for the quarter ended June 30, 2009 compared to
earnings of $59.9 million for the quarter ended June 30, 2008. The decrease in earnings of $17.0
million is primarily the result of lower earnings in the Exploration and Production segment. The
Utility and Pipeline and Storage segments, as well as the All Other category also contributed to
the decrease in earnings. Higher earnings in the Energy Marketing segment and the Corporate
category slightly offset these decreases.
The Companys earnings were $73.7 million for the nine months ended June 30, 2009 compared to
earnings of $225.5 million for the nine months ended June 30, 2008. The decrease in earnings of
$151.8 million is primarily the result of lower earnings in the Exploration and Production segment.
The Utility segment and the All Other category also contributed to the decrease in earnings.
Higher earnings in the Pipeline and Storage and Energy Marketing segments, as well as the Corporate
category, slightly offset these decreases. The Companys earnings for the nine months ended June
30, 2009 include a non-cash $182.8 million impairment charge ($108.2 million after tax) recorded
during the quarter ended December 31, 2008 for the Exploration and Production segments oil and gas
producing properties.
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 |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
(Thousands) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Utility |
|
$ |
5,396 |
|
|
$ |
7,848 |
|
|
$ |
(2,452 |
) |
|
$ |
60,303 |
|
|
$ |
62,228 |
|
|
$ |
(1,925 |
) |
Pipeline and Storage |
|
|
9,221 |
|
|
|
12,534 |
|
|
|
(3,313 |
) |
|
|
41,582 |
|
|
|
40,931 |
|
|
|
651 |
|
Exploration and Production |
|
|
27,083 |
|
|
|
39,791 |
|
|
|
(12,708 |
) |
|
|
(38,366 |
) |
|
|
108,385 |
|
|
|
(146,751 |
) |
Energy Marketing |
|
|
1,331 |
|
|
|
478 |
|
|
|
853 |
|
|
|
7,509 |
|
|
|
7,079 |
|
|
|
430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reportable Segments |
|
|
43,031 |
|
|
|
60,651 |
|
|
|
(17,620 |
) |
|
|
71,028 |
|
|
|
218,623 |
|
|
|
(147,595 |
) |
All Other |
|
|
(1,086 |
) |
|
|
(960 |
) |
|
|
(126 |
) |
|
|
(46 |
) |
|
|
7,351 |
|
|
|
(7,397 |
) |
Corporate |
|
|
959 |
|
|
|
164 |
|
|
|
795 |
|
|
|
2,728 |
|
|
|
(511 |
) |
|
|
3,239 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Consolidated |
|
$ |
42,904 |
|
|
$ |
59,855 |
|
|
$ |
(16,951 |
) |
|
$ |
73,710 |
|
|
$ |
225,463 |
|
|
$ |
(151,753 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
Utility Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
(Thousands) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Retail Sales Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
$ |
119,746 |
|
|
$ |
153,058 |
|
|
$ |
(33,312 |
) |
|
$ |
786,170 |
|
|
$ |
793,124 |
|
|
$ |
(6,954 |
) |
Commercial |
|
|
15,627 |
|
|
|
20,459 |
|
|
|
(4,832 |
) |
|
|
122,197 |
|
|
|
124,582 |
|
|
|
(2,385 |
) |
Industrial |
|
|
808 |
|
|
|
1,178 |
|
|
|
(370 |
) |
|
|
6,835 |
|
|
|
6,754 |
|
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
136,181 |
|
|
|
174,695 |
|
|
|
(38,514 |
) |
|
|
915,202 |
|
|
|
924,460 |
|
|
|
(9,258 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation |
|
|
22,012 |
|
|
|
21,584 |
|
|
|
428 |
|
|
|
94,951 |
|
|
|
97,345 |
|
|
|
(2,394 |
) |
Off-System Sales |
|
|
|
|
|
|
20,540 |
|
|
|
(20,540 |
) |
|
|
3,740 |
|
|
|
48,606 |
|
|
|
(44,866 |
) |
Other |
|
|
3,057 |
|
|
|
3,674 |
|
|
|
(617 |
) |
|
|
9,408 |
|
|
|
10,350 |
|
|
|
(942 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
161,250 |
|
|
$ |
220,493 |
|
|
$ |
(59,243 |
) |
|
$ |
1,023,301 |
|
|
$ |
1,080,761 |
|
|
$ |
(57,460 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-34-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Utility Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
June 30, |
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
(MMcf) |
|
2009 |
|
2008 |
|
Decrease |
|
2009 |
|
2008 |
|
(Decrease) |
Retail Sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential |
|
|
8,468 |
|
|
|
8,618 |
|
|
|
(150 |
) |
|
|
55,001 |
|
|
|
53,881 |
|
|
|
1,120 |
|
Commercial |
|
|
1,221 |
|
|
|
1,334 |
|
|
|
(113 |
) |
|
|
8,984 |
|
|
|
9,197 |
|
|
|
(213 |
) |
Industrial |
|
|
55 |
|
|
|
77 |
|
|
|
(22 |
) |
|
|
499 |
|
|
|
524 |
|
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,744 |
|
|
|
10,029 |
|
|
|
(285 |
) |
|
|
64,484 |
|
|
|
63,602 |
|
|
|
882 |
|
Transportation |
|
|
10,747 |
|
|
|
12,086 |
|
|
|
(1,339 |
) |
|
|
52,476 |
|
|
|
55,966 |
|
|
|
(3,490 |
) |
Off-System Sales |
|
|
|
|
|
|
1,711 |
|
|
|
(1,711 |
) |
|
|
513 |
|
|
|
4,790 |
|
|
|
(4,277 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,491 |
|
|
|
23,826 |
|
|
|
(3,335 |
) |
|
|
117,473 |
|
|
|
124,358 |
|
|
|
(6,885 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Degree Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent Colder |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Warmer) Than |
|
|
Normal |
|
2009 |
|
2008 |
|
Normal |
|
Prior Year |
Three Months Ended
June 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Buffalo |
|
|
927 |
|
|
|
854 |
|
|
|
817 |
|
|
|
(7.9 |
) |
|
|
4.5 |
|
Erie |
|
|
885 |
|
|
|
821 |
|
|
|
762 |
|
|
|
(7.2 |
) |
|
|
7.7 |
|
Nine Months Ended
June 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Buffalo |
|
|
6,514 |
|
|
|
6,558 |
|
|
|
6,175 |
|
|
|
0.7 |
|
|
|
6.2 |
|
Erie |
|
|
6,108 |
|
|
|
6,064 |
|
|
|
5,737 |
|
|
|
(0.7 |
) |
|
|
5.7 |
|
2009 Compared with 2008
Operating revenues for the Utility segment decreased $59.2 million for the quarter ended June
30, 2009 as compared with the quarter ended June 30, 2008. The decrease for the quarter is
primarily attributable to a $38.5 million decrease in retail sales revenue and a $20.5 million
decrease in off-system sales revenue. The $38.5 million decrease in retail gas sales revenues was
primarily a function of lower gas costs (subject to certain timing variations, gas costs are
recovered dollar for dollar in revenues). The decrease in off-system sales revenue stems from
Order No. 717 (Final Rule), which was issued by the FERC on October 16, 2008. The Final Rule
seemingly holds that a local distribution company making off-system sales on unaffiliated pipelines
would engage in marketing that would require compliance with the FERCs standards of conduct.
Accordingly, pending clarification of this issue from the FERC, as of November 1, 2008,
Distribution Corporation ceased off-system sales activities.
Operating revenues for the Utility segment decreased $57.5 million for the nine months ended
June 30, 2009 as compared with the nine months ended June 30, 2008. This decrease largely resulted
from a $44.9 million decrease in off-system sales revenue, which is discussed above, a $9.3 million
decrease in retail sales revenue and a $2.4 million decrease in transportation revenues. The
decrease in retail gas sales revenues for the Utility segment was largely a function of lower gas
costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues)
partially offset by higher residential retail sales volumes, as shown in the table above. The
volume increase was primarily the result of weather that was 6.2 percent colder than the prior year
in the New York jurisdiction and 5.7 percent colder than the prior year in the Pennsylvania
jurisdiction. The decrease in transportation revenues was primarily attributable to conservation
efforts and the poor economy.
In the New York jurisdiction, the NYPSC issued an order providing for an annual rate increase
of $1.8 million beginning December 28, 2007. As part of this rate order, a rate design change was
adopted that shifts a greater amount of cost recovery into the minimum bill amount, thus spreading
the recovery of such costs more evenly throughout the year. As a result of this rate
order, retail and transportation
-35-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
revenues for the nine months ended June 30, 2009 were $2.2 million lower than revenues for the nine
months ended June 30, 2008. There was no impact to revenues when comparing the quarters ended June
30, 2009 and June 30, 2008.
The Utility segments earnings for the quarter ended June 30, 2009 were $5.4 million, a
decrease of $2.4 million compared to earnings of $7.8 million for the quarter ended June 30, 2008.
In the New York jurisdiction, earnings decreased by $1.1 million. The decrease was largely due to
higher interest expense ($1.5 million) partially offset by lower operating costs ($0.4 million).
The increase in interest expense stems from the Companys April 2009 debt issuance. This debt was
issued at a significantly higher interest rate than the interest rates on existing debt at the time
of issuance. In the Pennsylvania jurisdiction, earnings decreased by $1.3 million. The decrease
was largely due to higher interest expense ($0.4 million) and lower usage per account ($0.4
million). The phrase usage per account refers to the average gas consumption per customer
account after factoring out any impact that weather may have had on consumption. As with the New
York jurisdiction, the increase in interest expense in the Pennsylvania jurisdiction is
attributable to the Companys April 2009 debt issuance.
The impact of weather variations on earnings in the New York jurisdiction is mitigated by that
jurisdictions weather normalization clause (WNC). The WNC in New York, which covers the
eight-month period from October through May, has had a stabilizing effect on earnings for the New
York jurisdiction. For both the quarter ended June 30, 2009 and June 30, 2008, the WNC preserved
earnings of approximately $0.4 million, as weather was warmer than normal for those periods.
The Utility segments earnings for the nine months ended June 30, 2009 were $60.3 million, a
decrease of $1.9 million when compared with earnings of $62.2 million for the nine months ended
June 30, 2008. In the New York jurisdiction, earnings decreased $0.5 million. The earnings impact
of the December 28, 2007 rate order discussed above ($1.4 million), higher interest expense ($1.1
million) and regulatory true-up adjustments ($0.5 million) were the main factors in the earnings
decrease. These factors were offset by a $3.0 million decrease in operating costs (primarily due
to a decrease in other post-retirement benefit costs as well as a decrease in health insurance and
prescription drug costs). The reason for the increase in interest costs is attributable to the
April 2009 debt issuance, as discussed above. In the Pennsylvania jurisdiction, earnings decreased
$1.4 million. The negative earnings impact associated with lower usage per account ($1.9 million),
higher income tax expense ($1.4 million) and higher operating costs of $1.3 million (primarily bad
debt expense due to the possible impact current economic conditions may have on customers) was
largely offset by the positive earnings impact of colder weather ($2.0 million) and lower interest
expense ($0.5 million).
For the nine months ended June 30, 2009, the WNC reduced earnings by approximately $0.2
million, as the weather was colder than normal. For the nine months ended June 30, 2008, the WNC
preserved earnings of approximately $2.5 million, as the weather was warmer than normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
(Thousands) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Firm Transportation |
|
$ |
32,894 |
|
|
$ |
29,020 |
|
|
$ |
3,874 |
|
|
$ |
105,931 |
|
|
$ |
93,427 |
|
|
$ |
12,504 |
|
Interruptible Transportation |
|
|
635 |
|
|
|
1,151 |
|
|
|
(516 |
) |
|
|
2,862 |
|
|
|
3,237 |
|
|
|
(375 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,529 |
|
|
|
30,171 |
|
|
|
3,358 |
|
|
|
108,793 |
|
|
|
96,664 |
|
|
|
12,129 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Firm Storage Service |
|
|
16,648 |
|
|
|
16,754 |
|
|
|
(106 |
) |
|
|
50,101 |
|
|
|
50,311 |
|
|
|
(210 |
) |
Interruptible Storage Service |
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
|
18 |
|
|
|
14 |
|
|
|
4 |
|
Other |
|
|
643 |
|
|
|
5,260 |
|
|
|
(4,617 |
) |
|
|
9,018 |
|
|
|
16,222 |
|
|
|
(7,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
50,824 |
|
|
$ |
52,185 |
|
|
$ |
(1,361 |
) |
|
$ |
167,930 |
|
|
$ |
163,211 |
|
|
$ |
4,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-36-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Pipeline and Storage Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
June 30, |
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
(MMcf) |
|
2009 |
|
2008 |
|
Decrease |
|
2009 |
|
2008 |
|
(Decrease) |
Firm Transportation |
|
|
60,798 |
|
|
|
68,263 |
|
|
|
(7,465 |
) |
|
|
305,001 |
|
|
|
283,104 |
|
|
|
21,897 |
|
Interruptible Transportation |
|
|
501 |
|
|
|
1,540 |
|
|
|
(1,039 |
) |
|
|
3,558 |
|
|
|
3,844 |
|
|
|
(286 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61,299 |
|
|
|
69,803 |
|
|
|
(8,504 |
) |
|
|
308,559 |
|
|
|
286,948 |
|
|
|
21,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 Compared with 2008
Operating revenues for the Pipeline and Storage segment decreased $1.4 million for the quarter
ended June 30, 2009 as compared with the quarter ended June 30, 2008. The decrease was primarily
due to decreased efficiency gas revenues ($3.9 million) reported as part of other revenues in the
table above. This decrease was primarily due to lower gas prices and lower transportation volumes
during the quarter ended June 30, 2009 as compared with the quarter ended June 30, 2008. Under
Supply Corporations tariff with suppliers, Supply Corporation is allowed to retain a set
percentage of shipper-supplied gas to cover compressor fuel costs and 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 customers. The
excess gas that is retained as inventory represents efficiency gas revenue to Supply Corporation.
The decrease in efficiency gas revenues was partially offset by an increase in transportation
revenues ($3.4 million) due to higher revenues from the Empire Connector, which was placed in
service in December 2008, combined with higher reservation, commodity, and surcharge revenues
associated with new contracts for transportation service. While transportation volumes decreased
during the quarter, volume fluctuations generally do not have a significant impact on revenues as a
result of the straight fixed-variable rate design used by both Supply Corporation and Empire.
Operating revenues for the nine months ended June 30, 2009 increased $4.7 million as compared
with the nine months ended June 30, 2008. The increase was primarily due to a $12.1 million
increase in transportation revenue primarily due to higher revenues from the Empire Connector and
new contracts for transportation service. Partially offsetting this increase, efficiency gas
revenues decreased $6.7 million due primarily to lower gas prices in the nine months ended June 30,
2009 as compared with the nine months ended June 30, 2008.
The Pipeline and Storage segments earnings for the quarter ended June 30, 2009 were $9.2
million, a decrease of $3.3 million when compared to earnings of $12.5 million for the quarter
ended June 30, 2008. The earnings decrease was primarily due to lower efficiency gas revenues
($2.5 million), as discussed above. Higher interest expense ($1.4 million) and a decrease in the
allowance for funds used during construction ($0.9 million) also contributed to the earnings
decrease. The decreases were partially offset by the earnings impact associated with higher transportation revenues ($2.2
million). The increase in interest expense can be attributed to higher debt balances and a higher
average interest rate on borrowings. The increase in the average interest rate stems from the
Companys April 2009 debt issuance. The decrease in the allowance for funds used during
construction can be attributed to the completion of the Empire Connector in December 2008.
The Pipeline and Storage segments earnings for the nine months ended June 30, 2009 were $41.6
million, an increase of $0.7 million when compared to earnings of $40.9 million for the nine months
ended June 30, 2008. The increase was primarily due to the earnings impact associated with an
increase in transportation revenues ($7.9 million), as discussed above. In addition, increased
earnings resulted from an increase in the allowance for funds used during construction ($0.7
million) and higher interest income ($0.1 million). The increase in the allowance for funds used
during construction reflects the fact that construction work in progress balances for the Empire
Connector were significantly higher during the quarter ended December 31, 2008 than they were
during the nine months ended June 30, 2008. While construction of the Empire Connector began in
September 2007, winter weather limited significant construction until the spring and summer of
2008. These factors, which increased earnings, were largely
-37-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
offset by a decrease in efficiency gas revenues ($4.4 million), higher interest expense ($3.1
million), and higher depreciation expense ($1.2 million). The increase in interest expense can be
attributed to higher debt balances and a higher average interest rate on borrowings. The increase
in the average interest rate stems from the Companys April 2009 debt issuance. The increase in
depreciation expense can be attributed primarily to a revision of accumulated depreciation combined
with the increased depreciation associated with placing the Empire Connector in service in December
2008.
Exploration and Production
Exploration and Production Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
(Thousands) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Gas (after Hedging) |
|
$ |
38,450 |
|
|
$ |
56,591 |
|
|
$ |
(18,141 |
) |
|
$ |
118,345 |
|
|
$ |
155,793 |
|
|
$ |
(37,448 |
) |
Oil (after Hedging) |
|
|
56,690 |
|
|
|
66,695 |
|
|
|
(10,005 |
) |
|
|
156,340 |
|
|
|
185,650 |
|
|
|
(29,310 |
) |
Gas Processing Plant |
|
|
5,380 |
|
|
|
13,566 |
|
|
|
(8,186 |
) |
|
|
18,785 |
|
|
|
35,674 |
|
|
|
(16,889 |
) |
Other |
|
|
270 |
|
|
|
(291 |
) |
|
|
561 |
|
|
|
717 |
|
|
|
(3,174 |
) |
|
|
3,891 |
|
Intrasegment Elimination (1) |
|
|
(3,171 |
) |
|
|
(10,407 |
) |
|
|
7,236 |
|
|
|
(12,777 |
) |
|
|
(25,114 |
) |
|
|
12,337 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
97,619 |
|
|
$ |
126,154 |
|
|
$ |
(28,535 |
) |
|
$ |
281,410 |
|
|
$ |
348,829 |
|
|
$ |
(67,419 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents the elimination of certain West Coast gas production 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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
June 30, |
|
June 30, |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
Increase/ |
Production Volumes |
|
2009 |
|
2008 |
|
(Decrease) |
|
2009 |
|
2008 |
|
(Decrease) |
Gas Production (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
3,307 |
|
|
|
3,019 |
|
|
|
288 |
|
|
|
7,118 |
|
|
|
8,868 |
|
|
|
(1,750 |
) |
West Coast |
|
|
1,014 |
|
|
|
1,007 |
|
|
|
7 |
|
|
|
3,063 |
|
|
|
3,010 |
|
|
|
53 |
|
Appalachia |
|
|
2,155 |
|
|
|
1,793 |
|
|
|
362 |
|
|
|
6,065 |
|
|
|
5,538 |
|
|
|
527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
6,476 |
|
|
|
5,819 |
|
|
|
657 |
|
|
|
16,246 |
|
|
|
17,416 |
|
|
|
(1,170 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Production (Mbbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
|
176 |
|
|
|
124 |
|
|
|
52 |
|
|
|
470 |
|
|
|
409 |
|
|
|
61 |
|
West Coast |
|
|
654 |
|
|
|
598 |
|
|
|
56 |
|
|
|
1,984 |
|
|
|
1,825 |
|
|
|
159 |
|
Appalachia |
|
|
14 |
|
|
|
23 |
|
|
|
(9 |
) |
|
|
41 |
|
|
|
88 |
|
|
|
(47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Production |
|
|
844 |
|
|
|
745 |
|
|
|
99 |
|
|
|
2,495 |
|
|
|
2,322 |
|
|
|
173 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-38-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Average Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
Decrease |
|
|
2009 |
|
|
2008 |
|
|
Decrease |
|
Average Gas Price/Mcf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
3.95 |
|
|
$ |
12.17 |
|
|
$ |
(8.22 |
) |
|
$ |
4.90 |
|
|
$ |
9.66 |
|
|
$ |
(4.76 |
) |
West Coast |
|
$ |
3.04 |
|
|
$ |
10.61 |
|
|
$ |
(7.57 |
) |
|
$ |
4.10 |
|
|
$ |
8.43 |
|
|
$ |
(4.33 |
) |
Appalachia |
|
$ |
4.11 |
|
|
$ |
11.53 |
|
|
$ |
(7.42 |
) |
|
$ |
6.06 |
|
|
$ |
9.25 |
|
|
$ |
(3.19 |
) |
Weighted Average |
|
$ |
3.86 |
|
|
$ |
11.71 |
|
|
$ |
(7.85 |
) |
|
$ |
5.18 |
|
|
$ |
9.32 |
|
|
$ |
(4.14 |
) |
Weighted Average
After Hedging |
|
$ |
5.94 |
|
|
$ |
9.73 |
|
|
$ |
(3.79 |
) |
|
$ |
7.28 |
|
|
$ |
8.95 |
|
|
$ |
(1.67 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Oil Price/Bbl |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf Coast |
|
$ |
56.29 |
|
|
$ |
124.43 |
|
|
$ |
(68.14 |
) |
|
$ |
50.64 |
|
|
$ |
103.46 |
|
|
$ |
(52.82 |
) |
West Coast |
|
$ |
55.77 |
|
|
$ |
114.35 |
|
|
$ |
(58.58 |
) |
|
$ |
46.84 |
|
|
$ |
94.64 |
|
|
$ |
(47.80 |
) |
Appalachia |
|
$ |
48.93 |
|
|
$ |
114.99 |
|
|
$ |
(66.06 |
) |
|
$ |
54.90 |
|
|
$ |
94.18 |
|
|
$ |
(39.28 |
) |
Weighted Average |
|
$ |
55.77 |
|
|
$ |
116.05 |
|
|
$ |
(60.28 |
) |
|
$ |
47.69 |
|
|
$ |
96.17 |
|
|
$ |
(48.48 |
) |
Weighted Average
After Hedging |
|
$ |
67.19 |
|
|
$ |
89.55 |
|
|
$ |
(22.36 |
) |
|
$ |
62.67 |
|
|
$ |
79.97 |
|
|
$ |
(17.30 |
) |
2009 Compared with 2008
Operating revenues for the Exploration and Production segment decreased $28.5 million for the
quarter ended June 30, 2009 as compared with the quarter ended June 30, 2008. Gas production
revenue after hedging decreased $18.1 million. This decrease is due to a decrease in the weighted
average price of gas after hedging ($3.79 per Mcf), partially offset by an increase in gas
production of 657 MMcf. The increase in gas production occurred partially in this segments
Appalachian region (362 MMcf) as a result of additional wells drilled throughout fiscal 2008 that
came on line in 2009. The Gulf Coast region also experienced an increase in gas production (288
MMcf). Production from a new field (Cyclops) that started producing at the end of March 2009 was
responsible for the increase, partly offset by declines in production from some existing fields,
quarter to quarter. Oil production revenue after hedging decreased $10.0 million due to a $22.36
per Bbl decline in weighted average prices of oil after hedging. This decrease was partially
offset by an increase in production in the Gulf Coast and West Coast regions of this segment. The
increase in crude oil production in the Gulf Coast region of 52 Mbbl is due to production from a
new field in the High Island area. In the West Coast region, increased production at the Midway
Sunset field is responsible for the increase in crude oil production of 56 Mbbl in this region.
Operating revenues for the Exploration and Production segment decreased $67.4 million for the
nine months ended June 30, 2009 as compared with the nine months ended June 30, 2008. Gas
production revenue after hedging decreased $37.4 million due to a decline in the weighted average
price of gas after hedging ($1.67 per Mcf) as well as a decrease in gas production of 1,170 MMcf.
The decrease in gas production occurred in the Gulf Coast region (1,750 MMcf) as a result of
lingering shut-ins caused by Hurricane Ike in September 2008. While Senecas properties sustained
only superficial damage from the hurricanes, two significant producing properties were shut-in for
a significant portion of the current fiscal year due to repair work on third party pipelines and
onshore processing facilities. One of the properties was back on line by March 31, 2009 and the
other property was back on line by the end of April 2009. Partly offsetting the decrease in gas
production in the Gulf Coast region was an increase in gas production in the Appalachian region of
527 MMcf as a result of additional wells drilled throughout fiscal 2008 that came on line in 2009.
Oil production revenue after hedging decreased $29.3 million due primarily to a $17.30 per Bbl
decrease in weighted average prices of oil after hedging, partially offset by an increase in
production in the West Coast and Gulf Coast regions.
The Exploration and Production segments earnings for the quarter ended June 30, 2009 were
$27.1 million, a decrease of $12.7 million when compared with earnings of $39.8 million for the
quarter ended June 30, 2008. Lower natural gas prices and crude oil prices decreased earnings by
$15.9 million and $12.3 million, respectively, while higher crude oil production and natural gas
production increased earnings by $5.8 million and $4.2 million, respectively. Lower interest
income of $1.3 million due to lower
-39-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
interest rates also contributed to the decline in earnings. Lower lease operating expenses of $2.8
million, lower interest expense of $1.7 million, and the earnings impact associated with a lower
effective tax rate ($2.4 million) somewhat offset the decline in earnings. The decrease in lease
operating expenses is primarily due to a reduction in steam fuel costs in the West Coast region and
a decline in marine fuel costs and production taxes as well as lower expenses due to the sale of
five properties during fiscal 2009, all in the Gulf Coast region. The decrease in interest expense
is primarily due to a lower average amount of debt outstanding.
The Exploration and Production segments loss for the nine months ended June 30, 2009 was
$38.4 million, compared with earnings of $108.4 million for the nine months ended June 30, 2008, a
decrease of $146.8 million. The decrease in earnings is primarily the result of an impairment
charge of $108.2 million, as discussed above. In addition, lower crude oil prices, lower natural
gas prices and lower natural gas production contributed to the decrease in earnings by $28.0
million, $17.5 million and $6.8 million, respectively, while higher crude oil production increased
earnings by $9.0 million. Higher operating costs of $3.0 million and lower interest income of $4.6
million also contributed to the decrease in earnings. The increase in operating costs is primarily
due to an increase in bad debt expense as a result of a customers bankruptcy filing, and higher
personnel costs in the Appalachian and Gulf Coast regions. The decline in interest income is due
to lower interest rates and lower temporary cash investment balances. Slightly offsetting these
earnings decreases were lower interest expense ($4.7 million), lower lease operating expenses ($3.1
million), lower depletion expense ($1.9 million) and lower state income tax expense ($3.2 million).
The decline in interest expense is primarily due to a lower average amount of debt outstanding.
The decrease in lease operating expenses is primarily due to a reduction in steam fuel costs in the
West Coast region and a decline in well servicing workover expenses and production taxes in the
Gulf Coast region. The decrease in depletion is primarily due to a lower full cost pool balance
after the impairment charge taken during the quarter ended December 31, 2008.
Energy Marketing
Energy Marketing Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
|
|
|
|
|
|
|
|
|
Increase/ |
|
(Thousands) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (after Hedging) |
|
$ |
71,870 |
|
|
$ |
162,127 |
|
|
$ |
(90,257 |
) |
|
$ |
350,331 |
|
|
$ |
440,123 |
|
|
$ |
(89,792 |
) |
Other |
|
|
24 |
|
|
|
2 |
|
|
|
22 |
|
|
|
114 |
|
|
|
(12 |
) |
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
71,894 |
|
|
$ |
162,129 |
|
|
$ |
(90,235 |
) |
|
$ |
350,445 |
|
|
$ |
440,111 |
|
|
$ |
(89,666 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy Marketing Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
Decrease |
|
2009 |
|
2008 |
|
Increase |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf) |
|
|
14,634 |
|
|
|
14,641 |
|
|
|
(7 |
) |
|
|
50,459 |
|
|
|
47,189 |
|
|
|
3,270 |
|
2009 Compared with 2008
Operating revenues for the Energy Marketing segment decreased $90.2 million and $89.7 million,
respectively, for the quarter and nine months ended June 30, 2009 as compared with the quarter and
nine months ended June 30, 2008. The decrease for both the quarter and nine months ended June 30,
2009 is primarily due to lower gas sales revenue due to a lower average price of natural gas that
was recovered through revenues. For the nine months ended June 30, 2009 as compared to the nine
months ended June 30, 2008, this decline was somewhat offset by an increase in volumes sold. The
increase in volumes is largely attributable to colder weather as well as sales transactions
undertaken to offset certain
-40-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
basis risk that the Energy Marketing segment was exposed to under certain commodity purchase
contracts. These offsetting transactions had the effect of increasing revenue and volumes sold with
minimal impact to earnings.
Earnings in the Energy Marketing segment increased $0.9 million and $0.4 million,
respectively, for the quarter and nine months ended June 30, 2009 as compared with the quarter and
nine months ended June 30, 2008. For the quarter ended June 30, 2009, lower operating costs of
$0.6 million, primarily due to a decrease in bad debt expense, as well as higher margins of $0.4
million, are responsible for the increase in earnings. The increase in margins was primarily
driven by lower pipeline transportation fuel costs due to lower natural gas commodity prices. For
the nine months ended June 30, 2009, higher margins of $0.6 million combined with lower operating
costs of $0.4 million (primarily due to a decline in bad debt expense) are responsible for the
increase in earnings. These increases were partially offset by higher income tax expense of $0.4
million for the nine months ended June 30, 2009 as compared to
the nine months ended June 30, 2008.
Corporate and All Other
2009 Compared with 2008
Corporate and All Other recorded losses of $0.1 million and $0.8 million for the quarters
ended June 30, 2009 and June 30, 2008, respectively. The decrease in the loss period over period
was largely due to lower operating costs ($1.1 million). In 2008, the proxy contest with New
Mountain Vantage GP, L.L.C. led to an increase in operating costs, which did not recur in 2009. In
addition, lower income tax expense ($0.8 million), higher margins from log and lumber sales ($0.3
million), and higher interest income ($0.3 million) contributed to the increase in earnings. These
were partially offset by higher interest expense ($0.8 million) due to higher borrowings at a
higher interest rate (mostly due to the $250 million of 8.75% notes that were issued in April
2009). In addition, lower equity method income from Horizon Powers investments in unconsolidated
subsidiaries ($0.6 million) and lower margins from Horizon LFG ($0.5 million) also decreased
earnings.
For the nine months ended June 30, 2009, Corporate and All Other had earnings of $2.7 million
compared with earnings of $6.8 million for the nine months ended June 30, 2008. The decrease in
earnings was largely attributable to lower margins from log and lumber sales ($5.5 million), lower
margins from Horizon LFG ($1.4 million), lower interest income ($1.9 million), lower income from
Horizon Powers investments in unconsolidated subsidiaries ($1.5 million), and higher interest
expense ($1.3 million). The increase in interest expense reflects higher borrowings at a higher
interest rate, as mentioned above. In addition, during the quarter ended December 31, 2008, ESNE,
an unconsolidated subsidiary of Horizon Power, recorded an impairment charge of $3.6 million.
Horizon Powers 50% share of the impairment was $1.8 million ($1.1 million on an after tax basis).
Also, Horizon Power recognized a gain on the sale of a turbine ($0.6 million) during 2008 that did
not recur in 2009. These earnings decreases were partially offset by lower operating costs ($3.7
million). In 2008, the proxy contest with New Mountain Vantage GP, L.L.C. led to an increase in
operating costs, which did not recur in 2009. In addition, lower income tax expense ($3.5 million)
and a gain on life insurance policies held by the Company ($2.3 million) further offset the
earnings decrease.
Interest Income
Interest income was $1.6 million lower in the quarter ended June 30, 2009 as compared to the
quarter ended June 30, 2008. For the nine months ended June 30, 2009, interest income decreased
$4.0 million as compared with the nine months ended June 30, 2008. These decreases are mainly due
to lower interest rates and lower average temporary cash investment balances.
Other Income
Other income decreased $1.0 million for the quarter ended June 30, 2009 as compared with the
quarter ended June 30, 2008. This decrease is attributable to a decrease in the allowance for
funds used during construction of $0.9 million in the Pipeline and Storage segment primarily
associated with the
-41-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Empire Connector project. For the nine months ended June 30, 2009, other income increased $1.5
million as compared with the nine months ended June 30, 2008. This increase is attributable to an
increase in the allowance for funds used during construction of $0.7 million in the Pipeline and
Storage segment primarily associated with the Empire Connector project, as well as a death benefit
gain on life insurance proceeds of $2.3 million recognized in the Corporate category. Offsetting
these increases, as noted above, Horizon Power recognized a pre-tax gain on the sale of a turbine
of $0.9 million during the quarter ended March 31, 2008 that did not recur in 2009.
Interest Expense on Long-Term Debt
Interest expense on long-term debt increased $2.3 million for the quarter ended June 30, 2009
as compared with the quarter ended June 30, 2008. For the nine months ended June 30, 2009,
interest expense on long-term debt increased $5.3 million as compared with the nine months ended
June 30, 2008. The increase is due to a higher average amount of long-term debt outstanding
combined with an overall increase in the weighted average interest rate. In April 2008, the
Company issued $300 million of 6.5% senior, unsecured notes due in April 2018, and in April 2009,
the Company issued $250 million of 8.75% senior, unsecured notes due in May 2019. This increase
was partly offset by the repayment of $200 million of 6.303% medium-term notes that matured in May
2008 and the repayment of $100 million of 6.0% medium-term notes that matured in March 2009.
Other Interest Expense
Other Interest expense increased $1.3 million for the quarter ended June 30, 2009 as compared
to the quarter ended June 30, 2008. For the nine months ended June 30, 2009, other interest
expense increased $0.8 million as compared with the nine months ended June 30, 2008. These
increases are mainly due to higher interest expense on regulatory deferrals (primarily deferred gas
costs) in the Utility segment.
Effective Tax Rate
The effective tax rate of 32.2% for the nine months ended June 30, 2009 is lower than the
effective tax rate of 38.8% for the nine months ended June 30, 2008 due to the reduction in pre-tax
income for the nine months ended June 30, 2009. The reduction in pre-tax income is a result of the
impairment charge recorded during the quarter ended December 31, 2008 in the Exploration and
Production segment.
CAPITAL RESOURCES AND LIQUIDITY
The Companys primary source of cash during the nine-month periods ended June 30, 2009 and
June 30, 2008 consisted of cash provided by operating activities and proceeds from the issuance of
long-term debt. These sources of cash were supplemented by issues of new shares of common stock as
a result of stock option exercises. During the nine months ended June 30, 2009 and June 30, 2008,
the common stock used to fulfill the requirements of the Companys 401(k) plans and Direct Stock
Purchase and Dividend Reinvestment Plan was obtained via open market purchases. During the quarter
and nine months ended June 30, 2008, the Company repurchased outstanding shares of its common stock
under a share repurchase program, which is discussed below under Financing Cash Flow.
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, impairment of oil and
gas producing properties, impairment of investment in partnerships, deferred income taxes, and
income or loss from unconsolidated subsidiaries net of cash distributions.
-42-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
Cash provided by operating activities in the Utility and the Pipeline and Storage segments may
vary from period to period because of the impact of rate cases. In the Utility segment, 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 balances receivable 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. The
Company uses various derivative financial instruments, including price swap agreements, no cost
collars, options and futures contracts in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $511.8 million for the nine months ended
June 30, 2009, an increase of $96.7 million compared with $415.1 million provided by operating
activities for the nine months ended June 30, 2008. The increase is primarily due to the timing of
gas cost recovery in the Utility segment for the nine months ended June 30, 2009 as compared to the
nine months ended June 30, 2008.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Companys expenditures for long-lived assets totaled $230.5 million during the nine months
ended June 30, 2009 and $284.6 million for the nine months ended June 30, 2008. The table below
presents these expenditures:
Total Expenditures for Long-Lived Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended June 30, |
|
|
|
|
|
|
|
|
|
Increase |
|
(Millions) |
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility |
|
$ |
40.4 |
|
|
$ |
38.8 |
|
|
$ |
1.6 |
|
Pipeline and Storage |
|
|
34.8 |
(1) |
|
|
106.2 |
(5) |
|
|
(71.4 |
) |
Exploration and Production |
|
|
151.7 |
(2) |
|
|
140.6 |
|
|
|
11.1 |
|
All Other |
|
|
3.9 |
(3) |
|
|
1.4 |
|
|
|
2.5 |
|
Eliminations |
|
|
(0.3 |
) (4) |
|
|
(2.4 |
)(6) |
|
|
2.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
230.5 |
|
|
$ |
284.6 |
|
|
$ |
(54.1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount for the nine months ended June 30, 2009 excludes $16.8 million of accrued
capital expenditures related to the Empire Connector project accrued at September 30, 2008 and paid
during the nine months ended June 30, 2009. This amount was excluded from the Consolidated
Statement of Cash Flows at September 30, 2008, since it represented a non-cash investing activity
at that date. The amount has been included in the Consolidated Statement of Cash Flows at June 30,
2009. |
-43-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
|
|
|
(2) |
|
Amount for the nine months ended June 30, 2009 includes $9.4 million of
accrued capital expenditures, the majority of which was in the Appalachian region. This amount has
been excluded from the Consolidated Statement of Cash Flows at June 30, 2009 since it represents a
non-cash investing activity at that date. |
|
(3) |
|
Amount includes a $0.8 million capital contribution made by NFG Midstream
Processing, LLC in the Whitetail Processing plant. |
|
(4) |
|
Represents $0.3 million of capital expenditures in the Pipeline and Storage segment
for the purchase of pipeline facilities from the Appalachian region of the Exploration and
Production segment during the quarter ended December 31, 2008. |
|
(5) |
|
Amount includes $19.9 million of accrued capital expenditures related to the
Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash
Flows at June 30, 2008 since it represents a non-cash investing activity at that date. |
|
(6) |
|
Represents $2.4 million of capital expenditures included in the Appalachian region
of the Exploration and Production segment for the purchase of storage facilities, buildings, and
base gas from Supply Corporation during the quarter ended March 31, 2008. |
Utility
The majority of the Utility capital expenditures for the nine months ended June 30, 2009 and
June 30, 2008 were made for replacement of mains and main extensions, as well as for the
replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures for the nine months ended June
30, 2009, and June 30, 2008 were related to the Empire Connector project, which was placed into
service on December 10, 2008, as well as for 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
is actively pursuing development of several expansion projects. The largest, Supply Corporations
Appalachian Lateral pipeline project is expected to be routed through areas in Pennsylvania where
producers are actively drilling and are seeking market access for their newly discovered reserves.
The Appalachian Lateral will complement Supply Corporations original West to East (W2E) project,
which was designed to transport Rockies gas supply from Clarington, Ohio to the
Ellisburg/Leidy/Corning area and includes the Tuscarora-to-Corning facilities previously referred
to as the Tuscarora Extension. The Appalachian Lateral will transport gas supply from
Pennsylvanias producing area to the Overbeck area of Supply Corporations existing system, where
the facilities associated with the W2E project will move the gas to eastern market points,
including Leidy, Pennsylvania, and to interconnections with Millennium and Empire at Corning, New
York. Preliminary engineering routing analysis, project cost estimate and rate design have been
completed, and prospective shippers have been offered precedent agreements for their consideration.
In addition, Supply Corporation is working with the Appalachian producers to develop two
strategic compressor horsepower expansions designed to move attached Marcellus production gas to
off-system markets. The first involves new compression and approximately 3.5 miles of new pipeline
to establish a delivery point from Supply Corporations Line N to Texas Eastern at Texas Easterns
Holbrook Station near Bristoria in southwestern Pennsylvania. This project will allow local (Marcellus)
production located in the vicinity of Line N to flow south and access markets off Texas Easterns
system, with a first phase of service commencing in mid-to-late 2010 and the second phase in late
2011. The second expansion involves the addition of compression at Supply Corporations existing
interconnect with Tennessee Gas Pipeline at Lamont, Pennsylvania, with a projected in-service date
early-to-mid-2010.
In conjunction with the Appalachian Lateral and W2E transportation projects, Supply
Corporation has plans to develop new storage capacity by expanding certain of its existing storage
facilities. The expansion of these fields, which Supply Corporation is pursuing concurrently with
the Appalachian Lateral/W2E transportation projects, could provide approximately 8.5 MMDth of
incremental storage capacity with incremental withdrawal deliverability of up to 121 MDth of
natural gas per day, with service
-44-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
commencing as early as 2012. Supply Corporation expects that the availability of this incremental
storage capacity will complement the Appalachian Lateral/W2E pipeline transportation projects and
help balance the increasing flow of Appalachian and Rockies gas supply into the western
Pennsylvania area, and the growing demand for gas on the east coast.
The timeline associated with all of Supply Corporations pipeline and storage projects will
depend on market development. Supply Corporation has not yet filed an application with the FERC for
the authority to build any of these projects.
The capital cost of the Appalachian Lateral/W2E transportation projects is estimated to be in
the range of $750 million to $1 billion, and is expected to be financed by a combination of debt
and equity. Preliminary cost estimates for the storage expansion,
Bristoria and Lamont projects are
$78 million, $35 million and $6 million, respectively. As of June 30, 2009, approximately $1.0
million has been spent to study the storage expansion project, $0.4 million has been spent to study
the Appalachian Lateral/W2E transportation projects, and lesser amounts have been spent on
preliminary engineering for the Bristoria and Lamont projects. Costs associated with these projects
have been included in preliminary survey and investigation charges and have been fully reserved for
at June 30, 2009.
The Companys Empire Connector project has been in service since December 10, 2008, when
construction of the actual pipeline and compression facilities was completed, with some
right-of-way restoration work remaining to be completed thereafter. During the quarter and nine
months ended June 30, 2009, the Company incurred costs of $0.1 million and $21.9 million,
respectively, on this project. After June 30, 2009, about $5.3 million, amounting to about 2.8% of
the $192 million total project cost, remain to be incurred, almost all of which is expected to be
incurred by the end of September 2009.
Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30,
2009 were primarily well drilling and completion expenditures and included approximately $16.9
million for the Gulf Coast region, substantially all of which was for the off-shore program in the
shallow waters of the Gulf of Mexico, $28.8 million for the West Coast region and $106.0 million
for the Appalachian region. These amounts included approximately $22.0 million spent to develop
proved undeveloped reserves.
In July 2009, the Exploration and Production segment purchased Ivanhoe Energys United States
oil and gas operations for approximately $39.2 million. This purchase complements the segments
existing oil producing assets in the Midway Sunset Field in California. This acquisition was
funded with cash on hand.
The Exploration and Production segment capital expenditures for the nine months ended June 30,
2008 included approximately $46.9 million for the Gulf Coast region, substantially all of which was
for the off-shore program in the shallow waters of the Gulf of Mexico, $51.1 million for the West
Coast region and $42.6 million for the Appalachian region. The Appalachian region capital
expenditures included $2.4 million for the purchase of storage facilities, buildings, and base gas
from Supply Corporation, as shown in the table on the previous page. These amounts included
approximately $20.7 million spent to develop proved undeveloped reserves.
All Other
The majority of the All Other categorys capital expenditures for the nine months ended June
30, 2009 were for the construction of Midstream Corporations Covington Gathering System, as
discussed below. The majority of the All Other categorys capital expenditures for the nine months
ended June 30, 2008 were for construction of a lumber sorter for Highlands sawmill operations as
well as for purchases of equipment for Highlands sawmill and kiln operations.
-45-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, is
constructing a gathering system in Tioga County and Lycoming County in Pennsylvania. The project,
called the Covington Gathering System, is to be constructed in three phases, with the first phase
under construction and anticipated to be placed in service by the fall of 2009. The second phase
is anticipated to be placed in service by the fall of 2010. The schedule for the final phase is
being developed. When all three phases are complete, the system will consist of approximately 30
miles of gathering system at a cost of $25 million to $30 million. As of June 30, 2009, the Company has spent approximately $2.8 million
in costs on Phase I and Phase II related to this project.
NFG Midstream Processing, LLC, another wholly owned subsidiary of Midstream Corporation, has a
35% ownership in the Whitetail Processing Plant. The plant is currently under construction with
completion expected in October 2009. The total project cost is estimated at $4 million. Once
completed, the plant will extract natural gas liquids from local production. As of June 30, 2009,
the Company invested $0.8 million related to the construction of the plant.
The Company anticipates funding the Midstream Corporation projects with cash from operations
and/or short-term borrowings. These expenditures were not included in the estimated capital
expenditures reported in the Companys 2008 Form 10-K.
In March 2008, Horizon Power sold a gas-powered turbine that it had planned to use in the
development of a co-generation plant. Horizon Power received proceeds of $5.3 million and recorded
a pre-tax gain of $0.9 million associated with the sale.
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, timber or 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
The Company did not have any outstanding short-term notes payable to banks or commercial paper
at June 30, 2009. However, 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, and other working capital needs.
Fluctuations in these items can have a significant impact on the amount and timing of short-term
debt. 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
aggregate to $420.0 million, are revocable at the option of the financial institutions and are
reviewed on an annual basis. The Company anticipates that these lines of credit will continue to
be renewed, or replaced by similar lines. The total amount available to be issued under the
Companys commercial paper program is $300.0 million. The commercial paper program is backed by a
syndicated committed credit facility totaling $300.0 million, which commitment extends through
September 30, 2010.
Under the Companys committed credit facility, the Company has agreed that its debt to
capitalization ratio will not exceed .65 at the last day of any fiscal quarter through September
30, 2010. At June 30, 2009, the Companys debt to capitalization ratio (as calculated under the
facility) was .43. The constraints specified in the committed credit facility would permit an
additional $1.78 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
would exceed .65. If a downgrade in any of the
-46-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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 June 30, 2009, the Company would have
been permitted to issue up to a maximum of $495.0 million 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 another impairment
of oil and gas properties this year, it is possible that these indenture covenants would restrict
the Companys ability to issue additional long-term unsecured indebtedness. This would not
preclude the Company from issuing new indebtedness to replace maturing debt.
The Companys 1974 indenture pursuant to which $99.0 million (or 7.9%) of the Companys
long-term debt (as of June 30, 2009) 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 $300.0 million committed credit facility 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 $20.0 million or more or (ii) an event occurs that causes, or
would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such
indebtedness to become due prior to its stated maturity. As of June 30, 2009, the Company had no
debt outstanding under the committed credit facility.
In April 2008, the Company issued $300.0 million of 6.50% senior, unsecured notes in a private
placement exempt from registration under the Securities Act of 1933. In February 2009, the Company
exchanged the notes for economically identical notes registered under the Securities Act of 1933.
The notes have a term of 10 years, with a maturity date in April 2018. 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
Company used $200.0 million of the proceeds of the issuance to refund $200.0 million of 6.303%
medium-term notes that matured on May 27, 2008.
In April 2009, the Company issued $250.0 million of 8.75% notes due in March 2019. After
deducting underwriting discounts and commissions, the net proceeds to the Company amounted to
$247.8 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 to replenish cash that was used to pay the $100 million due
at the maturity of the Companys 6.0% medium-term notes on March 1, 2009. After this debt
issuance, the Companys embedded cost of long-term debt increased from 6.5% to 6.95%. If the
Company were to issue long-term debt today, its borrowing costs might be expected to be in the
range of 7.0% to 8.0% depending on the length of maturity.
-47-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
On December 8, 2005, the Companys Board of Directors authorized the Company to implement a
share repurchase program, whereby the Company could repurchase outstanding shares of common stock,
up to an aggregate amount of 8 million shares in the open market or through privately negotiated
transactions. The Company repurchased 439,722 and 2,832,397 shares for $20.7 million and $129.6
million, respectively, during the quarter and nine months ended June 30, 2008 under this program.
The Company completed the repurchase of the 8 million shares during the last quarter of fiscal
2008. In September 2008, the Companys Board of Directors authorized the repurchase of an
additional 8 million shares of the Companys common stock. The Company, however, stopped
repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit
markets. Such repurchases may resume in the future. The share repurchases mentioned above were
funded with cash provided by operating activities.
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 and capital 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 $27.7 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. The Companys unconsolidated subsidiaries, which
are accounted for under the equity method, have capital leases of electric generating equipment
having a remaining lease commitment of approximately $2.3 million. The Company has guaranteed 50%
or $1.1 million of these capital lease commitments.
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 nine months ended June 30, 2009, the Company contributed $16.0 million to its
retirement plan and $21.5 million to its VEBA trusts and 401(h) accounts for its other
post-retirement benefits. In the remainder of 2009, the Company does not expect to contribute to
its retirement plan. As a result of the recent downturn in the stock markets and general economic
conditions, it is expected that the Company will fund in the range of $20 million to $40 million to
the retirement plan subsequent to fiscal 2009. In the remainder of 2009, the Company expects to
contribute approximately $5.0 million to its VEBA trusts and 401(h) accounts.
Market Risk Sensitive Instruments
Beginning in fiscal 2009, the Company adopted the provisions of SFAS 157. In accordance with
the adoption of SFAS 157, the Company has identified certain inputs used to recognize fair value as
Level 3 (unobservable inputs). The Level 3 derivative assets relate to natural gas and oil swap
agreements used to hedge forecasted sales at specific locations (southern California and the
Texas-Oklahoma border). The Companys internal model that is used to calculate fair value
applies a historical basis
-48-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not
a forward curve specific to these sales locations. Given the high level of historical correlation
between NYMEX prices and prices at these sales locations, the Company does not believe that the
fair values recorded by the Company would be significantly different from what it expects to
receive upon settlement. The fair value of the Level 3 derivative assets was reduced by $0.7
million based upon the Companys assessment of counterparty credit risk. The Company applied
default probabilities to the anticipated cash flows that it was expecting from its counterparties
to calculate the credit reserve. The Company incorporated hedging collateral deposits received
from the counterparties in calculating the credit reserve.
The Level 3 assets amount to $34.5 million at June 30, 2009 and represent 52% of the
Derivative Financial Instruments Assets or 7% of the Total Assets shown in Part I, Item 1 at Note 2
Fair Value Measurements at June 30, 2009.
At June 30, 2009, the Company transferred $9.8 million of derivative assets from Level 3
assets to Level 2 assets. These assets related to the natural gas swaps on southern California
natural gas production. This transfer occurred because the Company was able to obtain and utilize
forward-looking, observable basis differential information for the underlying hedges at this
location. In the prior quarters, the Company utilized historical basis differentials at this
location. Also, at June 30, 2009, the Company transferred $1.3 million of derivative assets from
Level 2 assets to Level 3 assets. These assets related to certain natural gas swaps on Gulf of
Mexico natural gas production. Since the basis differential related to these natural gas swaps
could no longer be considered immaterial and the Company could only utilize historical basis
differential information to estimate the basis differential, these positions were considered Level
3.
The Company uses the natural gas and crude oil swaps to hedge against the risk of declining
commodity prices and not as speculative investments. Gains or losses related to these Level 3
derivative assets (including any reduction for credit risk) are deferred until the hedged commodity
transaction occurs in accordance with the provisions of SFAS 133.
The significant increase in the fair value of the Level 3 assets from October 1, 2008 to June
30, 2009, as shown in Part I, Item 1 at Note 2, was attributable to a significant decrease in the
commodity price of natural gas and crude oil 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 June 30, 2009.
For a complete discussion of market risk sensitive instruments, refer to Market Risk
Sensitive Instruments in Item 7 of the Companys 2008 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
Base rate adjustments in both the New York and Pennsylvania rate jurisdictions do not reflect
the recovery of purchased gas costs. Such costs are recovered through operation of the purchased
gas adjustment clauses of the appropriate regulatory authorities.
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 recover 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 also adopted Distribution Corporations proposed revenue
decoupling mechanism. The revenue decoupling mechanism, like others, decouples revenues from
throughput by enabling the Company to collect from small volume customers its allowed margin
on average weather normalized
-49-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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 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 contends that portions of the rate order should be
invalidated because they fail to meet the applicable legal standard for agency decisions. Among
the issues challenged by the Company are the reasonableness of the NYPSCs disallowance of expense
items and the methodology used for calculating rate of return, which the appeal contends
understated the Companys cost of equity. Briefs have been filed and oral argument is scheduled to
be held in October 2009. The Company cannot predict the outcome of the appeal at this time.
On April 7, 2009, the Governor of the State of New York signed into law an amendment to the
Public Service Law increasing the utility assessment from the current rate of 1/3 of one percent to
one percent of a utilitys in-state gross operating revenue, together with a temporary surcharge
equal, as applied, to an additional one percent of the utilitys gross operating revenue. The
amendment is expected to increase the assessment charged to Distribution Corporations New York
Division, based on the most current calculation, from $2.3 million to approximately $26 million,
all other things being equal. The NYPSC, in a generic proceeding initiated for the purpose of
implementing the amended law, has provided for recovery, through rates, of the full cost of the
increased assessment.
Pennsylvania Jurisdiction
Distribution Corporation currently does not have a rate case on file with the PaPUC.
Distribution Corporations current tariff in its Pennsylvania jurisdiction was last 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 currently does not have a rate case on file with the FERC. The rate
settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general
rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general
rate filing before then, with some exceptions specified in the settlement.
Empires new facilities (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
make a filing at the FERC, within three years after the in-service date, either justifying Empires
existing recourse rates or proposing alternative rates.
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. The Company has received approval from the NYDEC of a Remedial Design work
plan for this site and has recorded an estimated minimum liability for remediation of this site of
$16.0 million.
-50-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
At June 30, 2009, 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 $19.0 million to $23.2
million. The minimum estimated liability of $19.0 million, which includes the $16.0 million
discussed above, has been recorded on the Consolidated Balance Sheet at June 30, 2009. The Company
expects to recover its environmental clean-up costs from a combination of rate recovery and
deferred insurance proceeds that are currently recorded as a regulatory liability on the
Consolidated Balance Sheet.
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.
New Accounting Pronouncements
In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value
to measure assets and liabilities. The pronouncement serves to clarify the extent to which
companies measure assets and liabilities at fair value, the information used to measure fair value,
and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever
another standard requires or allows assets or liabilities to be measured at fair value. In
accordance with FASB Staff Position FAS No. 157-2, on October 1, 2008, the Company adopted
SFAS 157 for financial assets and financial liabilities that are recognized or disclosed at fair
value on a recurring basis. The same FASB Staff Position delays the effective date for
nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed
at fair value on a recurring basis, until the Companys first quarter of fiscal 2010. For further
discussion of the impact of the adoption of SFAS 157 for financial assets and financial
liabilities, refer to Part I, Item 1 at Note 2 Fair Value Measurements. The Company is currently
evaluating the impact that the adoption of SFAS 157 for nonfinancial assets and nonfinancial
liabilities will have on its consolidated financial statements. The Company has identified
Goodwill as being the major nonfinancial asset that may be impacted by the adoption of SFAS 157.
The Company does not believe there are any nonfinancial liabilities that will be impacted by the
adoption of SFAS 157.
In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and
SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the
underfunded or overfunded status of their defined benefit pension and other post-retirement benefit
plans on their balance sheets, as well as recognize changes in the funded status of a defined
benefit post-retirement plan in the year in which the changes occur through comprehensive income.
The pronouncement also specifies that a plans assets and obligations that determine its funded
status be measured as of the end of the Companys fiscal year, with limited exceptions. In
accordance with SFAS 158, the Company has recognized the funded status of its benefit plans and
implemented the disclosure requirements of SFAS 158 at September 30, 2007. The requirement to
measure the plan assets and benefit obligations as of the Companys fiscal year-end date will be
fully adopted by the Company by the end of fiscal 2009. The Company has historically measured its
plan assets and benefit obligations using a June 30th measurement date. In anticipation of
changing to a September 30th measurement date, the Company will be recording fifteen months of
pension and other post-retirement benefit costs during fiscal 2009. In accordance with the
provisions of SFAS 158, these costs have been calculated using June 30, 2008 measurement date data.
Three of those months pertain to the period of July 1, 2008 to September 30, 2008. The pension
and other post-retirement benefit costs for that period amounted to $5.1 million and have been
recorded by the Company during the quarter ended December 31, 2008 as a $3.8 million increase to
Other Regulatory Assets in the Companys Utility and Pipeline and Storage segments and a $1.3
million ($0.8 million after tax) adjustment to earnings reinvested in the business. For further
discussion of the impact of adopting the measurement date provisions of SFAS 158, refer to Part I,
Item 1 at Note 9 Retirement Plan and Other Post-Retirement Benefits.
-51-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
In December 2007, the FASB issued SFAS 141R. SFAS 141R will significantly change the
accounting for business combinations in a number of areas including the treatment of contingent
consideration, contingencies, acquisition costs, in process research and development and
restructuring costs. In addition, under SFAS 141R, changes in deferred tax asset valuation
allowances and acquired income tax uncertainties in a business combination after the measurement
period will impact income tax expense. SFAS 141R is effective as of the Companys first quarter of
fiscal 2010.
In December 2007, the FASB issued SFAS 160. SFAS 160 will change the accounting and reporting
for minority interests, which will be recharacterized as noncontrolling interests (NCI) and
classified as a component of equity. This new consolidation method will significantly change the
accounting for transactions with minority interest holders. SFAS 160 is effective as of the
Companys first quarter of fiscal 2010. The Company currently does not have any NCI.
In March 2008, the FASB issued SFAS 161. SFAS 161 requires entities to provide enhanced
disclosures related to an entitys derivative instruments and hedging activities in order to enable
investors to better understand how derivative instruments and hedging activities impact an entitys
financial reporting. The additional disclosures include how and why an entity uses derivative
instruments, how derivative instruments and related hedged items are accounted for under SFAS 133
and its related interpretations, and how derivative instruments and related hedged items affect an
entitys financial position, financial performance, and cash flows. The Company adopted the
disclosure provisions of SFAS 161 during the quarter ended March 31, 2009. These disclosures may
be found at Part I, Item 1 at Note 3 Financial Instruments.
On December 31, 2008, the SEC issued a final rule on Modernization of Oil and Gas Reporting.
The final rule modifies the SECs reporting and disclosure rules for oil and gas reserves and
aligns the full cost accounting rules with the revised disclosures. The most notable changes of
the final rule include the replacement of the single day period-end pricing to value oil and gas
reserves to a 12-month average of the first day of the month price for each month within the
reporting period. The final rule also permits voluntary disclosure of probable and possible
reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure
requirements are effective for the Companys Form 10-K for the period ended September 30, 2010.
Early adoption is not permitted. The Company is currently evaluating the impact that adoption of
these rules will have on its consolidated financial statements and MD&A disclosures.
Effective April 1, 2009, the Company adopted FASB Staff Position FAS 107-1 and APB 28-1,
Interim Disclosures about Fair Value of Financial Instruments. This FASB Staff Position amends
SFAS 107, Disclosures about Fair Value of Financial Instruments, to require disclosures about
fair value of financial instruments for interim reporting periods of publicly traded companies as
well as in annual financial statements. Refer to Part I, Item 1 at Note 3 Financial Instruments
under Long-Term Debt for additional disclosures included in accordance with this FASB Staff
Position.
Effective with this June 30, 2009 Form 10-Q, the Company adopted SFAS 165. SFAS 165
establishes general standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available to be issued. Refer
to Part I, Item 1 at Note 10 Subsequent Events for disclosures made as a result of the adoption
of SFAS 165.
In June 2009, the FASB issued SFAS 168. SFAS 168 establishes the FASB Accounting Standards
CodificationTM (the Codification) as the source of authoritative GAAP recognized by the
FASB to be applied by all nongovernmental entities in the preparation of financial statements in
conformity with GAAP. Rules and interpretive releases of the SEC under authority of federal
securities law are also sources of authoritative GAAP for SEC registrants. All other
nongrandfathered, non-SEC accounting literature not included in the Codification will become
nonauthoritative. SFAS 168 is effective for interim and annual periods ending after September 15,
2009. The Company will update its disclosures to conform to the Codification in its annual report
on Form 10-K for the year ending September 30, 2009. There will be no impact on the Companys
consolidated financial statements as the Codification does not change or alter existing GAAP.
-52-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
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, 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 results
or outcomes to differ materially from those expressed in the forward-looking statements. The
forward-looking statements contained herein are based on various assumptions, many of which are
based, in turn, upon further assumptions. The Companys expectations, beliefs and projections are
expressed in good faith and are believed by the Company to have a reasonable basis, including,
without limitation, managements examination of historical operating trends, data contained in the
Companys records and other data available from third parties, 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. |
|
Financial and economic conditions, including the availability of credit, and their effect
on the Companys ability to obtain financing on acceptable terms for working capital, capital
expenditures and other investments; |
|
2. |
|
Occurrences affecting the Companys ability to obtain financing under credit lines or other
credit facilities or through the issuance of commercial paper, other short-term notes or debt
or equity securities, including any downgrades in the Companys credit ratings and changes in
interest rates and other capital market conditions; |
|
3. |
|
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; |
|
4. |
|
The creditworthiness or performance of the Companys key suppliers, customers and
counterparties; |
|
5. |
|
Economic disruptions or uninsured losses resulting from terrorist activities, acts of war,
major accidents, fires, hurricanes, other severe weather, pest infestation or other natural
disasters; |
|
6. |
|
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; |
|
7. |
|
Changes in demographic patterns and weather conditions; |
|
8. |
|
Changes in the availability and/or price of natural gas or oil and the effect of such
changes on the accounting treatment of derivative financial instruments or the valuation of
the Companys natural gas and oil reserves; |
-53-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Cont.)
9. |
|
Impairments under the SECs full cost ceiling test for natural gas and oil reserves; |
|
10. |
|
Uncertainty of oil and gas reserve estimates; |
|
11. |
|
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, weather conditions, shortages, delays or unavailability of equipment and
services required in drilling operations, and the need to obtain governmental approvals and
permits and comply with environmental laws and regulations; |
|
12. |
|
Significant differences between the Companys projected and actual production levels for
natural gas or oil; |
|
13. |
|
Changes in the availability and/or price of derivative financial instruments; |
|
14. |
|
Changes in the price differentials between oil having different quality and/or different
geographic locations, or changes in the price differentials between natural gas having
different heating values and/or different geographic locations; |
|
15. |
|
Inability to obtain new customers or retain existing ones; |
|
16. |
|
Significant changes in competitive factors affecting the Company; |
|
17. |
|
Changes in laws and regulations to which the Company is subject, including tax,
environmental, safety and employment laws and regulations; |
|
18. |
|
Governmental/regulatory actions, initiatives and proceedings, including those involving
acquisitions, financings, rate cases (which address, among other things, allowed rates of
return, rate design and retained natural gas), affiliate relationships, industry structure,
franchise renewal, and environmental/safety requirements; |
|
19. |
|
Unanticipated impacts of restructuring initiatives in the natural gas and electric
industries; |
|
20. |
|
Significant differences between the Companys projected and actual capital expenditures and
operating expenses and unanticipated project delays or changes in project costs or plans; |
|
21. |
|
The nature and projected profitability of pending and potential projects and other
investments, and the ability to obtain necessary governmental approvals and permits; |
|
22. |
|
Ability to successfully identify and finance acquisitions or other investments and ability to
operate and integrate existing and any subsequently acquired business or properties; |
|
23. |
|
Significant changes in tax rates or policies or in rates of inflation or interest; |
|
24. |
|
Significant changes in the Companys relationship with its employees or contractors and the
potential adverse effects if labor disputes, grievances or shortages were to occur; |
|
25. |
|
Changes in accounting principles or the application of such principles to the Company; |
|
26. |
|
The cost and effects of legal and administrative claims against the Company or activist
shareholder campaigns to effect changes at the Company; |
|
27. |
|
Increasing health care costs and the resulting effect on health insurance premiums and on the
obligation to provide other post-retirement benefits; or |
|
28. |
|
Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
-54-
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
(Concl.)
The Company disclaims any obligation to update any forward-looking statements to reflect
events or circumstances after the date hereof.
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 June 30, 2009.
Changes in Internal Controls Over Financial Reporting
There were no changes in the Companys internal control over financial reporting that occurred
during the quarter ended June 30, 2009 that have materially affected, or are reasonably likely to
materially affect, the Companys internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
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 2 MD&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.
Item 1A. Risk Factors
The risk factors in Item 1A of the Companys 2008 Form 10-K, as amended by Item 1A of the
Companys Forms 10-Q for the quarters ended December 31, 2008 and March 31, 2009, 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 2008 Form 10-K and the December 31, 2008 and March 31,
2009 Forms 10-Q and should otherwise be read in conjunction with all of the risk factors disclosed
in those reports.
-55-
Item 1A. Risk Factors (Concl.)
National Fuels 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 National Fuel 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 National Fuels 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 affect its business in ways that the Company cannot predict.
In its Utility segment, the operations of Distribution Corporation are subject to the
jurisdiction of the NYPSC and the PaPUC. 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.
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have
sought to establish competitive markets in which customers may purchase supplies of gas from
marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed
into law the Natural Gas Choice and Competition Act. The Act revised the Public Utility Code
relating to the restructuring of the natural gas industry, to permit consumer choice of natural gas
suppliers. The early programs instituted to comply with the Act did not result in significant
change, and many residential customers currently continue to purchase natural gas from the utility
companies. In October 2005, the PaPUC concluded that effective competition does not exist in the
retail natural gas supply market statewide. On September 11, 2008, the PaPUC adopted a Final Order
and Action Plan designed to increase effective competition in the retail market for natural gas
services. The plan sets forth a schedule of action items for utilities and the PaPUC in order to
remove barriers in the market structure that, in the opinion of the PaPUC, prevented the full
participation of unregulated natural gas suppliers in Pennsylvania retail markets. In New York, in
August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail
Energy Markets. This policy statement has a similar goal of encouraging customer choice of
alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer
choice at the retail residential level, and customer choice activities increased in Distribution
Corporations New York service territory. In April 2007, the
NYPSC, noting that the retail energy marketplace in New York is established and continuing to
expand, commenced a review to determine if existing programs initially designed to promote
competition had outlived their usefulness and whether the cost of programs currently funded by
utility rate payers should be shifted to market competitors. Increased retail choice activities,
to the extent they occur, may increase Distribution Corporations cost of doing business, put an
additional portion of its business at regulatory risk, and create uncertainty for the future, all
of which may make it more difficult to manage Distribution Corporations business profitably.
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 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
-56-
Item 1A. Risk Factors (Concl.)
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 its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC
with respect to Supply Corporation and Empire. 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 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.
Environmental regulation significantly affects National Fuels business.
National Fuels business operations are subject to federal, state, and local laws and
regulations relating to environmental protection. These laws and regulations concern the
generation, storage, transportation, disposal or discharge of contaminants and greenhouse gases
into the environment, the reporting of such matters, and the general protection of public health,
natural resources, wildlife and the environment. Costs of compliance and liabilities could
negatively affect National Fuels results of operations, financial condition and cash flows. In
addition, compliance with environmental laws and regulations could require unexpected capital
expenditures at National Fuels facilities or delay or cause the cancellation of expansion projects
or oil and natural gas drilling activities. Because the costs of complying with environmental
regulations are significant, additional regulation could negatively affect National Fuels
business. Although National Fuel cannot predict the impact of the interpretation or enforcement of
EPA standards or other federal, state and local regulations, National Fuels costs could increase
if environmental laws and regulations become more strict.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On April 1, 2009, the Company issued a total of 2,800 unregistered shares of Company common
stock to the seven non-employee directors of the Company then serving on the Board of Directors of
the Company and receiving compensation under the Companys Retainer Policy for Non-Employee
Directors, 400 shares to each such director. All of these unregistered shares were issued as
partial consideration for the directors services during the quarter ended June 30, 2009. These
transactions were exempt from registration by Section 4(2) of the Securities Act of 1933 as
transactions not involving a public offering.
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Maximum Number of |
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
Shares that May Yet |
|
|
|
|
|
|
|
|
|
|
Part of Publicly |
|
Be Purchased Under |
|
|
Total Number of |
|
|
|
|
|
Announced Share |
|
Share Repurchase |
|
|
Shares |
|
Average Price |
|
Repurchase Plans or |
|
Plans or |
Period |
|
Purchased(a) |
|
Paid per Share |
|
Programs |
|
Programs(b) |
Apr. 1 - 30, 2009 |
|
|
11,818 |
|
|
$ |
31.05 |
|
|
|
|
|
|
|
6,971,019 |
|
May 1 - 31, 2009 |
|
|
12,103 |
|
|
$ |
31.02 |
|
|
|
|
|
|
|
6,971,019 |
|
June 1 - 30, 2009 |
|
|
14,508 |
|
|
$ |
35.24 |
|
|
|
|
|
|
|
6,971,019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
38,429 |
|
|
$ |
32.62 |
|
|
|
|
|
|
|
6,971,019 |
|
-57-
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 or shares of restricted stock for the payment of option exercise prices or
applicable withholding taxes. During the quarter ended June 30, 2009, the Company did not
purchase any shares of its common stock pursuant to its publicly announced share repurchase
program. Of the 38,429 shares purchased other than through a publicly announced share
repurchase program, 34,661 were purchased for the Companys 401(k) plans and 3,768 were
purchased as a result of shares tendered to the Company by holders of stock options or shares
of restricted stock. |
|
(b) |
|
In December 2005, the Companys Board of Directors authorized the repurchase of up
to eight million shares of the Companys common stock. The Company completed the repurchase
of the eight million shares during 2008. In September 2008, the Companys Board of Directors
authorized the repurchase of an additional eight million shares of the Companys common stock.
The Company, however, stopped repurchasing shares after September 17, 2008 in light of the
unsettled nature of the credit markets. However, such repurchases may be made in the future
if conditions improve. Such repurchases would be made in the open market or through private
transactions. |
Item 6. Exhibits
|
|
|
|
|
Exhibit |
|
|
Number |
|
Description of Exhibit |
|
|
|
|
|
|
4 |
|
|
Instruments defining the rights of security holders: |
|
|
|
|
|
|
|
|
|
Officers Certificate establishing 8.75% Notes due 2019, dated April 6,
2009 (incorporated by reference to Exhibit 4.4, Form 8-K dated April 6, 2009). |
|
|
|
|
|
|
10 |
|
|
Material contracts: |
|
|
|
|
|
|
10.1 |
|
|
Agreement to Extend Duration of Director Services Agreement,
dated June 1, 2009, between National Fuel Gas Company and Philip C. Ackerman |
|
|
|
|
|
|
12 |
|
|
Statements regarding Computation of Ratios: |
|
|
|
|
Ratio of Earnings to Fixed Charges for the Twelve Months Ended June
30, 2009 and the Fiscal Years Ended September 30, 2005 through 2008. |
|
|
|
|
|
|
31.1 |
|
|
Written statements of Chief Executive Officer pursuant to Rule
13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
|
|
|
|
|
|
31.2 |
|
|
Written statements of Principal Financial Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. |
|
|
|
|
|
|
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 June 30, 2009 and 2008. |
|
|
Incorporated herein by reference as indicated. |
-58-
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
NATIONAL FUEL GAS COMPANY
(Registrant)
|
|
|
/s/ R. J. Tanski
|
|
|
R. J. Tanski |
|
|
Treasurer and Principal Financial Officer |
|
|
|
|
|
|
/s/ K. M. Camiolo
|
|
|
K. M. Camiolo |
|
|
Controller and Principal Accounting Officer |
|
|
Date: August 7, 2009
-59-