UNITED STATESSECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010
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 1-3551
EQT CORPORATION
(Exact name of registrant as specified in its charter)
PENNSYLVANIA
25-0464690
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)
625 Liberty Avenue, Pittsburgh, Pennsylvania
15222
(Address of principal executive offices)
(Zip code)
(412) 553-5700
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
Accelerated Filer
Non-Accelerated Filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
As of March 31, 2010, 143,573,133 shares of common stock, no par value, of the registrant were outstanding.
EQT CORPORATION AND SUBSIDIARIES
Index
Page No.
Part I. Financial Information:
Item 1.
Financial Statements (Unaudited):
Statements of Consolidated Income for the Three Months Ended March 31, 2010 and 2009
3
Statements of Condensed Consolidated Cash Flows for the Three Months Ended March 31, 2010 and 2009
4
Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009
5 – 6
Notes to Condensed Consolidated Financial Statements
7 – 18
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
19 – 30
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
31 – 32
Item 4.
Controls and Procedures
33
Part II. Other Information:
Legal Proceedings
34
Item 1A.
Risk Factors
35
Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.
Exhibits
36
Signature
37
Index to Exhibits
38
2
Item 1. Financial Statements
Statements of Consolidated Income (Unaudited)
Three Months Ended
March 31,
2010
2009
(Thousands, except per share amounts)
$
436,640
469,403
113,962
209,007
34,339
31,590
16,800
15,020
1,335
3,311
39,212
29,750
61,879
44,589
267,527
333,267
169,113
136,136
527
590
2,527
1,122
34,134
19,243
138,033
118,605
49,968
46,612
88,065
71,993
134,084
130,743
0.66
0.55
135,009
131,400
0.65
0.22
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
Statements of Condensed Consolidated Cash Flows (Unaudited)
Three Months EndedMarch 31,
(Thousands)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to cash provided by operating activities:
Provision for losses on accounts receivable
4,000
1,140
Depreciation, depletion, and amortization
Other income
(34
)
(590
Equity in earnings of nonconsolidated investments
(2,527
(1,122
Equity award expense
3,244
1,935
Deferred income taxes
50,150
56,417
Excess tax benefits from share-based payment arrangements
–
(127
Decrease in inventory
69,926
141,100
(Increase) decrease in accounts receivable and unbilled revenues
(5,374
51,285
Increase in margin deposits
(10,542
(1,253
Decrease in accounts payable
(62,154
(157,951
Change in derivative instruments at fair value, net
1,619
41,953
Changes in other assets and liabilities
77,161
(36,723
Net cash provided by operating activities
275,413
212,646
Cash flows from investing activities:
Capital expenditures
(217,527
(207,715
Capital contribution to Nora Gathering, LLC
(4,500
Investment in available-for-sale securities
(750
(3,000
Net cash used in investing activities
(218,277
(215,215
Cash flows from financing activities:
Dividends paid
(28,818
(28,833
Proceeds from issuance of common stock, net
527,735
(Decrease) increase in short-term loans
(5,000
31,050
Proceeds from exercises under employee compensation plans
1,973
225
127
Net cash provided by financing activities
495,890
2,569
Net increase in cash and cash equivalents
553,026
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Cash paid during the period for:
Interest, net of amount capitalized
12,762
12,130
Net income tax refunds received
124,142
3,981
Condensed Consolidated Balance Sheets (Unaudited)
March 31,2010
December 31,2009
ASSETS
Current assets:
Cash and cash equivalents
$ 553,026
$ –
Accounts receivable (less accumulated provision for doubtful accounts:March 31, 2010, $21,205; December 31, 2009, $16,792)
172,727
155,574
Unbilled revenues
22,521
38,300
Inventory
113,031
182,957
Derivative instruments, at fair value
244,193
163,879
Prepaid expenses and other
12,438
154,456
Total current assets
1,117,936
695,166
Equity in nonconsolidated investments
184,321
181,866
Property, plant and equipment
6,694,452
6,478,486
Less: accumulated depreciation and depletion
1,619,619
1,563,755
Net property, plant and equipment
5,074,833
4,914,731
Investments, available-for-sale
38,334
36,156
Regulatory assets
98,688
99,144
Other assets
45,721
30,194
Total assets
$6,559,833
$ 5,957,257
5
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Short-term loans
$ 5,000
Accounts payable
186,833
248,987
112,426
132,518
Other current liabilities
172,576
226,169
Total current liabilities
471,835
612,674
Long-term debt
1,949,200
Deferred income taxes and investment tax credits
1,131,010
1,039,473
Unrecognized tax benefits
54,501
56,621
Pension and other post-retirement benefits
47,125
47,615
Other credits
107,649
100,644
Total liabilities
3,761,320
3,806,227
Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: March 31, 2010 and December 31, 2009, 170,130 and 157,630, respectively
1,473,179
952,237
Treasury stock, shares at cost: March 31, 2010, 26,557; December 31, 2009, 26,699
(479,532)
(482,125)
Retained earnings
1,754,605
1,695,358
Accumulated other comprehensive income (loss)
50,261
(14,440)
Total common stockholders’ equity
2,798,513
2,151,030
Total liabilities and stockholders’ equity
$ 6,559,833
6
EQT Corporation and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)
A. Financial Statements
The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information and with the requirements of Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements. In this Form 10-Q, references to “we,” “us,” “our,” “EQT,” “EQT Corporation,” and the “Company” refer collectively to EQT Corporation and its consolidated subsidiaries. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of March 31, 2010, and the results of its operations and cash flows for the three month periods ended March 31, 2010 and 2009. Certain previously reported amounts have been reclassified to conform to the current year presentation.
The balance sheet at December 31, 2009 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by United States generally accepted accounting principles for complete financial statements.
Due to the seasonal nature of the Company’s natural gas distribution and storage businesses and the volatility of commodity prices, the interim statements for the three month period ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.
For further information, refer to the consolidated financial statements and footnotes thereto included in EQT Corporation’s Annual Report on Form 10-K for the year ended December 31, 2009 as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” on page 21 of this document.
B. Segment Information
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.
The Company reports its operations in three segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, and a limited amount of crude oil, in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, processing, transportation and storage activities of the Company as well as sales of natural gas liquids (NGL). Distribution’s operations primarily comprise the state-regulated natural gas distribution activities of the Company.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income, equity in earnings of nonconsolidated investments and other income. Interest expense and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon a fixed allocation of the headquarters’ annual operating budget. Actual headquarters’ expenses in excess of budget, which are primarily related to certain incentive compensation and administrative costs, are not allocated to the operating segments.
Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States.
7
Revenues from external customers:
EQT Production
128,990
97,763
EQT Midstream
185,465
123,374
Distribution
222,255
293,172
Less: intersegment revenues (a)
(100,070
(44,906
Total
Operating income:
58,493
44,417
67,315
48,980
47,419
43,852
Unallocated expenses (b)
(4,114
(1,113
Reconciliation of operating income to net income:
Equity in earnings of nonconsolidated investments:
42
2,464
1,067
Unallocated
21
19
Other income:
195
550
332
40
Interest expense
Income taxes
December 31,
Segment Assets:
3,161,725
2,931,053
1,969,251
1,984,525
812,241
860,222
Total operating segments
5,943,217
5,775,800
Headquarters assets, including cash and short-term investments
616,616
181,457
6,559,833
5,957,257
8
Depreciation, depletion and amortization:
40,910
26,433
14,924
12,238
5,994
5,438
Other
51
480
Expenditures for segment assets:
178,415
137,436
34,687
62,173
3,975
6,776
450
1,330
217,527
207,715
(a) Intersegment revenues primarily represent natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and Distribution.
(b) Unallocated expenses primarily consist of certain incentive compensation and administrative costs in excess of budget that are not allocated to the operating segments.
C. Derivative Instruments
Natural Gas Hedging Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and natural gas liquids, which can affect the operating results of the Company primarily through the EQT Production and EQT Midstream segments. The Company’s overall objective in its commodity hedging program is to ensure an adequate level of return for the well development and infrastructure investments at these segments. The Company uses non-leveraged derivative commodity instruments to reduce the effect of this commodity price volatility. These instruments are placed with major financial institutions whose creditworthiness is continually monitored. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between a fixed and variable price for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. Put option contracts provide protection from dropping prices and require the counterparty to pay the Company if the index price falls below the contract price. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on short or long-term debt.
The Company recognizes all derivative instruments as either assets or liabilities at fair value. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. At contract inception, the Company designates its derivative instruments as hedging or trading activities. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (loss), net of tax, and is subsequently reclassified into earnings, in the same caption associated with the forecasted transaction and in the same period or periods during which the hedged forecasted transaction affects earnings. For derivative instruments that have not been designated as cash flow hedges, the change in fair value for the instrument is recognized in the Statements of Consolidated Income as operating revenues each period.
Exchange-traded instruments are generally settled with offsetting positions. Over the counter (OTC) arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying statements of Condensed Consolidated Cash Flows.
9
The various derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales have been designated and qualify as cash flow hedges under Accounting Standards Codification Topic 815, Derivatives and Hedging.
The Company assesses the effectiveness of hedging relationships, the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income.
The Company also enters into a limited amount of energy trading contracts to leverage its assets and limit its exposure to shifts in market prices and has a limited amount of other derivative instruments not designated as hedges.
The current hedge position extends through 2015 and provides price protection for approximately 34%, 20% and 6% of expected natural gas production sales volumes in 2010, 2011 and 2012, respectively. See “Commodity Risk Management” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for further details of the Company’s hedged position.
All derivatives recognized in the balance sheet and used in cash flow hedging relationships are commodity contracts. All gains (losses) recognized in income or reclassified from accumulated other comprehensive income into income are reported in operating revenues. All derivative instrument assets and liabilities are reported in the balance sheet captions derivative instruments, at fair value. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Derivatives designated as hedging instruments
Amount of gain recognized in other comprehensive income (OCI) (effective portion), net of tax
$ 77,519
$ 143,542
Amount of gain reclassified from accumulated OCI into income (effective portion), net of tax (a)
14,107
57,734
Amount of gain (loss) recognized in income (ineffective portion) (b)
1,801
(6,058)
Derivatives not designated as hedging instruments
Amount of loss recognized in income
(123)
(153)
Asset derivatives
$ 160,879
$ 111,375
83,314
52,504
$ 244,193
$ 163,879
$ 11,829
$ 61,179
100,597
71,339
$ 112,426
$ 132,518
(a) Includes $2.6 million and $8.7 million for the three months ended March 31, 2010 and 2009, respectively, of unrealized hedge gains reclassified into earnings to offset lower of cost or market adjustments on hedged items. The Company also had an immaterial amount of OCI reclassified to interest expense related to an interest rate swap on long-term debt.
(b) No amounts have been excluded from effectiveness testing.
10
The net fair value of derivative instruments changed during the first quarter of 2010 primarily as a result of a decrease in natural gas prices. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 148 Bcf and 172 Bcf as of March 31, 2010 and December 31, 2009, respectively, and are primarily related to natural gas swaps and collars. The open positions at March 31, 2010 had maturities extending through December 2015.
The Company had deferred net gains of $79.0 million and $15.6 million in accumulated other comprehensive income (loss), net of tax, as of March 31, 2010 and December 31, 2009, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $39.5 million of net unrealized gains on its derivative commodity instruments reflected in accumulated other comprehensive income, net of tax, as of March 31, 2010 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions. This recognition occurs through an increase in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that New York Mercantile Exchange (NYMEX) traded futures contracts have minimal credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various processes and analysis to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company deals with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.
When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset in the Condensed Consolidated Balance Sheets. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposit in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009.
When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. Participants must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded a current asset of $3.6 million as of March 31, 2010 and a current liability of $6.9 million as of December 31, 2009 for such deposits in its Condensed Consolidated Balance Sheets.
Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings are lowered below investment grade, additional collateral must be deposited with the counterparty. This additional collateral can be up to 100% of the derivative liability. As of March 31, 2010, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position is $13.4 million, for which the Company had no collateral posted on March 31, 2010. If the Company’s credit rating had been downgraded below investment grade on March 31, 2010, the Company would have been required to post additional collateral of $12.6 million of the liability position. Investment grade refers to the quality of the Company’s credit as assessed by one or more
11
credit rating agencies. The Company’s unsecured medium-term debt was rated BBB by Standard & Poor’s Rating Services (S&P), Baa1 by Moody’s Investor Services (Moody’s) and BBB+ by Fitch Ratings Service (Fitch) at March 31, 2010. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Fitch and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade.
D. Investments, Available-For-Sale
As of March 31, 2010, the investments classified by the Company as available-for-sale consist of approximately $38.3 million of equity and bond funds intended to fund plugging and abandonment and other liabilities for which the Company self-insures.
March 31, 2010
Adjusted Cost
Gross Unrealized Gains
Gross Unrealized Losses
Fair Value
Equity funds
$ 23,021
$ 6,914
$ 29,935
Bond funds
7,705
694
8,399
Total investments
$ 30,726
$ 7,608
$ 38,334
Unrealized gains or losses with respect to temporarily impaired investments classified as available-for-sale are recognized within the Condensed Consolidated Balance Sheets as a component of equity, accumulated other comprehensive income (loss). The Company evaluates these investments quarterly and if the Company subsequently determines that a loss is other-than-temporary, any unrealized losses stemming from such impaired investments will be recognized in earnings.
During the three month periods ended March 31, 2010 and 2009, the Company purchased additional securities with a cost basis totaling $0.8 million and $3.0 million, respectively. The Company uses the average cost method to determine the cost of securities sold.
E. Fair Value Measurements
The Company has an established process for determining fair value for its financial instruments, principally derivative commodity instruments and available-for-sale investments. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk free instrument. The Company also considers credit default swaps rates where applicable.
The Company has categorized its financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Financial instruments included in Level 1 include the Company’s futures contracts and available-for-sale investments, while instruments included in Level 2 include the majority of the Company’s swap agreements, and instruments included in Level 3 include the Company’s collar and option agreements and an insignificant portion of the Company’s swap agreements. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.
The fair value of financial instruments included in Level 2 is based on industry models that use significant observable inputs, including NYMEX forward curves and LIBOR-based discount rates. Swaps included in Level 3 are valued using internal models that use significant unobservable inputs; these internal models are validated each period with non-binding broker price quotes. The Company has not experienced significant differences between internally calculated values and broker price quotes. Collars and options included in Level 3 are valued using internal models calculated with market derived volatilities. The Company uses NYMEX forward curves to value
12
futures, NYMEX swaps, collars and options. The NYMEX forward curves are validated to external sources at least monthly.
The following assets and liabilities were measured at fair value on a recurring basis during the period:
Fair value measurements at reporting date using
Description
Quoted prices in active markets for identical assets(Level 1)
Significant other observable inputs(Level 2)
Significant unobservable inputs(Level 3)
Assets
8,729
101,574
133,890
282,527
43,063
Liabilities
11,438
100,356
632
Fair value measurements using significant unobservable inputs(Level 3)
Derivative instruments, at fair value, net
Balance at January 1, 2010
88,570
Total gains or losses:
Included in earnings
(9)
Included in other comprehensive income
52,670
Purchases, issuances, and settlements
(7,973)
Transfers in and/or out of Level 3
Balance at March 31, 2010
133,258
The amount of total (losses) or gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets and liabilities still held as of March 31, 2010
Gains and losses related to derivative commodity instruments included in earnings for the period are reported in operating revenues in the Statements of Consolidated Income. All gains or losses included in earnings related to available-for-sale securities are included in other income.
13
F. Comprehensive Income
Total comprehensive income, net of tax, was as follows:
Three Months Ended March 31,
Other comprehensive income:
Net change in cash flow hedges
63,443
85,837
Unrealized gain (loss) on investments, available-for-sale
855
(1,603
Pension and other post-retirement benefit plans
403
388
Total comprehensive income
152,766
156,615
The components of accumulated other comprehensive income (loss), net of tax, are as follows:
Net unrealized gain from hedging transactions
78,740
15,297
Unrealized gain on available-for-sale securities
4,945
4,090
Pension and other post-retirement benefits adjustment
(33,424
(33,827
(14,440
G. Income Taxes
The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period. Separate effective income tax rates are calculated for net income from continuing operations and any other separately reported net income items, such as discontinued operations.
The Company’s effective income tax rate for the three months ending March 31, 2010 is 36.2%. The estimated annual effective income tax rate as of March 31, 2009 was 39.3%. The Company currently estimates the 2010 annual effective income tax rate to be approximately 36.2%. The decrease in the expected annual effective tax rate from 2009 is primarily the result of a decrease in limitations imposed on certain state tax losses. In addition, carrying 2009 losses back to receive a cash refund of taxes paid in prior years resulted in the loss of certain deductions, thereby increasing the overall 2009 rate.
There were no material changes to the Company’s methodology or to the balance recorded for unrecognized tax benefits during the three months ended March 31, 2010.
The Internal Revenue Service (IRS) has completed its audit and review of the Company’s federal income tax filings through 2005. The only unresolved issue relates to the research and experimentation tax credits of $3.8 million claimed by the Company for years 2001 through 2005 which is currently at the Appeals Division of the IRS. The IRS is scheduled to begin its audit and review of the Company’s federal income tax filings for the 2006 through 2009 years during the second quarter of 2010. The Company also is the subject of various state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions claimed during the periods to be reviewed.
The Worker, Homeownership and Business Assistance Act of 2009 extended the applicability of the tax net operating loss carryback provision from 2 years to 5 years for either the 2008 or 2009 tax year. The Company elected to carryback its 2009 tax operating loss under this new law and received a refund of $121.5 million from the IRS during the first quarter of 2010. EQT also received a refund of $115.2 million primarily in the second quarter of 2009 from the IRS relating to the 2008 net operating loss carryback. These net operating losses were primarily generated from intangible drilling costs (IDC) for the Company’s drilling program that are deducted currently for tax purposes and from accelerated tax depreciation for expansion of the Company’s midstream business.
14
The Reconciliation Act and the Health Care Act passed in March of 2010 eliminated the deduction allowed in regard to companies receiving Medicare Part D subsidies. The Company does not receive any such subsidies and was not impacted by this law change.
H. Short-Term Loans
On October 27, 2006, the Company entered into a $1.5 billion, five-year revolving credit agreement, which replaced the Company’s previous $1 billion, five-year revolving credit agreement. On December 15, 2006, the maturity date was extended to October 26, 2011. Additionally, the Company may request two one-year extensions of the stated maturity date; however, these extensions require the approval of 51% of the lenders underwriting the credit facility. The revolving credit agreement may be used for working capital, capital expenditures, share repurchases and other purposes including support of a commercial paper program. Subject to certain terms and conditions, the Company may, on a one time basis, request that the lenders’ commitments be increased to an aggregate amount of up to $2.0 billion. Each lender in the facility may decide if it will increase its commitment.
The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and had committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million.
The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by S&P, Moody’s or Fitch, on the Company’s non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate.
As of March 31, 2010, the Company had no loans outstanding under the revolving credit facility. An irrevocable standby letter of credit of $23.9 million was outstanding at March 31, 2010. As of December 31, 2009, the Company had outstanding short-term loans under the revolving credit facility of $5.0 million and an irrevocable standby letter of credit of $24.4 million. Commitment fees averaging approximately one-twelfth of one percent in 2010 and 2009 were paid to maintain credit availability under the revolving credit facility.
The weighted average interest rate for short-term loans outstanding as of December 31, 2009 was 0.51% per annum. The maximum amount of outstanding short-term loans at any time during the three months ended March 31, 2010 and 2009 was $139.7 million and $491.7 million, respectively. The average daily balance of short-term loans outstanding during the three months ended March 31, 2010 and 2009 was approximately $86.1 million and $384.0 million at weighted average annual interest rates of 0.47% and 0.72%, respectively.
15
I. Long-Term Debt
5.15% notes, due November 15, 2012
$ 200,000
5.00% notes, due October 1, 2015
150,000
5.15% notes, due March 1, 2018
200,000
6.50% notes, due April 1, 2018
500,000
8.13% notes, due June 1, 2019
700,000
7.75% debentures, due July 15, 2026
115,000
Medium-term notes:
8.5% to 9.0% Series A, due 2011 thru 2021
46,200
7.3% to 7.6% Series B, due 2013 thru 2023
30,000
7.6% Series C, due 2018
8,000
Less debt payable within one year
Total long-term debt
$ 1,949,200
The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s long-term indebtedness.
Aggregate maturities of long-term debt are $0 in 2010, $6.0 million in 2011, $200.0 million in 2012, $10.0 million in 2013 and $5.0 million in 2014.
J. Pension and Other Postretirement Benefit Plans
The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three months ended March 31, 2010 and 2009 were as follows:
Pension Benefits
Other Benefits
Components of net periodic benefit cost
Service cost
$ 150
$ 109
$ 154
$ 144
Interest cost
847
906
494
537
Expected return on plan assets
(1,072)
(1,145)
Amortization of prior service cost
(226)
Recognized net actuarial loss
331
298
399
437
Settlement loss
210
173
Net periodic benefit cost
$ 466
$ 345
$ 821
$ 892
K. Fair Value of Financial Instruments
The carrying value of cash equivalents and short-term loans approximates fair value due to the short maturity of the instruments. Available-for-sale securities and derivative instruments are reported in the Condensed Consolidated Balance Sheets at fair value. See Notes C, D and E.
The estimated fair value of long-term debt on the Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009 was approximately $2 billion. The fair value was estimated using the Company’s established fair value methodology. Where quoted market prices are not available, the Company uses an internal model which uses significant observable inputs including market discount rates consistent with the associated risk and term of the Company’s long-term debt.
16
L. Recently Issued Accounting Standards
Disclosures about Fair Value Measurements
In January 2010, the Financial Accounting Standards Board (FASB) issued an amendment intended to enhance fair value disclosures, improve the transparency of the inputs and assumptions used to measure the fair value of assets and liabilities reported, and improve comparability with International Financial Reporting Standards. During the three months ended March 31, 2010, the Company adopted certain provisions of this amendment; this did not have a material effect on the Company’s financial statements. Other provisions of the amendment are effective for fiscal years beginning after December 15, 2010. The Company is currently evaluating the affect that this amendment will have on its consolidated financial statement disclosures.
M. Acquisitions
On March 2, 2010, the Company announced that it will acquire approximately 58,000 net acres in the Marcellus Shale from a group of private operators and landowners. The acreage is located primarily in Cameron, Clearfield, Elk and Jefferson counties in Pennsylvania. The purchase includes a 200 mile gathering system, with associated rights of way, and approximately 100 producing vertical wells. The Company will pay approximately $280 million for these assets, 90% in EQT stock and 10% in cash. Following the closing of the acquisition, the Company will hold approximately 500,000 net acres in the high pressure Marcellus Shale fairway.
N. Earnings Per Share
The computation of basic and diluted earnings per common share is shown in the table below:
(Thousands, except pershare amounts)
Basic earnings per common share:
Average common shares outstanding
Basic earnings per common share
Diluted earnings per common share:
Potentially dilutive securities
Stock options and awards (a)
925
657
Diluted earnings per common share
(a) Options to purchase 1,241,566 and 977,127 shares of common stock were not included in the computation of diluted earnings per common share for the three months ended March 31, 2010 and 2009, respectively, because the options’ exercise prices were greater than the average market prices of common shares as of the respective dates.
O. Other Events
On March 16, 2010, the Company completed a public offering of 12,500,000 shares of its common stock, no par value (the Common Stock), at an offering price to the public of $44.00 per share. The proceeds from the offering are being used to accelerate development of the Marcellus Shale and Huron/Berea plays.
The underwriters in this transaction also exercised their over-allotment option to purchase 225,000 additional shares of the Company’s Common Stock on April 14, 2010 at an offering price to the public of $44.00 per share.
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P. Subsequent Events
The Company has evaluated subsequent events through the date of financial statement issuance.
18
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAUTIONARY STATEMENTS
Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “will,” “approximate,” “expect,” “forecast,” “project,” “intend,” “plan,” “may,” “believe” and other words of similar meaning in connection with any discussion of future operating or financial matters. Without limiting the generality of the foregoing, forward-looking statements contained in this report include the matters discussed in the sections captioned “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and the expectations of plans, strategies, objectives, and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s drilling and infrastructure programs (including the Equitrans Marcellus Expansion Project) and technology, the estimated number of acres to be held in the high-pressure Marcellus Shale fairway following and the timing of the closing of the previously announced Marcellus Shale acreage acquisition, the timing of construction of public-access natural gas refueling stations, production and sales volumes, reserves, unit costs, capital expenditures, financing requirements, hedging strategy and tax position. These statements involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. The risks and uncertainties that may affect the operations, performance and results of the Company’s business and forward-looking statements include, but are not limited to, those set forth under Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2009.
Any forward-looking statement applies only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.
In reviewing any agreements incorporated by reference in this Form 10-Q, please remember they are included to provide you with information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Company. The agreements may contain representations and warranties by the Company, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
CORPORATE OVERVIEW
Three Months Ended March 31, 2010
vs. Three Months Ended March 31, 2009
EQT Corporation’s consolidated net income for the three months ended March 31, 2010 totaled $88.1 million, or $0.65 per diluted share, compared to $72.0 million, or $0.55 per diluted share, reported for the same period a year ago. Several factors contributed to the increase in net income between periods. The Company was favorably impacted by increased produced natural gas sales volumes, increased sales prices for NGLs, higher gathered volumes, and base rate increases for residential customers in the distribution business. These favorable net revenue variances were partially offset by increased depletion expenses resulting from an increased investment in natural gas producing properties and increased natural gas production, increased interest charges resulting from additional long-term debt issued during 2009, increased operating expenses for 2010 and reduced margins in marketing activities. The effective income tax rate decreased in 2010 compared to 2009 as a result of lower limitations on state tax operating losses.
The Company has reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. EQT’s management believes that presentation of this information provides useful information to management and investors
regarding the financial condition, operations and trends of each of EQT’s segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and certain compensation expenses. In addition, management uses these measures for budget planning purposes.
EQT PRODUCTION
OVERVIEW
EQT Production’s strategy is to maximize value by profitably developing the Company’s extensive acreage position through organic growth enabled by a low cost structure. The Company is focused on continuing its significant organic reserve and production growth through its drilling program and believes that it is a technological leader in drilling in low pressure shale. The Company drilled 108 gross (90 net) wells in the first quarter of 2010, including 77 horizontal wells comprised of 56 horizontal Huron/Berea wells and 21 horizontal Marcellus Shale wells. In the comparable quarter in 2009, the Company drilled 137 gross (96 net) wells, including 57 horizontal wells, comprised of 53 horizontal Huron/Berea wells and 4 horizontal Marcellus Shale wells. See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for details regarding the Company’s capital expenditures for drilling and development.
During the first quarter of 2010, the Company announced that it will acquire approximately 58,000 net acres in the Marcellus Shale from a group of private operators and landowners. The acreage is located primarily in Cameron, Clearfield, Elk and Jefferson counties in Pennsylvania. The purchase includes a 200 mile gathering system, with associated rights of way, and approximately 100 producing vertical wells. EQT will pay approximately $280 million for these assets, 90% in EQT stock and 10% in cash. Following the closing of the acquisition, the Company will hold approximately 500,000 net acres in the high pressure Marcellus Shale fairway. The Company expects a significant portion of the transaction to close by April 30, 2010, subject to customary closing conditions.
EQT Production’s operating revenues for the first quarter of 2010 increased 32% compared to the first quarter of 2009 as a result of significantly increased production as well as higher commodity prices. Gas sales volumes increased 31% from the first quarter of 2009 to the first quarter of 2010. The increase was primarily the result of increased production from the 2009 and 2010 drilling programs partially offset by the normal production decline in the Company’s existing wells.
First quarter operating expenses at EQT Production included an increase in the Company’s depletion expense as a result of higher depletion rates attributable to the significant on-going well development program and increased production volumes.
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RESULTS OF OPERATIONS
%
OPERATIONAL DATA
Natural gas and oil production (MMcfe)
31,397
24,478
28.3
Company usage, line loss (MMcfe)
(1,397)
(1,502)
(7.0)
Total sales volumes (MMcfe)
22,976
30.6
Average (well-head) sales price ($/Mcfe)*
4.23
4.16
1.7
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)
0.25
Production taxes ($/Mcfe)
0.26
0.36
(27.8)
Production depletion ($/Mcfe)
1.24
1.03
20.4
Depreciation, depletion and amortization (DD&A) (thousands):
Production depletion
38,977
25,205
54.6
Other depreciation, depletion and amortization
1,933
1,228
57.4
Total DD&A
54.8
Capital expenditures (thousands)
29.8
FINANCIAL DATA (Thousands)
Total operating revenues
31.9
Operating expenses:
LOE, excluding production taxes
7,803
6,042
29.1
Production taxes
8,069
8,824
(8.6)
Exploration expense
(59.7)
Selling, general and administrative (SG&A)
12,380
8,736
41.7
DD&A
Total operating expenses
70,497
53,346
32.2
Operating income
31.7
*Average (well-head) sales price is calculated as market price adjusted for hedging activities less deductions for gathering, processing and transmission and NGL revenues included in EQT Midstream revenues. These deductions totaled $2.39 and $1.89 per Mcfe for the three months ended March 31, 2010 and 2009, respectively.
EQT Production’s operating income totaled $58.5 million for the three months ended March 31, 2010 compared to $44.4 million for the three months ended March 31, 2009. The $14.1 million increase in operating income was primarily the result of increased produced natural gas sales volumes partially offset by higher depletion, depreciation and amortization and higher selling, general and administrative expenses.
Total operating revenues were $129.0 million for the three months ended March 31, 2010 compared to $97.8 million for the three months ended March 31, 2009. The $31.2 million increase in total operating revenues was primarily due to an increase in produced natural gas sales volumes as well as a 2% increase in the average well-head sales price. The increase in produced natural gas sales volumes was the result of increased production from the 2009 and
2010 drilling programs, primarily in the Huron/Berea and Marcellus Shale plays as the Company drilled 37 more gross horizontal wells in the fourth quarter of 2009 compared to the fourth quarter of 2008. The increase in produced natural gas sales volumes were partially offset by the normal production decline in the Company’s wells. The $0.07 per Mcfe increase in the average well-head sales price was due to a $0.41 per Dth (8%) increase in the average NYMEX price and a higher percentage of unhedged gas sales, partially offset by a lower realized hedge price. The operating revenues and recognized price reflect a non-cash benefit for ineffectiveness in cash flow hedges of $2.7 million ($0.09 per Mcfe) in 2010 and a non-cash charge for ineffectiveness in cash flow hedges of $6.2 million ($0.27 per Mcfe) in 2009. The ineffectiveness in the first quarter of 2009 was a non-cash charge related to NYMEX swaps entered into in 2003 and 2004 with maturity dates from 2009 through 2011. The charge was primarily the result of decreases in forecast basis in the Appalachian Basin as compared to basis at the inception of the hedges. At March 31, 2010, the change in the forecasted basis prices resulted in less ineffectiveness on the NYMEX swaps which resulted in a partial reversal of the charge in the first quarter of 2010. The Company evaluates hedge effectiveness on a quarterly basis and, as a result, increases or decreases in location basis may generate gains or losses from time to time.
Operating expenses totaled $70.5 million for the three months ended March 31, 2010 compared to $53.3 million for the three months ended March 31, 2009. The increase in operating expenses was primarily the result of increases in DD&A and in SG&A. The depletion expense increase reflects increases in the unit rate ($6.8 million) and in volumes ($6.8 million). The $0.21 per Mcfe increase in the depletion rate is primarily attributable to the increased investment in oil and gas producing properties. The increase in SG&A was primarily due to personnel costs associated with the growth of the business and a first quarter 2009 favorable adjustment to the reserve for uncollectible accounts. These factors were partially offset by decreases in exploration expense and production taxes. The decrease in exploration expense was due to a reduction in exploration activity compared to the prior year. The decrease in production taxes was due to decreased property taxes partially offset by an increase in severance taxes. The decrease in property taxes was a direct result of the reduction in commodity prices from 2008 to 2009, as property taxes in several of the taxing jurisdictions where the Company’s wells are located are calculated based on historical gas commodity prices and gas sales volumes calculated on a rolling one to three-year lag. The increase in severance taxes (a production tax directly imposed on the value of the gas extracted) was primarily due to higher gas commodity prices in the current year.
OUTLOOK
EQT Production’s business strategy is focused on organic growth of the Company’s natural gas reserves and sales volumes. Key elements of EQT Production’s strategy include:
· Expanding reserves and production through horizontal drilling in Kentucky, West Virginia and Pennsylvania. The Company is committed to expanding its production and developed reserves through cost-effective technologically advanced horizontal drilling in its existing plays. The Company will seek to maximize the value of its existing asset base by developing its large acreage position, which the Company believes holds significant production and reserve growth potential. A substantial portion of the Company’s 2010 drilling efforts will be focused on drilling horizontal wells in shale formations in Kentucky, West Virginia and Pennsylvania. The Company continues to focus on its highly successful horizontal air drilling program by drilling fractured horizontal single lateral wells, non-fractured horizontal multilateral wells, stacked horizontal wells and extended lateral wells. Additionally, based on favorable preliminary results, the Company is in the process of incorporating extended lateral wells into its preferred standard operating procedures for the Huron/Berea play. The Company expects to access significantly more reserves through the extended lateral drilling procedures for less than a proportional amount of the development costs.
EQT MIDSTREAM
EQT Midstream’s long-term strategy is focused on capitalizing on the synergies presented by EQT’s production and pipeline footprint. Our Midstream location of assets across a wide area of the Marcellus Shale uniquely positions the segment for growth.
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EQT Midstream’s 2010 first quarter net operating revenues were 26% higher than the first quarter 2009 period. Increases in NGL sales prices and higher gathering, processing, and transmission volumes were partially offset by a decrease in margin on third party marketing that utilized Big Sandy Pipeline capacity. Operating and maintenance expense increased in conjunction with the overall growth of the business while DD&A increased primarily due to the investment in infrastructure during 2009.
See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for information regarding the Company’s capital expenditures for Midstream infrastructure projects.
Gathered volumes (BBtu)
44,623
38,479
16.0
Average gathering fee ($/MMBtu)
$ 1.10
$ 1.03
6.8
Gathering and compression expense ($/MMBtu)
$ 0.37
$ 0.40
(7.5)
NGLs sold (Mgal) (a)
33,214
27,374
21.3
Average NGL sales price ($/gal)
$ 1.15
$ 0.67
71.6
Transmission pipeline throughput (BBtu)
24,993
17,218
45.2
Net operating revenues (thousands):
Gathering
$ 48,734
$ 38,679
26.0
Processing
22,734
6,620
243.4
Transmission
21,553
19,810
8.8
Storage, marketing and other
23,827
27,447
(13.2)
Total net operating revenues
$ 116,848
$ 92,556
26.2
$ 34,687
$ 62,173
(44.2)
$ 185,465
$ 123,374
50.3
Purchased gas costs
68,617
30,818
122.7
116,848
92,556
Operating and maintenance (O&M)
23,977
21,201
13.1
SG&A
10,632
10,137
4.9
21.9
49,533
43,576
&n bsp;
13.7
$ 67,315
$ 48,980
37.4
$ 195
$ 550
(64.5)
$ 2,464
$ 1,067
130.9
(a) NGLs sold includes NGLs recovered at the Company’s processing plant and transported to a fractionation plant owned by a third party for separation into commercial components, net of volumes retained, as well as equivalent volumes sold at liquid component prices under the Company’s contractual processing arrangements with third parties.
23
EQT Midstream’s operating income totaled $67.3 million for the three months ended March 31, 2010 compared to $49.0 million for the three months ended March 31, 2009. The $18.3 million increase in operating income was primarily the result of favorable commodity prices for NGLs and an increase in gathered volumes and processing and transmission activity offset by lower marketing spreads.
Total net operating revenues were $116.8 million for the three months ended March 31, 2010 compared to $92.6 million for the three months ended March 31, 2009. The increase in total net operating revenues was due to a $16.1 million increase in processing net operating revenues, a $10.1 million increase in gathering net operating revenues, and a $1.7 million increase in transmission net operating revenues, partially offset by a $3.6 million decrease in storage, marketing and other net operating revenues.
The increase in processing net revenues in the first quarter 2010 compared to the first quarter of 2009 primarily was due to a 72% higher sales price for NGLs. This NGL price increase, combined with a 21% increase in NGLs sold in the first quarter of 2010 compared to the first quarter of 2009, resulted in record first quarter processing revenues.
Gathering net operating revenues increased due to a 16% increase in gathered volumes as well as a 7% increase in the average gathering fee. The volume increase was driven primarily by more Marcellus Shale volumes gathered for EQT Production.
Transmission net revenues in the first quarter of 2010 increased from the prior year primarily due to higher firm transportation activity resulting from increased Marcellus Shale volumes from affiliated shippers.
The decrease in storage, marketing and other net revenues was primarily due to decreased margins on third party marketing that primarily utilized Big Sandy Pipeline capacity. This decrease was partially offset by increased sales to an industrial customer.
Total operating revenues increased $62.1 million primarily as a result of higher NGL sales prices as well as increased gathering and processing volumes, gathering rates and increased transmission revenues partially offset by decreased commercial activity related to contractual storage assets. Total purchased gas costs decreased 123% as a result of decreased commercial activity related to contractual storage assets.
Operating expenses totaled $49.5 million for the three months ended March 31, 2010 compared to $43.6 million for the three months ended March 31, 2009. The increase in operating expenses was primarily due to increases of $2.8 million in O&M and $2.7 million in DD&A. The increase in O&M is primarily due to higher operational costs associated with the growth in the Midstream business including electricity, labor and severance tax expenses. The increase in DD&A was primarily due to the increased investment in gathering, processing, and transmission infrastructure.
Other income primarily represents allowance for equity funds used during construction. The $0.4 million decrease from the first quarter of 2009 to the first quarter of 2010 was primarily the result of decreased assets under construction on regulated pipeline projects.
Equity in earnings of nonconsolidated investments totaled $2.5 million for the three months ended March 31, 2010 compared to $1.1 million for the three months ended March 31, 2009, and relates to equity earnings recorded for EQT Midstream’s investment in Nora Gathering, LLC. The $1.4 million increase was driven by additional gathered volumes.
EQT Midstream’s long-term strategy is focused on capitalizing on its infrastructure asset position in the heart of the Marcellus Shale play in southwestern Pennsylvania and northern West Virginia. The location of our midstream assets across a wide area of the Marcellus Shale uniquely positions the segment for growth. In addition, EQT Midstream continues to provide and maintain a long-term growth platform for EQT Production in the Huron/Berea play. Key projects of EQT Midstream’s strategy include:
24
· Gathering Projects. In the first quarter, EQT Midstream completed construction of the Ingram Gathering system which allowed for the delivery of 50,000 Dth per day of EQT production in Greene County, Pennsylvania, into two Equitrans pipelines. The second phase of this project will extend the system further east to nearby EQT Production acreage. The second phase will provide an additional 40,000 Dth per day of capacity for EQT’s production by year-end 2010. The necessary right-of-ways have been acquired and the pipe has been purchased. In Northern West Virginia, EQT Midstream is in the process of constructing a Doddridge Gathering System Expansion which will deliver EQT’s production from North Central West Virginia into the western leg of the Equitrans system. Capacity additions of 50,000 Dth per day will be made available by year end, bringing total gathering capacity in West Virginia to approximately 70,000 Dth per day.
· Equitrans Marcellus Expansion Project. The Equitrans Marcellus Expansion Project is underway and, given its significant scope, is progressing in stages. Equitrans has secured the market commitments necessary to support Phase 1, and FERC Prior Notice Application authority for this phase was received April 2, 2010. Phase 1 construction consists of upgrades to various segments on the existing Equitrans transmission system along with modifications to compression at the Pratt Station. This $15 million expansion will allow for approximately 100,000 Dth per day of incremental delivery capacity to Equitrans’ interconnections with five interstate pipeline facilities. Construction of this phase is expected to be completed in the fourth quarter 2010. Equitrans is preparing a second quarter 2010 certificate pre-filing with the Federal Energy Regulatory Commission for the balance of the Equitrans Marcellus Expansion Project. A provisional, in-service date of mid-2012 is anticipated.
· Lower Huron. Processing upgrades to the Kentucky Hydrocarbon facility are underway.
Gathering, processing and transmission revenues are expected to increase as EQT Midstream expands its infrastructure to support EQT Production growth in the Huron/Berea and Marcellus Shale plays. In light of the anticipated continued growth of production, EQT Midstream is considering partnering and other arrangements to facilitate the continued expansion of its processing, gathering, and transmission assets.
DISTRIBUTION
Distribution’s net operating revenues for the first quarter increased 9% from 2009 to 2010, primarily due to an increase in base rates effective with the Company’s settlement of its Pennsylvania rate case in late February 2009. Total operating expenses in the first quarter of 2010 increased 11% due to higher bad debt expense and other operating costs.
See “Capital Resources and Liquidity” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for information on the Company’s capital expenditures for distribution projects.
25
2,860
2,887
(0.9)
11,865
11,961
(0.8)
11,436
10,190
12.2
23,301
22,151
5.2
$ 49,630
$ 44,179
12.3
19,823
19,610
1.1
7,388
6,603
11.9
$ 76,841
$ 70,392
9.2
$ 3,975
$ 6,776
(41.3)
FINANCIAL DATA (thousands)
$ 222,255
$ 293,172
(24.2)
145,414
222,780
(34.7)
76,841
70,392
10,600
9,779
8.4
12,828
11,323
13.3
10.2
29,422
26,540
10.9
$ 47,419
$ 43,852
8.1
Distribution’s operating income totaled $47.4 million for the first quarter of 2010 compared to $43.9 million for the first quarter of 2009. The increase in operating income is primarily due to an increase in base rates partially offset by higher operating expenses.
Net operating revenues were $76.8 million for the first quarter of 2010 compared to $70.4 million for the first quarter of 2009. The $6.4 million increase in net operating revenues was primarily a result of increased revenues from residential customers as a result of the approval of the Company’s base rate increase in late February 2009. The weather in Distribution’s service territory in the first quarter of 2010 was comparable to the first quarter of 2009 (2% warmer than the 30-year National Oceanic and Atmospheric Administration average for the Company’s service territory) and did not have a significant impact on residential net operating revenues. Off-system and energy services net operating revenues increased $0.8 million due to higher revenues from gathering activities resulting from increased rates as well as greater asset optimization opportunities realized in 2010. Commercial and industrial net revenues increased $0.2 million due to an increase in usage by one industrial customer. The high volume sales from the industrial customer have low unit margins and thus these increases in volumes do not significantly impact total
26
net operating revenues. Additionally, a decrease in the commodity component of residential tariff rates resulted in a decrease in both total operating revenues and purchased gas costs.
Operating expenses totaled $29.4 million for the first quarter of 2010 compared to $26.5 million for the first quarter of 2009. The $2.9 million increase in operating expenses was primarily the result of a $1.8 million increase in bad debt expense, increased field operating and maintenance activities and an increase in DD&A. The increase in bad debt expense was primarily the result of favorable adjustments in the allowance for uncollectible accounts in the first quarter of 2009 mainly due to increased funding for, and participation in, programs assisting low-income customers in paying their bills and the recovery of CAP costs associated with the approval of the rate case settlement. A significant reduction in funding from government programs assisting low-income customers from 2009 to 2010 contributed to the increase in bad debt expense in 2010. The Company will continue to closely monitor its collection rates and adjust its reserve for uncollectible accounts as necessary. Future changes are not expected to have a material impact on the consolidated results of operations. The increase in DD&A was primarily due to additional assets placed in service during 2009.
Distribution will continue to execute its strategy of earning a competitive return on its asset base through operational efficiency and regulatory mechanisms. Distribution is focused on enhancing the value of its existing assets by improving the efficiency of its workforce, establishing a reputation for excellent customer service, effectively managing its capital spending and continuing to leverage technology throughout its operations. Distribution is also seeking out growth opportunities for the sale of natural gas through new outlets such as natural gas vehicles while promoting customer conservation and efficiency. In April 2010, Equitable Gas Company, LLC was selected by the Pennsylvania Department of Environmental Protection to receive a $700,000 grant that will assist in the construction of a public-access natural gas fueling station in Pittsburgh, PA. Construction of the fueling station is expected to be completed in early 2011.
CAPITAL RESOURCES AND LIQUIDITY
Overview
The Company’s primary sources of cash for the first quarter of 2010 were proceeds from an offering of common stock and cash flows from operating activities, including a $121.5 million income tax refund. On March 16, 2010, the Company completed a common stock offering of 12,500,000 shares. The Company will use the $527.7 million of net proceeds from the offering to accelerate development of its Marcellus Shale and Huron/Berea plays. As of March 31, 2010, the net proceeds were invested in standard money market funds. Additionally, on March 5, 2010, the Company received a refund of $121.5 million from the IRS relating to its 2009 net operating loss carryback claim. The Company used the cash primarily to fund its capital program and for operating expenses.
Operating Activities
Cash flows provided by operating activities totaled $275.4 million for the first quarter of 2010 and $212.6 million for the first quarter of 2009, an increase of $62.8 million in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was primarily attributable to the following:
· the receipt of a $121.5 million income tax refund;
· increased operating revenues, primarily as a result of $28 million from increased sales volumes of produced natural gas;
partially offset by:
· decreases in commodity prices from 2008 to 2009 which resulted in significant changes in inventory, accounts receivable and accounts payable in the first quarter 2009.
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Investing Activities
Cash flows used in investing activities were relatively unchanged in the first quarter 2010 compared to the first quarter 2009. Capital expenditures totaled $217.5 million for the first quarter of 2010 and $207.7 million for the first quarter of 2009.
Capital expenditures for drilling and development totaled $178.4 million and $137.4 million during the first quarter of 2010 and 2009, respectively. The Company drilled 108 gross wells, including 77 gross horizontal wells in the first quarter of 2010, compared to 137 gross wells, including 57 gross horizontal wells in the first quarter of 2009.
Capital expenditures for the Midstream operations totaled $34.7 million and $62.2 million during the first quarter of 2010 and 2009, respectively. The 2010 expenditures were for gathering pipeline and gathering compression projects. The $27.5 million decrease in capital expenditures was due to fewer gathering pipeline and gathering compression projects primarily as a result of inclement weather during the first quarter of 2010.
Capital expenditures at Distribution totaled $4.0 million for the first quarter of 2010 compared to $6.8 million for the first quarter of 2009. The 2010 expenditures were for mainline replacements and other infrastructure projects. The $2.8 million decrease in capital expenditures was primarily due to reduced mainline replacement work in the first quarter of 2010 as compared to the same period in 2009 primarily as a result of inclement weather during the first quarter of 2010.
Financing Activities
Cash flows provided by financing activities totaled $495.9 million for the first quarter of 2010 compared to $2.6 million for the first quarter of 2009, an increase of $493.3 million in cash flows provided by financing activities between years. In the first quarter of 2010, the Company completed a common stock offering of 12,500,000 shares. The Company will use the net proceeds from the offering to accelerate development of its Marcellus Shale and Huron/Berea plays.
Security Ratings
The table below reflects the current credit ratings for the outstanding debt instruments of the Company. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt and its access to the credit markets.
Senior
Short-Term
Rating Service
Notes
Rating
Moody’s Investors Service
Baa1
P-2
Standard & Poor’s Ratings Services
BBB
A-3
Fitch Ratings
BBB+
F-2
On February 17, 2010, Standard & Poor’s Ratings Services (S&P) affirmed its ratings on EQT. At the same time, S&P revised its outlook to negative and lowered the short-term rating to A-3 citing the Company’s growth in its exploration and production and midstream businesses.
On March 9, 2009, Moody’s reaffirmed its ratings on EQT. The outlook is negative. Moody’s stated that the “ratings reflect the diversification and vertical integration among its three business segments as well as the Baa stand-alone quality of both its E&P and LDC operations.”
On March 26, 2010, Fitch affirmed its ratings on EQT stating that the “ratings are supported by the strong performance of its upstream segment, the relatively predictable cash flows from its midstream and distribution segment, a significant use of equity to help finance its growth strategy, and management’s continued maintenance of a strong liquidity position.”
The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies
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downgrade the Company’s ratings, particularly below investment grade, the Company’s access to the capital markets may be limited, borrowing costs and margin deposits would increase, counterparties may request additional assurances and the potential pool of investors and funding sources may decrease. The required margin is also subject to significant change as a result of factors other than credit rating such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company.
The Company’s debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most important default events include maintaining covenants with respect to maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations, and change of control provisions. The Company’s current credit facility’s financial covenants require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income (loss). As of March 31, 2010, the Company is in compliance with all existing debt provisions and covenants.
Commodity Risk Management
The Company’s overall objective in its hedging program is to ensure an adequate level of return for the well development and infrastructure investment at EQT Production and EQT Midstream. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and OTC natural gas swap agreements and options (collectively, “derivative commodity instruments”) to hedge exposures to fluctuations in natural gas prices and for trading purposes. The derivative commodity instruments currently utilized by the Company are primarily fixed price swaps, collars and options.
The approximate volumes and prices of the Company’s total hedge position for 2010 through 2012 production are:
2010**
2011
2012
Swaps
Total Volume (Bcf)
Average Price per Mcf (NYMEX)*
$ 5.12
$ 5.10
Puts
Average Floor Price per Mcf (NYMEX)*
$ 7.35
Collars
$ 7.28
$ 7.11
Average Cap Price per Mcf (NYMEX)*
$ 14.05
$ 14.12
$ 14.07
* The above price is based on a conversion rate of 1.05 MMBtu/Mcf
**April through December
The Company’s current hedge position extends through 2015 and provides price protection for approximately 34%, 20% and 6% of expected natural gas production sales volumes in 2010, 2011 and 2012, respectively. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is approximately $0.05, $0.08 and $0.10 per diluted share for 2010, 2011 and 2012, respectively. The Company also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices.
See Note C to the Company’s Condensed Consolidated Financial Statements for further discussion of the Company’s hedging activities.
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Commitments and Contingencies
Several West Virginia lessors claimed in a suit filed on July 31, 2006 that EQT Production Company had underpaid royalties on gas produced and marketed from leases. The suit sought compensatory and punitive damages, an accounting and other relief. The plaintiffs later amended their complaint to name EQT as an additional defendant. The Company has settled the litigation. The settlement covers all of the Company’s lessors in West Virginia who have not opted out of the settlement class. The Court has entered its final order approving the settlement and certifying the settlement class on April 28, 2010. The Company believes the reserve established for this litigation is sufficient.
In the ordinary course of business, various other legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves it believes to be appropriate for other pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
Dividend
On April 21, 2010, the Board of Directors declared a regular quarterly cash dividend of $0.22 per share, payable June 1, 2010, to shareholders of record on May 7, 2010.
Critical Accounting Policies
The Company’s critical accounting policies are described in the notes to the Company’s Consolidated Financial Statements for the year ended December 31, 2009 contained in the Company’s Annual Report on Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements which have a material impact on the Company have been included in the notes to the Company’s Condensed Consolidated Financial Statements for the period ended March 31, 2010. The application of the Company’s critical accounting policies may require management to make judgments and estimates about the amounts reflected in the Condensed Consolidated Financial Statements. Management uses historical experience and all available information to make these estimates and judgments, and different amounts could be reported using different assumptions and estimates.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Derivative Commodity Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily through the EQT Production and EQT Midstream segments. The Company’s use of derivatives to reduce the effect of this volatility is described in Note C to the Condensed Consolidated Financial Statements and under the caption “Commodity Risk Management” in Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q. The Company uses non-leveraged derivative commodity instruments that are placed with major financial institutions whose creditworthiness is continually monitored. The Company also enters into energy trading contracts to leverage its assets and limit its exposure to shifts in market prices. The Company’s use of these derivative financial instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and Board of Directors.
Commodity Price Risk
The following sensitivity analysis estimates the potential effect on fair value or future earnings from derivative commodity instruments due to a 10% increase and a 10% decrease in commodity prices.
For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels which are exposed to price risk. For the derivative commodity instruments used to hedge forecasted natural gas purchases and sales which are exposed to price risk, the Company sets limits related to acceptable exposure levels.
The financial instruments currently utilized by the Company include futures contracts, swap agreements, collar agreements and option contracts which may require payments to or receipt of payments from counterparties based on the differential between a fixed and variable price for the commodity. The Company also considers other contractual agreements in determining its commodity hedging strategy.
Management monitors price and production levels on a continuous basis and will make adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to ensure an adequate level of return for the well development and infrastructure investment at EQT Production and EQT Midstream.
With respect to the derivative commodity instruments held by the Company for purposes other than trading as of March 31, 2010, the Company hedged portions of expected equity production through 2015 and portions of forecasted purchases and sales by utilizing futures contracts, swap agreements, collar agreements and option contracts covering approximately 117.1 Bcf of natural gas. See the “Commodity Risk Management” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-Q for further discussion. A hypothetical decrease of 10% in the market price of natural gas from the March 31, 2010 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $48.4 million. A hypothetical increase of 10% in the market price of natural gas from the March 31, 2010 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $47.0 million.
The Company determined the change in the fair value of the derivative commodity instruments using a model similar to its normal determination of fair value as described in Note 4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. The Company assumed a 10% change in the price of natural gas from its levels at March 31, 2010. The price change was then applied to the derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheet, resulting in the change in fair value.
The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company and its subsidiaries’ physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments
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held for risk management purposes associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the physical derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Other Market Risks
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value. The Company believes that NYMEX-traded futures contracts have minimal credit risk because the Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s swap, collar and option derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various information technology systems to monitor and evaluate its credit risk exposures. This includes closely monitoring current market conditions, counterparty credit spreads and credit default swap rates. Credit exposure is controlled through credit approvals and limits. To manage the level of credit risk, the Company enters transactions with financial counterparties that are of investment grade, enters into netting agreements whenever possible and may obtain collateral or other security.
Approximately 70%, or $234.7 million, of OTC derivative contracts outstanding at March 31, 2010 have a positive fair value. All derivative contracts outstanding as of March 31, 2010 are with counterparties having an S&P rating of A- or above at that date.
As of March 31, 2010, the Company is not in default under any derivative contracts and has no knowledge of default by any counterparty to derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheet.
The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas. A significant amount of revenues and related accounts receivable from EQT Production are generated from the sale of produced natural gas to certain marketers, including the Company’s wholly-owned marketing subsidiary EQT Energy, and utility and industrial customers located mainly in the Appalachian Basin area. Additionally, a significant amount of revenues and related accounts receivable from EQT Midstream are generated from the sale of produced natural gas liquids to a gas processor in Kentucky and gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.
The Company has a $1.5 billion revolving credit facility that matures on October 26, 2011. The credit facility is underwritten by a syndicate of 15 financial institutions each of which is obligated to fund its pro-rata portion of any borrowings by the Company. Lehman Brothers Bank, FSB (Lehman) is one of the 15 financial institutions in the syndicate and has committed to make loans not exceeding $95 million under the facility. Lehman failed to fund its portion of all recent borrowings by the Company which effectively reduces the total amount available under the facility to $1,405 million. As of March 31, 2010, the Company had no loans outstanding under the facility. The Company had a $23.9 million irrevocable standby letter of credit at March 31, 2010.
No one lender of the 15 financial institutions in the syndicate holds more than 10% of the facility. The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure if further problems or consolidation occur in the banking industry.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (“the Exchange Act”)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the first quarter of 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Kay Company, LLC et al v. EQT Production Company et al, U.S. District Court, Southern District of West Virginia
In addition to the claim disclosed above, in the ordinary course of business various other legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company has established reserves it believes to be appropriate for other pending matters, and after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any other matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.
Item 1A. Risk Factors
Information regarding risk factors is discussed in Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 2009. There have been no material changes from the risk factors previously disclosed in the Company’s Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table sets forth the Company’s repurchases of equity securities registered under Section 12 of the Exchange Act that occurred in the three months ended March 31, 2010.
Period
Totalnumber ofshares (or units)purchased(a)
Averageprice paidper share(or unit)
Total number ofshares (or units)purchased as partof publiclyannounced plansor programs
Maximum number (orapproximate dollarvalue) of shares (orunits) that may yet bepurchased under theplans or programs
January 2010(January 1 – January 31)
2,484
$ 44.03
February 2010(February 1 – February 28)
2,495
$ 44.37
March 2010(March 1 – March 31)
3,831
$ 43.72
8,810
(a) Comprised solely of Company-directed purchases made by the Company’s 401(k) plans.
Item 6. Exhibits
10.1
Form of Participant Award Agreement (Phantom Stock Unit Award)
31.1
Rule 13(a)-14(a) Certification of Principal Executive Officer
31.2
Rule 13(a)-14(a) Certification of Principal Financial Officer
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
101
Interactive Data File*
* In accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission, Exhibit 101 is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.
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.
(Registrant)
By:
/s/ Philip P. Conti
Philip P. Conti
Senior Vice President and Chief Financial Officer
Date: April 28, 2010
INDEX TO EXHIBITS
Exhibit No.
Document Description
Incorporated by Reference
Filed herewith as Exhibit 10.1
Filed herewith as Exhibit 31.1
Filed herewith as Exhibit 31.2
Filed herewith as Exhibit 32
Filed herewith as Exhibit 101