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 JUNE 30, 2006
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
EQUITABLE RESOURCES, INC.
(Exact name of registrant as specified in its charter)
PENNSYLVANIA
25-0464690
(State or other jurisdiction of
(IRS Employer
incorporation or organization)
Identification No.)
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (412) 553-5700
(Former name, former address and former fiscal year, if changed since last report)
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 ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b—2 of the Exchange Act.
Large Accelerated Filer x
Accelerated Filer o
Non-Accelerated Filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Outstanding at
Class
June 30, 2006
Common stock, no par value
120,674,630 shares
EQUITABLE RESOURCES, INC. AND SUBSIDIARIES
Index
Part I.
Financial Information:
Item 1.
Financial Statements (Unaudited):
Statements of Consolidated Income for the Three and Six Months Ended June 30, 2006 and 2005
Statements of Condensed Consolidated Cash Flows for the Six Months Ended June 30, 2006 and 2005
Condensed Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005
Notes to Condensed Consolidated Financial Statements
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
Part II.
Other Information:
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Submission of Matters to a Vote of Security Holders
Item 5.
Other Information
Item 6.
Exhibits
Signature
Index to Exhibits
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Consolidated Income (Unaudited)
Three Months EndedJune 30,
Six Months EndedJune 30,
2006
2005
(Thousands, except per share amounts)
Operating revenues
$
251,207
230,194
681,326
631,470
Cost of sales
86,113
75,917
294,930
264,648
Net operating revenues
165,094
154,277
386,396
366,822
Operating expenses:
Operation and maintenance
25,366
24,865
48,970
48,708
Production
15,670
15,026
31,789
29,196
Selling, general and administrative
28,050
30,492
57,755
54,119
Office consolidation impairment charges
(2,908
)
7,316
7,835
Depreciation, depletion and amortization
24,797
23,119
49,014
46,309
Total operating expenses
90,975
100,818
184,620
186,167
Operating income
74,119
53,459
201,776
180,655
Gain on sale and tender of available-for-sale securities, net
—
60,819
Equity in earnings of nonconsolidated investments
(124
108
50
197
Other income, net
57
1,195
Interest expense
9,995
9,988
22,952
22,175
Income from continuing operations before income taxes
64,000
104,455
178,874
220,691
Income taxes
20,091
46,502
62,606
87,947
Income from continuing operations
43,909
57,953
116,268
132,744
Income from discontinued operations, net of tax of $1,433 and $2,484 for the three and six months ended June 30, 2005, respectively
6,366
7,981
Net income
64,319
140,725
Earnings per share of common stock:
Basic:
Weighted average common shares outstanding
120,128
121,472
119,823
0.37
0.48
0.97
1.09
Income from discontinued operations
0.05
0.07
0.53
1.16
Diluted:
122,044
123,990
121,899
124,186
0.36
0.47
0.95
1.07
0.06
0.52
1.13
Dividends declared per common share
0.22
0.21
0.43
0.40
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
3
Statements of Condensed Consolidated Cash Flows (Unaudited)
(Thousands)
Cash flows from operating activities:
Adjustments to reconcile net income to cash provided by operating activities:
Income from discontinued operations, net of tax
(7,981
Provision for losses on accounts receivable
614
5,260
Depreciation, depletion, and amortization
(60,819
Deferred income taxes
5,899
(58,688
Excess tax benefits from share-based payment arrangements
(5,758
Decrease in inventory
908
14,793
Decrease in accounts receivable and unbilled revenues
158,688
102,333
Decrease (increase) in margin deposits
199,837
(173,647
Decrease in accounts payable
(78,919
(7,477
Changes in other assets and liabilities
(45,770
(42,428
Total adjustments
281,605
(174,510
Net cash provided by (used in) continuing operating activities
397,873
(33,785
Net cash used in discontinued operating activities
(29,176
Net cash provided by (used in) operating activities
(62,961
Cash flows from investing activities:
Capital expenditures
(153,416
(120,651
Investment in available-for-sale securities
(2,201
(3,606
Proceeds from sale of Kerr-McGee shares
354,319
Proceeds from sale of properties
130,213
Restricted cash from sale of properties
(30,000
Purchase of interest in Eastern Seven Partners, L.P.
(57,500
Net cash (used in) provided by continuing investing activities
(155,617
272,775
Net cash (used in) provided by discontinued investing activities
(724
2,709
Net cash (used in) provided by investing activities
(156,341
275,484
Cash flows from financing activities:
Dividends paid
(51,729
(48,711
Purchase of treasury stock
(52,887
Proceeds from exercises under employee compensation plans
16,274
20,771
5,758
Repayments and retirements of long-term debt
(10,000
Decrease in short-term loans
(286,801
(139,000
Net cash used in continuing financing activities
(316,498
(229,827
Net cash provided by discontinued financing activities
17,304
Net cash used in financing activities
(212,523
Net decrease in cash and cash equivalents
(74,966
Cash and cash equivalents at beginning of period
74,966
Cash and cash equivalents at end of period
Cash paid during the period for:
Interest, net of amount capitalized
22,972
25,639
Income taxes, net of refund
30,448
113,536
4
Condensed Consolidated Balance Sheets (Unaudited)
June 30,2006
December 31,2005
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable (less accumulated provision for doubtful accounts: June 30, 2006, $22,699; December 31, 2005, $23,329)
137,537
249,397
Unbilled revenues
11,516
58,958
Margin deposits with financial institutions
117,995
317,832
Inventory
289,013
289,921
Derivative instruments, at fair value
44,642
42,899
Prepaid expenses and other
54,293
60,732
Assets held for sale from discontinued operations
2,518
Total current assets
654,996
1,097,223
Equity in nonconsolidated investments
35,116
35,555
Property, plant and equipment
3,328,885
3,236,097
Less: accumulated depreciation and depletion
1,154,418
1,152,892
Net property, plant and equipment
2,174,467
2,083,205
Investments, available-for-sale
27,873
25,194
Other assets
98,642
101,108
Total assets
2,991,094
3,342,285
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt
3,000
Short-term loans
78,499
365,300
Accounts payable
163,699
242,618
852,920
1,264,204
Other current liabilities
146,671
217,374
Total current liabilities
1,244,789
2,092,496
Debentures and medium-term notes
763,434
Deferred income taxes and investment tax credits
199,190
24,042
Other credits
98,048
107,845
Common stockholders’ equity:
Common stock, no par value, authorized 320,000 shares; shares issued: June 30, 2006 and December 31, 2005, 149,008
363,971
358,684
Treasury stock, shares at cost: June 30, 2006, 28,332; December 31, 2005, 29,102 (net of shares and cost held in trust for deferred compensation of 156, $2,680 and 142, $2,429)
(484,550
(496,511
Retained earnings
1,312,434
1,247,895
Accumulated other comprehensive loss
(506,222
(755,600
Total common stockholders’ equity
685,633
354,468
Total liabilities and stockholders’ equity
5
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 report, unless the context requires otherwise, references to “we,” “us,” “our,” or the “Company” are intended to mean Equitable Resources, Inc. 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 Equitable Resources, Inc. and subsidiaries as of June 30, 2006, and the results of its operations and cash flows for the three and six-month periods ended June 30, 2006 and 2005.
Certain Condensed Consolidated Financial Statements and related footnote disclosures have been reclassified to reflect the operating results and cash flows of the discontinued NORESCO segment for the three and six-month periods ended June 30, 2005, as discontinued operations. Additionally, certain previously reported amounts have been reclassified to conform to the current year presentation.
The balance sheet at December 31, 2005 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 energy marketing businesses and the volatility of natural gas prices, the interim statements for the three and six-month periods ended June 30, 2006 are not necessarily indicative of the results that may be expected for the year ending December 31, 2006.
For further information, refer to the consolidated financial statements and footnotes thereto included in Equitable Resources’ Annual Report on Form 10-K for the year ended December 31, 2005, as well as in “Information Regarding Forward Looking Statements” on page 17 of this document.
B. Segment Information
The Company reports its operations in two segments, which reflect its lines of business. The Equitable Utilities segment’s operations comprise the sale and transportation of natural gas to customers at state-regulated rates, interstate pipeline gathering, transportation and storage of natural gas subject to federal regulation, the unregulated marketing of natural gas and limited trading activities. The Equitable Supply segment’s activities comprise the development, production, gathering, marketing and sale of natural gas and a small amount of associated oil and the extraction and sale of natural gas liquids. In December 2005, the Company discontinued and sold the operations of its NORESCO segment, which provided energy efficiency solutions to customers including governmental, military, institutional, commercial and industrial end-users.
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, net. 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. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments.
Substantially all of the Company’s operating revenues, income from continuing operations and assets are generated or located in the United States.
Effective January 1, 2006, certain gathering systems consisting of 1,400 miles of pipeline and related facilities with approximately 13.3 Bcf of annual throughput were transferred from Equitable Supply to Equitable Utilities for segment reporting purposes. The effect of the transfer is not material to the results of operations or financial position of the Equitable Utilities or Equitable Supply segments; segment results have not been restated for this transfer.
6
Revenues from external customers:
Equitable Utilities
139,027
137,904
473,725
436,972
Equitable Supply
119,327
112,209
241,776
225,484
Less: intersegment revenues (a)
(7,147
(19,919
(34,175
(30,986
Total
Total operating expenses:
31,900
36,386
69,731
73,279
53,884
49,039
104,350
96,961
Unallocated expenses
5,191
15,393
10,539
15,927
Operating income:
13,867
5,682
74,889
68,059
65,443
63,170
137,426
128,523
(5,191
(15,393
(10,539
(15,927
Reconciliation of operating income to net income:
Equity in earnings of nonconsolidated investments:
83
(18
130
Unallocated
25
68
67
Other income, net (b)
June 30,
December 31,
Segment Assets:
1,257,162
1,412,215
1,665,886
1,844,883
Total operating segments
2,923,048
3,257,098
Headquarters assets, including cash and short-term investments
68,046
82,669
Total operating assets
3,339,767
7
Expenditures for segment assets:
13,626
11,786
29,080
21,573
Equitable Supply (c)
68,615
59,182
122,527
147,813
Unallocated expenditures
541
5,910
1,809
8,765
82,782
76,878
153,416
178,151
(a) Intersegment revenues primarily represent sales from Equitable Supply to the unregulated marketing affiliate of Equitable Utilities.
(b) Unallocated other income, net for the six months ended June 30, 2005 relates to pre-tax dividend income of $1.2 million for Kerr-McGee Corporation shares.
(c) Capital expenditures for the six months ended June 30, 2005 include $57.5 million for the acquisition of the 99% limited partnership interest in Eastern Seven Partners, L.P.
C. Derivative Instruments
Natural Gas Hedging Instruments
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. 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. Exchange-traded instruments are generally settled with offsetting positions. Over the Counter (OTC) arrangements require settlement in cash. The fair value of these derivative commodity instruments was a $44.6 million asset and a $815.2 million liability as of June 30, 2006, and a $36.0 million asset and a $1.2 billion liability as of December 31, 2005. These amounts are included in the Condensed Consolidated Balance Sheets as derivative instruments, at fair value. The net amount of derivative instruments, at fair value, changed from a net liability of $1.2 billion at December 31, 2005 to a net liability of $770.6 million at June 30, 2006, primarily as a result of the 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 443.5 Bcf and 383.5 Bcf as of June 30, 2006 and December 31, 2005, respectively, and primarily related to natural gas swaps. The open positions at June 30, 2006 had maturities extending through December 2013.
The Company deferred net losses of $492.1 million and $741.0 million in accumulated other comprehensive loss, net of tax, as of June 30, 2006 and December 31, 2005, respectively, associated with the effective portion of the change in fair value of its derivative instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $137.7 million of net unrealized losses on its derivative commodity instruments reflected in accumulated other comprehensive loss, net of tax, as of June 30, 2006 will be recognized in earnings during the next twelve months. This recognition occurs through a reduction in the Company’s net operating revenues resulting in the average hedged price becoming the realized sales price.
For the three months ended June 30, 2006 and 2005, ineffectiveness associated with the Company’s derivative instruments designated as cash flow hedges increased (decreased) earnings by approximately $0.2 million and ($0.5) million, respectively. These amounts are included in operating revenues in the Statements of Consolidated Income.
The Company conducts trading activities through its unregulated marketing group. The function of the Company’s trading business is to contribute to the Company’s earnings by taking market positions within defined limits subject to the Company’s corporate risk management policy.
The absolute notional quantities of the futures and swaps held for trading purposes at June 30, 2006 totaled 1.3 Bcf and 31.8 Bcf, respectively.
8
Below is a summary of the activity of the fair value of the Company’s derivative commodity contracts with third parties held for trading purposes during the six months ended June 30, 2006 (in thousands).
Fair value of contracts outstanding as of December 31, 2005
(330
Contracts realized or otherwise settled
(313
Other changes in fair value
1,646
Fair value of contracts outstanding as of June 30, 2006
1,003
The following table presents maturities and the fair valuation source for the Company’s derivative commodity instruments that are held for trading purposes as of June 30, 2006.
Source of Fair Value
MaturityLess than1 Year
Maturity1-3 Years
Maturity4-5 Years
Maturity inExcess of5 Years
Total FairValue
Prices actively quoted (NYMEX) (1)
983
Prices provided by other external sources (2)
1
19
20
Net derivative assets
984
(1) Contracts include futures and fixed price swaps
(2) Contracts include basis swaps
When the net fair value of any of the 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 recorded such deposits in the amount of $117.8 million as margin deposits with financial institutions in its Condensed Consolidated Balance Sheet as of June 30, 2006.
When the Company enters into exchange-traded natural gas contracts, exchanges require participants, including 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. The initial margin requirements are established by the exchanges based on prices, volatility and the time to expiration of the related contract and are subject to change at the exchanges’ discretion. The Company recorded such deposits in the amount of $0.2 million as margin deposits in its Condensed Consolidated Balance Sheet at June 30, 2006.
The fair value of derivative instruments assumed as part of the purchase of the limited partnership interest in Eastern Seven Partners, L.P. (ESP) in January 2005 was a $20.2 million liability at June 30, 2006. The fair value of derivative instruments associated with forecasted production at non-core gas properties sold in May 2005 was a $17.5 million liability at June 30, 2006. The Company does not treat these derivatives as hedging instruments under Statements of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). These amounts are included in the Condensed Consolidated Balance Sheet as derivative instruments, at fair value. See Note L for further discussion of the related transactions.
D. Investments
As of June 30, 2006, the investments classified by the Company as available-for-sale consist of approximately $27.9 million of equity securities intended to fund plugging and abandonment and other liabilities for which the Company self-insures.
Any unrealized gains or losses with respect to investments classified as available-for-sale are recognized within the Consolidated Balance Sheets as a component of equity, accumulated other comprehensive loss. The Company utilizes the specific identification method to determine the cost of all investment securities sold.
In May 2005, the Company terminated three variable share forward transactions. In connection with the termination, the Company incurred a termination cost of $95.8 million and sold 4.3 million Kerr-McGee shares to its three counterparties at an average price of $75.43 per share to cover its counterparties’ respective hedged positions. The Company received $227.4 million in pre-tax proceeds from the sale of the Kerr-McGee shares net of the termination cost. In addition, the Companyunconditionally tendered 1.7 million Kerr-McGee shares at $85.00 per share to Kerr-McGee in connection with Kerr-McGee’s Dutch auction tender offer to purchase its own shares. Accordingly, as a result of its tender of shares, the Company received approximately $49 million in pre-tax proceeds on the sale of approximately 0.6 million shares.
9
In April 2005, the Company sold approximately 1.0 million unhedged Kerr-McGee shares for total proceeds of $77.9 million. The sale of these remaining shares resulted in a pre-tax gain to the Company of $26.7 million.
In the first six months of 2005, the Company recorded dividend income on its investment in Kerr-McGee Corporation of $1.2 million, which is recorded in other income, net on the Statement of Consolidated Income for the six months ended June 30, 2005.
E. Comprehensive Income (Loss)
Total comprehensive income (loss), net of tax, was as follows:
Other comprehensive income (loss):
Net change in cash flow hedges:
Natural gas (Note C)
49,563
(50,655
248,954
(243,827
Interest rate
29
58
Unrealized (loss) gain on investments, available-for-sale:
Kerr-McGee
(43,782
50,047
Other
(389
(7
366
(107
Unrealized loss on collars on hedged Kerr-McGee shares
(66,792
Total comprehensive income (loss)
93,112
(30,096
365,646
(119,896
The components of accumulated other comprehensive loss, net of tax, are as follows:
Net unrealized loss from hedging transactions
(492,792
(741,804
Unrealized gain on available-for-sale securities
1,936
1,570
Minimum pension liability adjustment
(15,366
F. Share-Based Compensation
The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R) as of January 1, 2006. The Company previously accounted for share-based compensation transactions using the intrinsic value method of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25). Under SFAS No. 123R, an entity must recognize the compensation cost related to employee services received in exchange for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The compensation cost of the award is generally measured based on the grant-date fair value of the award.
The Company adopted SFAS No. 123R using the modified prospective method. Under the modified prospective method, compensation cost is recognized beginning with the effective date and prior period results are not restated. As such, compensation cost related to all share-based awards was recorded as selling, general and administrative expense in the Company’s Statement of Consolidated Income for the three and six months ended June 30, 2006.
10
The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123R to employee share-based awards for the three and six months ended June 30, 2005.
Three Months EndedJune 30, 2005
Six Months EndedJune 30, 2005
Net income, as reported
Add: Gross share-based employee compensation expense included in reported net income
13,190
17,103
Deduct: Income tax benefit from share-based employee compensation expense included in reported net income
(4,473
(5,870
Deduct: Total share-based employee compensation expense determined under fair value method for all awards, net of related tax effects
(9,222
(12,442
Pro forma net income
63,814
139,516
Earnings per share:
Basic, as reported
Basic, pro forma
1.15
Diluted, as reported
Diluted, pro forma
0.51
1.12
Adoption of SFAS No. 123R had the effect of reducing operating income and income from continuing operations before income taxes by $0.1 million and $0.7 million for the three and six month periods ended June 30, 2006, respectively. Prior to the adoption of SFAS No. 123R, the Company presented all tax benefits for deductions resulting from the exercise of share-based awards as cash flows from operating activities in its statements of condensed consolidated cash flows. SFAS No. 123R requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a cash flow from financing activities, rather than as a cash flow from operating activities. This requirement reduced cash flows from operating activities and increased cash flows from financing activities by $5.8 million for the six months ended June 30, 2006. Total net cash flows were not impacted by the adoption of SFAS No. 123R.
Executive Performance Incentive Programs
The vesting of the units granted under the Executive Performance Incentive Program (2005 Program) will occur contingent upon a combination of the level of total shareholder return relative to a fixed group of peer companies and the Company’s average absolute return on total capital during the four year performance period. The Company anticipates, based on current estimates, that a certain level of performance will be met. The 2005 Program expense for the six months ended June 30, 2006 was $10.1 million and is classified as selling, general and administrative expense in the Statements of Consolidated Income. A portion of the 2005 Program expense is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note B.
Restricted Stock Awards
The Company granted 88,200 and 74,900 restricted stock awards during the six months ended June 30, 2006 and 2005, respectively, to key executives of the Company. These awards will be fully vested at the end of the three-year period commencing the date of grant. The fair value of each share is equal to the market price of the Company’s common stock on the date of grant. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s stock, was $35.75 and $29.44, for the six months ended June 30, 2006 and 2005, respectively. The total intrinsic value of restricted stock awards vested during the six months ended June 30, 2006 and 2005 was $1.5 million and $1.8 million, respectively. Compensation expense recorded by the Company related to restricted stock awards was $1.6 million and $1.4 million for the six month periods ended June 30, 2006 and 2005, respectively.
11
As of June 30, 2006, there was $6.6 million of total unrecognized compensation cost related to nonvested restricted stock awards. That cost is expected to be recognized over a weighted average period of approximately 15.8 months.
A summary of restricted stock activity as of June 30, 2006, and changes during the six months then ended, is presented below:
Restricted Stock
Non-VestedShares
WeightedAverageFair Value
WeightedAverageRemainingContractualTerm
AggregateFair Value
Outstanding at January 1, 2006
520,435
22.82
11,877,895
Granted
88,200
35.75
3,152,775
Vested
(77,115
18.91
(1,458,367
Forfeited
(12,680
28.86
(365,928
Outstanding at June 30, 2006
518,840
25.45
15.8 months
13,206,375
Stock Options
The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the six month periods ended June 30, 2006 and 2005. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The dividend yield is based on the historical dividend yield of the Company’s stock. Expected volatilities are based on historical volatility of the Company’s stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience.
Six Months Ended June 30,
Risk-free interest rate
4.59% to 5.04%
3.74% to 4.34%
Dividend yield
2.34% to 2.38%
2.75% to 2.83%
Volatility factor
.212 to .226
.258 to .262
Expected term
7 years
The Company granted 56,257 and 68,898 stock options during the six months ended June 30, 2006 and 2005, respectively, all of which comprised options granted for reload rights associated with previously-awarded options. The weighted average grant date fair value of these reload option grants was $9.07 and $7.65 for the six month periods ended June 30, 2006 and 2005, respectively. The total intrinsic value of options exercised during the six month periods ended June 30, 2006 and 2005 was $19.7 million and $43.5 million, respectively.
As of June 30, 2006, there was no unrecognized compensation cost related to outstanding nonvested stock options as all outstanding options were fully vested.
12
A summary of option activity as of June 30, 2006, and changes during the six months then ended, is presented below:
Nonqualified Stock Options
Shares
WeightedAverageExercisePrice
AggregateIntrinsicValue
5,110,421
16.32
56,257
35.93
Exercised
(1,003,792
17.20
(4,716
17.46
4,158,170
16.37
5.2 years
71,368,543
Exercisable at June 30, 2006
Nonemployee Directors’ Stock Incentive Plans
At June 30, 2006, 160,904 options were outstanding under the 1999 Nonemployee Directors’ Stock Incentive Plan at prices ranging from $6.59 to $29.67 per share, and 537,200 options had been exercised under this plan since plan inception. The exercise price for each award is equal to the market price of the Company’s common stock on the date of grant. Each option is subject to time-based vesting provisions and expires 5 to 10 years after date of grant.
The Company has also historically granted to non-employee directors stock units which vested upon award. The value of the stock units will be paid in cash on the earlier of the director’s death or retirement from the Company’s Board of Directors. A total of 72,960 non-employee director stock units were outstanding as of June 30, 2006. A total of 18,000 stock units were granted to non-employee directors during each of the six month periods ended June 30, 2006 and 2005.
Cash received from exercises under all share-based payment arrangements for employees and directors for the six month periods ended June 30, 2006 and 2005, was $16.3 million and $20.8 million, respectively. The actual tax benefit realized for tax deductions from share-based payment arrangements for the six month periods ended June 30, 2006 and 2005, was $7.5 million and $16.4 million, respectively.
The Company typically funds restricted share obligations from treasury stock at the date of grant and has a policy of issuing shares from treasury stock to satisfy option exercises.
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, extraordinary items and cumulative effects of accounting changes. The Company currently estimates the annual effective income tax rate from continuing operations as of June 30, 2006 to be 35.0%. The estimated annual effective income tax rate as of June 30, 2005 was 34.5%, excluding the tax benefit disallowances recorded in 2005 under Section 162(m) of the Internal Revenue Code.
13
H. Pension and Other Postretirement Benefit Plans
The Company’s costs related to its defined benefit pension and other postretirement benefit plans for the three and six months ended June 30, 2006 and 2005 were as follows:
Pension Benefits
Other Benefits
Three Months Ended June 30,
Components of net periodic (benefit) cost
Service cost
225
138
135
Interest cost
1,097
1,436
725
792
Expected return on plan assets
(1,533
(1,985
Amortization of prior service cost
93
192
(34
(10
Recognized net actuarial loss
267
209
536
551
Settlement loss
(109
1,725
Net periodic benefit cost
(77
1,802
1,365
1,468
216
450
276
270
2,194
3,134
1,450
1,584
(3,066
(4,091
186
383
(68
(21
534
489
1,072
1,103
2,181
46
2,546
2,730
2,936
I. Recently Issued Accounting Standards
Accounting for Uncertain Tax Positions
In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Tax Positions — an Interpretation of FASB Statement No. 109.” The Interpretation applies to all open tax positions accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes.” This Interpretation is intended to result in increased relevance and comparability in financial reporting of income taxes and to provide more information about the uncertainty in income tax assets and liabilities. This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact of this Interpretation on the Company’s financial position and results of operations.
Earnings Per Share
In September 2005, the FASB issued an exposure draft of a proposed amendment to SFAS No. 128, “Earnings Per Share.” The proposed amendment would clarify guidance for calculating earnings per share in regards to mandatorily convertible instruments, the treasury stock method, contracts that may be settled in cash or shares and contingently issuable shares. The FASB has delayed issuance of the final amendment until it completes additional deliberations. The Company will evaluate the impact of any change in accounting standard when the final interpretation is issued.
Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans
In March 2006, the FASB issued an exposure draft of a proposed amendment to SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106.” The proposed amendment would improve existing reporting for defined benefit postretirement plans. Under the exposure draft,
14
the proposed amendment would become effective for the Company in the fourth quarter of 2006, generally on a retrospective basis. The Company will evaluate the impact of any change in accounting standards on the Company’s financial position and results of operations when the final interpretation is issued.
J. Discontinued Operations
In the fourth quarter of 2005, the Company sold its NORESCO domestic business for $82 million before customary purchase price adjustments.
In the second quarter of 2006, the Company completed the sale of the remaining interest in its investment in IGC/ERI Pan-Am Thermal Generating Limited (Pan Am), previously included in the NORESCO business segment, for total proceeds of $2.6 million.
Total operating revenues reclassified to discontinued operations for the three and six month periods ended June 30, 2005 were $38.8 million and $77.3 million, respectively.
K. Office Consolidation / Impairment Charges
In May 2005, the Company completed the relocation of its corporate headquarters and other operations to a newly constructed office building located at the North Shore in Pittsburgh. The relocation resulted in the early termination of several operating leases and the early retirement of assets and leasehold improvements at several locations. In accordance with SFAS No. 146, “Accounting for Costs associated with Exit or Disposal Activities” (SFAS No. 146), the Company recognized a loss of $5.3 million on the early termination of operating leases during the three months ended June 30, 2005 for facilities deemed to have no economic benefit to the Company. The Company also recognized a loss on impairment of assets of $2.0 million during the second quarter of 2005 and $0.5 million in the first quarter of 2005 in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144), associated with the office consolidations.
During the second quarter of 2006, the Company began to utilize certain of the leased space previously deemed to have no economic benefit to the Company, to make space available for the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. transition planning activities. The Company reversed approximately $2.4 million of the associated early termination liability for these leases during the three months ended June 30, 2006. Additionally, the Company recorded a $0.5 million reduction in the early termination liability during the three months ended June 30, 2006 resulting from a revision of the amount of estimated cash flows for one of its operating leases.
L. Other Events
On April 5, 2006, the Federal Energy Regulatory Commission (FERC) approved a settlement to resolve all issues raised in Equitrans, L.P.’s rate case filings. According to its terms, the settlement became effective on June 1, 2006. The settlement’s approval, which was recognized in the first quarter of 2006, improved operating income by $6.9 million for the first quarter of 2006, including $5.4 million relating to years 2005 and prior.
On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution and midstream assets in Pennsylvania and its natural gas distribution assets in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc.
The transaction requires approvals from the Pennsylvania Public Utility Commission and the Public Service Commission of West Virginia and is subject to review under the Hart-Scott-Rodino Act and by the Pennsylvania Attorney General. The Company is targeting regulatory approval by the end of 2006. The Company plans to finance the transaction through a combination of equity and debt issuances and possibly hybrid issuances and/or asset sales.
15
In January 2005, the Company purchased the 99% limited partnership interest in ESP for cash of $57.5 million and assumed liabilities of $47.3 million.
In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $142 million after purchase price adjustments.
M. Stock Split
On July 13, 2005, the Board of Directors of the Company declared a two-for-one stock split payable September 1, 2005, to shareholders of record on August 12, 2005. All share and per share information as of and for the three and six months ended June 30, 2005 has been retroactively adjusted to reflect the stock split.
16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
INFORMATION REGARDING FORWARD LOOKING 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 “should,” “anticipate,” “estimate,” “forecasts,” “approximate,” “expect,” “may,” “will,” “project,” “intend,” “plan,” “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 this 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 program, production and sales volumes, liquidity, capital expenditures and earnings and the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. and the financing of that acquisition. A variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the Company’s forward-looking statements. 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, 2005.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statements, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Three Months Ended June 30, 2006vs. Three Months Ended June 30, 2005
Equitable Resources’ consolidated income from continuing operations for the three months ended June 30, 2006 totaled $43.9 million, or $0.36 per diluted share, compared to $58.0 million, or $0.47 per diluted share, reported for the same period a year ago. This $14.1 million decrease in income from continuing operations from 2005 to 2006 was largely due to several unusual items in 2005 including the gain on the sale of Kerr-McGee shares, a negative tax impact related to a tax benefit disallowance under Section 162(m) of the Internal Revenue Code and office relocation costs. Excluding the unusual items, income from continuing operations increased primarily due to an increase in revenues in the Pipeline business as a result of the Equitrans rate case settlement, an increase in Energy Marketing revenues, an increase in production sales volumes, an increase in the average gathering fee and a reduction in allowance for doubtful accounts. These factors were partially offset by increased operating expenses and a decrease in the average well-head sales price.
Six Months Ended June 30, 2006vs. Six Months Ended June 30, 2005
Equitable Resources’ consolidated income from continuing operations for the six months ended June 30, 2006 totaled $116.3 million, or $0.95 per diluted share, compared to $132.7 million, or $1.07 per diluted share, reported for the same period a year ago. This $16.4 million decrease in income from continuing operations from 2005 to 2006 was largely due to the unusual factors explained above as well as a pre-tax dividend income on Kerr-McGee shares recognized in the first quarter of 2005. Excluding the unusual items, income from continuing operations increased due to the approval and settlement of the previously reported Equitrans rate case, an increase in Energy Marketing revenues, an increase in production sales volumes, an increase in the average gathering fee and a reduction in allowance for doubtful accounts. These factors were partially offset by warmer weather and lower gas customer usage in 2006 and increases in operating costs.
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. Equitable’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 Equitable’s segments without being obscured by the financial condition, operations and trends for other segment or by the effects of corporate allocations of interest and income taxes. In addition, management uses these measures for budget planning purposes.
17
EQUITABLE UTILITIES
OVERVIEW
Customer Payment Assistance Programs
The gas cost rates effective for Equitable Gas Company’s residential and commercial customers beginning October 1, 2005, include then-current high natural gas commodity prices, resulting in residential rates in the first and second quarters of 2006 as much as 40% higher than those in place in 2005. These increases could present a significant challenge to the Company’s low-income customers, especially during the winter months. Under various government- and Company-managed programs, significant funds were provided to assist low-income customers in re-establishing and maintaining their service during the 2005-2006 winter heating season. These programs enabled Equitable Gas to improve its bad debt expense in the first and second quarters of 2006 as compared to the first and second quarters of 2005 despite the high natural gas commodity prices. In addition, due to continued improvements in collection experience, the Company was able to reduce its overall reserve for uncollectible accounts during the second quarter of 2006. The Company will continue to closely monitor its collections rates and adjust its reserve for uncollectible accounts as necessary.
Pipeline Rate Case Settlement
On April 5, 2006, the Federal Energy Regulatory Commission (FERC) approved a settlement to resolve all issues raised in Equitrans’ rate case filings. The settlement provides for the following:
· An overall cost of service underlying the settled rates of $62.8 million, which was derived on a global basis; an expected annual revenue increase of $6.0 million and an expected operating income increase of $3.2 million
· Replenishment of 7.1 Bcf of migrated base gas from prior periods
· Consolidation of transmission assets into a single transmission system with a system-wide rate
· Consolidation of gathering assets into a single gathering system with a system-wide rate
· Tracking and recovery of ongoing Pipeline Safety Act and Security related costs
· Redesigned contract storage services
· Five-year rate moratorium on gathering rates
· Three-year rate moratorium on transmission rates
According to its terms, the settlement became effective on June 1, 2006. The settlement’s approval, which was recognized in the first quarter of 2006, improved operating income by $6.9 million for the three months ended March 31, 2006, including $5.4 million relating to years 2005 and prior. On-going increases related to the new rates and related contract negotiations resulted in additional net increases of pipeline operating income of $1.8 million in the second quarter 2006 compared to the same quarter in the prior year.
Transfer of Gathering Assets
18
RESULTS OF OPERATIONS
%
OPERATIONAL DATA
Heating degree days (30 year normal average: Qtr — 705; YTD — 3,635)
565
597
(5.4
3,103
3,431
(9.6
Residential sales and transportation volumes (MMcf)
2,656
3,173
(16.3
12,861
15,546
(17.3
Commercial and industrial volumes (MMcf)
4,667
4,322
8.0
13,750
15,105
(9.0
Total throughput (MMcf) — Distribution Operations
7,323
7,495
(2.3
26,611
30,651
(13.2
Net operating revenues (thousands):
Distribution Operations (regulated):
Residential
16,648
17,754
(6.2
53,167
60,915
(12.7
Commercial & industrial
6,589
7,408
(11.1
22,668
28,650
(20.9
1,697
2,128
(20.3
3,204
4,517
(29.1
Total Distribution Operations
24,934
27,290
(8.6
79,039
94,082
(16.0
Pipeline Operations (regulated)
13,868
10,498
32.1
38,937
26,964
44.4
Energy Marketing
6,965
4,280
62.7
26,644
20,292
31.3
Total net operating revenues
45,767
42,068
8.8
144,620
141,338
2.3
Total operating expenses as a % of net operating revenues
69.70
86.49
(19.4
48.22
51.85
(7.0
Operating income (thousands):
Distribution Operations (regulated)
2,285
933
144.9
29,571
39,260
(24.7
5,150
835
516.8
19,348
9,254
109.1
6,432
3,914
64.3
25,970
19,545
32.9
Total operating income
144.1
10.0
Depreciation, depletion and amortization (DD&A):
Distribution Operations
4,962
4,664
6.4
9,887
9,228
7.1
Pipeline Operations
2,190
2,058
4,401
4,107
7.2
5.6
37
Total DD&A
7,171
6,740
14,325
13,372
Capital expenditures(thousands)
15.6
34.8
FINANCIAL DATA (Thousands)
Distribution revenues (regulated)
61,594
66,141
(6.9
283,303
269,871
5.0
Pipeline revenues (regulated)
14,239
35.6
39,636
47.0
Marketing revenues
75,840
71,243
6.5
181,237
167,348
8.3
Less: intrasegment revenues
(12,646
(9,978
26.7
(30,451
(27,211
11.9
Total operating revenues
0.8
8.4
Purchased gas costs
93,260
95,836
(2.7
329,105
295,634
11.3
Operating and maintenance (O & M)
14,642
14,571
0.5
28,257
28,517
(0.9
Selling, general and administrative (SG&A)
12,483
11,234
11.1
29,545
27,549
(2,396
3,841
(162.4
DD&A
(12.3
(4.8
Equitable Utilities’ operating income totaled $13.9 million for the three months ended June 30, 2006 compared to $5.7 million for the three months ended June 30, 2005. The $8.2 million increase in operating income is primarily due to the $6.2 million positive operating income impact from office consolidation impairment charges recorded in the second quarter of 2005 and a partial reversal of those charges in the second quarter of 2006, a $3.7 million increase in net operating revenues and a reduction in allowance for uncollectible accounts of $1.9 million. These positive variances were partially offset by $2.7 million of transition costs incurred in the second quarter of 2006 in planning for the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc.
Net operating revenues for the three months ended June 30, 2006 were $45.8 million compared to $42.1 million for the same quarter in 2005. The $3.7 million increase was due to increased revenues in the Pipeline business as a result of the previously reported Equitrans rate case settlement and increased marketing storage asset optimization opportunities realized in the high and volatile natural gas commodity price environment. These positive variances were partially offset by decreases in Distribution net operating revenues. Lower residential net operating revenues were the result of decreased throughput from warmer weather and lower customer usage in 2006 as a result of conservation due to customers’ sensitivity to high commodity prices. Lower net operating revenues from commercial and industrial customers resulted as warmer weather produced high levels of gas inventory and low commodity margins.
Operating expenses totaled $31.9 million for the three months ended June 30, 2006 compared to $36.4 million for the three months ended June 30, 2005. The $4.5 million decrease in operating expenses was primarily attributable to the 2005 office consolidation impairment charges of $3.8 million, the reversal of $2.4 million of office consolidation impairment charges in 2006, a decrease in bad debt expense of $1.9 million as the provision for uncollectible accounts was reduced, and a 2005 charge of $0.8 million for an enhanced severance program for certain represented employees. The reversal of lease impairment charges in the second quarter of 2006 was the result of the Company beginning to utilize certain leased space, previously deemed to have no economic benefit to the Company, to make space available for acquisition transition activities. As such, these expenses are now considered costs related to the acquisition. The Company’s improved collection experience, coupled with the regulatory and other assistance provided to assist low income customers, has allowed the Company to realize this improvement despite increased rates and customer bills. These positive variances were partially offset by $2.7 million of other transition planning costs related to the pending acquisition, an increase in gathering operating expense of $0.7 million due to increased
line-walking, right-of-way clearing and leak repair activities, $0.6 million of postretirement benefit expenses recognized in 2006 as a result of the Equitrans rate case settlement and an increase in DD&A of $0.4 million due to an increased depreciable asset base reflecting increased capital spending.
Capital expenditures totaled $13.6 million for the three months ended June 30, 2006 compared to $11.8 million for the three months ended June 30, 2005. The $1.8 million increase was due to increased expenditures for the automated meter reading program, which began in the second quarter of 2005 and is expected to be completed in the third quarter of 2006.
Equitable Utilities’ operating income totaled $74.9 million for the six months ended June 30, 2006 compared to $68.1 million for the six months ended June 30, 2005. The $6.8 million increase in operating income is primarily due to the $6.2 million positive operating impact from office consolidation impairment charges recorded in the second quarter of 2005 and a partial reversal of those charges in the second quarter of 2006, previously discussed, a reduction in allowance for uncollectible accounts of $3.8 million and a $3.3 million increase in net operating revenues. These positive variances were partially offset by $2.9 million of postretirement benefit expenses recognized in 2006 as a result of the Equitrans rate case settlement and $2.7 million of transition planning costs incurred in the second quarter of 2006 in planning for the pending acquisition.
Net operating revenues for the six months ended June 30, 2006 were $144.6 million compared to $141.3 million for the same period in 2005. The $3.3 million increase was due to increased revenues in the Pipeline business as a result of the previously reported Equitrans rate case settlement and increased marketing storage asset optimization opportunities realized in the high and volatile natural gas commodity price environment. These positive variances were partially offset by decreases in Distribution net operating revenues. Lower residential net operating revenues were the result of decreased throughput from warmer weather and lower customer usage in 2006 as a result of conservation due to customers’ sensitivity to high commodity prices. Lower net operating revenues from commercial and industrial customers resulted as warmer weather produced high levels of gas inventory and low commodity margins.
Operating expenses totaled $69.7 million for the six months ended June 30, 2006 compared to $73.3 million for the six months ended June 30, 2005. The $3.6 million decrease in operating expenses was primarily attributable to the $6.2 million positive impact from office consolidation impairment charges recorded in the second quarter of 2005 and a partial reversal of those charges in the second quarter of 2006 as previously discussed, a decrease in bad debt expense of $3.8 million as the provision for uncollectible accounts was reduced and a 2005 charge of $0.8 million for an enhanced severance program for certain represented employees. These positive variances were partially offset by $2.9 million of postretirement benefit expenses recognized in 2006 as a result of the Equitrans rate case settlement, $2.7 million of other transition planning costs related to the pending acquisition, an increase in gathering operating expense of $1.1 million due to increased line-walking, right-of-way clearing and leak repair activities and an increase in DD&A of $1.0 million due to an increased depreciable asset base reflecting increased capital spending.
Capital expenditures totaled $29.1 million for the six months ended June 30, 2006 compared to $21.6 million for the six months ended June 30, 2005. The $7.5 million increase was primarily due to increased expenditures for the automated meter reading program, which began in the second quarter of 2005 and is expected to be completed in the third quarter of 2006.
21
OUTLOOK
Equitable Utilities’ business strategy is focused on effectively managing its gas distribution assets, optimizing its return on assets, selectively growing its gas distribution business through acquisition and developing a portfolio of closely related, unregulated businesses with an emphasis on risk management and earnings viability. On March 1, 2006, the Company entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution and midstream assets in Pennsylvania and its natural gas distribution assets in West Virginia for approximately $970 million, subject to adjustments, in a cash transaction for the stock of The Peoples Natural Gas Company and Hope Gas, Inc. The transaction requires approvals from the Pennsylvania Public Utility Commission (PA PUC) and the Public Service Commission of West Virginia (WV PSC) and is subject to review under the Hart-Scott-Rodino Act and by the Pennsylvania Attorney General. Initial regulatory filings have been submitted to the PA PUC, the WV PSC and the Federal Trade Commission. The assets to be acquired will increase the number of customers by 475,000 or 173%, total storage capacity by 33 Bcf or 60%, miles of gathering pipelines by 936 miles, gathered volumes by 40%, and miles of high pressure transmission by 466 or 42%. The Company is targeting regulatory approval by the end of 2006. Transition activities have commenced at Equitable Utilities to plan for the integration of The Peoples Natural Gas Company and Hope Gas, Inc. assets, resources and business processes into Equitable Resources. The Company incurred $2.7 million of transition planning costs through June 30, 2006. Based on the work completed to date, Equitable expects that the conversion activities will accelerate and increase Utilities operating expenses in the third and fourth quarters of 2006 in anticipation of closing the transaction.
EQUITABLE SUPPLY
In May 2005, the Company sold certain non-core gas properties and associated gathering assets for proceeds of approximately $142 million after purchase price adjustments. The unit of production depletion rate (or DD&A rate) decreased by $0.04 per Mcfe prospectively as a result of this transaction.
22
Capital expenditures (thousands) (a)
15.9
(17.1
Production:
Total sales volumes (MMcfe)
19,115
18,494
3.4
37,444
36,822
1.7
Average (well-head) sales price ($/Mcfe)
4.71
4.77
(1.3
4.90
4.76
2.9
Company usage, line loss (MMcfe)
1,266
1,116
13.4
2,519
2,347
7.3
Natural gas inventory usage, net (MMcfe)
(51
100.0
Natural gas and oil production (MMcfe)
20,381
19,610
3.9
39,963
39,118
2.2
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)
0.31
0.33
(6.1
0.30
(9.1
Production taxes ($/Mcfe)
0.46
0.44
4.5
0.50
0.42
19.0
Production depletion ($/Mcfe)
0.62
0.60
3.3
0.61
1.6
Gathering:
Gathered volumes (MMcfe)
26,268
28,960
(9.3
53,550
62,112
(13.8
Average gathering fee ($/Mcfe)
1.01
0.78
29.5
1.00
0.75
33.3
Gathering and compression expense ($/Mcfe)
0.38
15.2
Gathering and compression depreciation ($/Mcfe)
0.15
0.12
25.0
0.14
0.11
27.3
(in thousands)
Production operating income
56,655
58,154
(2.6
118,667
115,437
2.8
Gathering operating income
8,788
5,016
75.2
18,759
13,086
43.4
3.6
6.9
Production depletion
12,594
11,840
24,731
23,899
3.5
Gathering and compression depreciation
3,821
3,401
12.3
7,588
6,725
12.8
Other DD&A
1,034
950
1,976
1,952
1.2
17,449
16,191
7.8
34,295
32,576
5.3
(a) Capital expenditures for the six months ended June 30, 2005 include $57.5 million for the acquisition of the limited partnership interest in ESP which was separately approved by the Board of Directors of the Company in addition to the total amount originally authorized for the 2005 capital budget program.
23
Production revenues
92,671
89,712
188,192
178,816
5.2
Gathering revenues
26,656
22,497
18.5
53,584
46,668
14.8
6.3
LOE, excluding production taxes
6,360
6,481
(1.9
11,790
12,716
(7.3
Production taxes
9,310
8,545
9.0
19,999
16,480
21.4
Gathering and compression (O&M)
10,582
10,301
2.7
20,424
20,197
1.1
SG&A
10,183
7,521
35.4
17,842
14,473
23.3
519
(100.0
9.9
7.6
(249.4
(113.8
Equitable Supply’s operating income totaled $65.4 million for the three months ended June 30, 2006 compared to $63.2 million for the three months ended June 30, 2005. The $2.2 million increase in operating income was primarily due to an increase in production sales volumes and an increase in gathering revenues, partially offset by increased operating expenses and a decrease in the average well-head sales price.
Total operating revenues were $119.3 million for the three months ended June 30, 2006 compared to $112.2 million for the three months ended June 30, 2005. The $7.1 million increase in total operating revenues was primarily due to a 3% increase in production sales volumes and a 19% increase in gathering revenues, partially offset by a 1% decrease in the average well-head sales price. Production sales volumes increased by 0.6 Bcfe to 19.1 Bcfe as volumes from new wells more than offset the 0.6 Bcfe from wells sold in May 2005. Excluding property dispositions, sales volumes were up by 6.7%. The increase in gathering revenues was due to a 30% increase in the average gathering fee, partially offset by a 9% decline in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to an increased infrastructure program, along with higher gas prices and related operating cost increases. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities for segment reporting purposes. The decrease in gathered volumes is primarily due to the aforementioned transfer of certain regulated gathering facilities and the sale of certain non-core gathering assets in May 2005. These decreases were partially offset by increased gathered volumes for Equitable Supply production in 2006. The $0.06 per Mcfe decrease in the average well-head sales price was primarily the result of increased gathering rates and a reserve established in connection with certain contract disputes, offset by favorable market prices.
Operating expenses totaled $53.9 million for the three months ended June 30, 2006 compared to $49.0 million for the three months ended June 30, 2005. The $4.9 million increase in operating expenses was primarily attributable to increases of $2.7 million in SG&A, $1.2 million in DD&A and $0.8 million in production taxes. The increase in SG&A was primarily related to a reserve established in connection with certain contract disputes. The increase in DD&A was primarily related to a 4% increase in produced volumes and the Company’s increased investment in infrastructure. The increase in production taxes was due to increased property taxes and severance taxes. The increase in property taxes was a direct result of increased prices and sales in prior years, 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 sales volumes. The increase in severance taxes (a production tax directly imposed on the value of gas extracted) was primarily due to higher current gas commodity prices and sales volumes in the various taxing jurisdictions that impose such taxes.
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Capital expenditures totaled $68.6 million for the three months ended June 30, 2006 compared to $59.2 million for the three months ended June 30, 2005. The $9.4 million increase was mainly due to increased spending on drilling and development and the Big Sandy Pipeline project. The Company drilled 142 wells and 107 wells for the three months ended June 30, 2006 and 2005, respectively.
Equitable Supply’s operating income for the six months ended June 30, 2006 was $137.4 million compared to $128.5 million for the six months ended June 30, 2005. The $8.9 million increase in operating income was primarily due to an increase in production sales volumes, an increase in the average well-head sales price and an increase in gathering revenues, partially offset by higher operating expenses.
Total operating revenues were $241.8 million for the six months ended June 30, 2006 compared to $225.5 million for the six months ended June 30, 2005. The $16.3 million increase in total operating revenues was primarily attributable to a 2% increase in production sales volumes, a 3% increase in the average well-head sales price and a 15% increase in gathering revenues. The increase in production sales volumes was primarily due to new wells drilled in 2005 and 2006, partially offset by the lack of sales from certain non-core gas properties sold in May 2005 (1,470 MMcfe) as well as the natural decline from the remaining wells. The $0.14 per Mcfe increase in the average well-head sales price was primarily the result of increased market prices on unhedged volumes. The increase in gathering revenues was due to a 33% increase in the average gathering fee, partially offset by a 14% decrease in gathered volumes. The increase in the average gathering fee is reflective of the Company’s commitment to an increased infrastructure program, along with higher gas prices and rising operating cost. The average gathering fee was also positively impacted by the transfer of certain regulated gathering facilities to Equitable Utilities for segment reporting purposes. The decrease in gathered volumes is primarily attributable to the aforementioned transfer of certain regulated gathering facilities the sale of certain non-core gathering assets in May 2005 and third-party volume shut-ins caused by extended maintenance projects on interstate pipelines. These decreases were partially offset by increased gathered volumes for Equitable Supply production in 2006.
Operating expenses were $104.4 million for the six months ended June 30, 2006, compared to $97.0 million for the six months ended June 30, 2005. The $7.4 million increase in operating expenses was primarily due to increases of $3.5 million in production taxes, $3.3 million in SG&A, and $1.7 million in DD&A, partially offset by a $0.9 million decrease in LOE and a 2005 impairment charge of $0.5 million related to the office consolidation. The increase in production taxes was due to increased property taxes and severance taxes for the reasons previously discussed. The increase in SG&A was primarily related to a reserve established for certain contract disputes. The increase in DD&A was primarily related to a 2% increase in produced volumes and the Company’s increased investment in infrastructure.
Capital expenditures totaled $122.5 million for the six months ended June 30, 2006 compared to $147.8 million for the six months ended June 30, 2005. The $25.3 million decrease was due to the $57.5 million acquisition in January 2005 of the limited partnership interest in ESP partially offset by increased spending on drilling and development and the Big Sandy Pipeline project. The Company drilled 275 wells and 173 wells for the six months ended June 30, 2006 and 2005, respectively.
Equitable Supply’s business strategy is focused on achieving profit maximization by primarily focusing on developing new opportunities, through increased drilling and other development in the Appalachian Basin, as well as improvements to and expansion of its gathering systems, and secondarily focusing on cost control. The Company believes that the margin leverage from realizable gas prices outweighs the increase in unit cost structure necessary to implement this strategy. The Company expects to drill 550 wells and sell between 76 Bcfe and 77 Bcfe of natural gas in 2006. The drilling program includes drilling horizontal test wells, with five test wells expected to be drilled by the end of 2006, to determine reservoir response that will enable the Company to begin testing the economic viability of using horizontal drilling techniques in future reserve development. Equitable Supply plans to continue to expand its pipeline and compression infrastructure in order to manage increased gathered volumes from both Company drilling programs and third party shippers. The Company also plans to expand its gathering systems by approximately 190 miles of pipeline and approximately 20,000 horsepower of compression in 2006.
In 2005, the Company announced a new pipeline infrastructure project, the Big Sandy Pipeline. In December of 2005, the Company started FERC’s pre-filing environmental review process, and on May 10, 2006, the Company filed its certificate application with the FERC for approval to build a 70-mile, 20-inch diameter pipeline to provide, based on the currently proposed system design, up to 130,000 Dekatherms per day. The Big Sandy Pipeline, which is owned and operated by Equitrans, will connect the Kentucky Hydrocarbon operated processing plant in Langley, Kentucky, with the Tennessee Gas Pipeline interconnect in Carter County, Kentucky. The pipeline is targeted for completion in 2007. The Company is also planning an upgrade to the Langley plant for completion in early 2008. Both projects are projected to cost a total of $191 million and should enable the Company to further support its drilling growth, mitigate pipeline curtailments, increase flexibility and reliability of its midstream gathering systems and satisfy third party producer demand in the Appalachian Basin. Initial interest in the project is approximately 155,000 Dekatherms per day. In the event the Company is able to enter into definitive agreements, the project can be quickly expanded to accommodate this increased demand. Natural gas processing expansion will continue to be required in order to meet the interstate pipeline gas quality standards and will represent an opportunity for the Company. The Company is evaluating several processing, pipeline and compression expansion opportunities in Appalachia and expects to invest in additional projects in 2006 and beyond.
CAPITAL RESOURCES AND LIQUIDITY
Operating Activities
Cash flows provided by operating activities totaled $397.9 million for the first six months of 2006 as compared to $63.0 million of cash flows used in operating activities for the first six months of 2005, a net increase of $460.9 million in cash flows provided by operating activities between years. The increase in cash flows provided by operating activities was attributable primarily to the following:
· a $373.4 million net decrease in cash outflows for margin deposit requirements on the Company’s natural gas hedge agreements, primarily resulting from decreased natural gas prices and increased margin deposit thresholds with financial institutions during the first six months of 2006;
· a greater decrease in accounts receivable primarily due to a greater decrease in natural gas prices during the first six months of 2006 as compared to the first six months of 2005;
partially offset by:
· a greater decrease in accounts payable primarily due to a greater decrease in natural gas prices during the first six months of 2006 as compared to the first six months of 2005.
Investing Activities
Cash flows used in investing activities totaled $156.3 million for the first six months of 2006 as compared to $275.5 million of cash flows provided by investing activities for the first six months of 2005, a net increase of $431.8 million in cash flows used in investing activities between years. The increase in cash flows used in investing activities was primarily due to the following:
· net proceeds of $354.3 million received from the sale of approximately 5.9 million shares of Kerr-McGee Corporation common stock in the first six months of 2005;
· unrestricted cash proceeds of $100.2 million from the sale of non-core properties in the first six months of 2005;
· an increase in capital expenditures to $153.4 million in the first six months of 2006 from $120.7 million in the first six months of 2005;
· the Company’s acquisition of the 99% limited partnership interest in ESP for $57.5 million in the first six months of 2005.
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Financing Activities
Cash flows used in financing activities totaled $316.5 million for the first six months of 2006 and $212.5 million for the first six months of 2005, a net increase of $104.0 million in cash flows used in financing activities between years. The increase in cash flows used in financing activities was attributable to the following:
· a $286.8 million decrease in amounts borrowed under short-term loans in the first six months of 2006 compared to a $139.0 million decrease in short-term borrowings in the first six months of 2005. The decrease in short-term borrowings in the first six months of 2006 was primarily the result of decreased requirements for funding margin deposits as previously discussed;
· no repurchases of shares of the Company’s common stock under the Company’s share repurchase program during the first six months of 2006 in anticipation of the pending acquisition of The Peoples Natural Gas Company and Hope Gas, Inc. compared to repurchases of $52.9 million of common stock in the first six months of 2005.
The Company believes that cash generated from operations, amounts available under its credit facilities and amounts which the Company could obtain in the debt and equity markets given its financial position, are adequate to meet the Company’s reasonably foreseeable operating liquidity requirements. The Company intends to finance the $970 million purchase price for the previously discussed acquisition through a combination of equity and debt issuances and possible hybrid issuances and/or asset sales.
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.
Rating Service
SeniorUnsecured Debt
CommercialPaper
Moody’s Investors Service
A-2
P-1
Standard & Poor’s Ratings Services
A-
On March 2, 2006, Standard & Poor’s Ratings Services placed the Company’s short and long-term credit ratings on CreditWatch with negative implications and Moody’s Investors Service placed the ratings under review for possible downgrade. These actions resulted from the Company’s announcement that it had entered into a definitive agreement to acquire Dominion Resources’ natural gas distribution and midstream assets in Pennsylvania and its natural gas distribution assets in West Virginia, subject to anti-trust and regulatory approvals. The final ratings outcomes are expected to be determined after the requisite approvals are received and the acquisition financing plan has been reviewed by the ratings agencies.
The Company’s credit ratings are 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 rating agency if, in its judgment, circumstances so warrant. If the rating agencies downgrade the Company’s ratings, particularly below investment grade, it may significantly limit the Company’s access to the commercial paper market and borrowing costs would increase. In addition, the Company would likely be required to pay a higher interest rate in future financings and incur increased margin deposit requirements with respect to its hedging instruments and the potential pool of investors and funding sources would decrease.
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%. This calculation excludes unrealized gains or losses from hedging transactions recorded in accumulated other comprehensive income (loss). As of June 30, 2006, the Company is in compliance with all existing debt provisions and covenants.
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Commodity Risk Management
The Company’s overall objective in its hedging program is to protect earnings from undue exposure to the risk of changing commodity prices. The Company’s risk management program includes the use of exchange-traded natural gas futures contracts and options and Over the Counter (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 preponderance of derivative commodity instruments currently utilized by the Company are fixed price swaps or NYMEX-traded forwards.
During the first six months of 2006, the Company increased its hedge position for 2007 through 2013. The approximate volumes and prices of the Company’s production hedges for 2006 through 2008 are:
Swaps
2006**
2007
2008
Total Volume (Bcf)
30
56
54
Average Price per Mcf (NYMEX)*
4.74
4.64
Collars
Average Floor Price per Mcf (NYMEX)*
7.35
7.61
Average Cap Price per Mcf (NYMEX)*
10.84
11.27
* The above price is based on a conversion rate of 1.05 MMbtu/Mcf
** July through December
The Company’s current hedged position provides price protection for a substantial portion of expected equity production for the years 2006 through 2008 and a smaller but significant portion of expected equity production for the years 2009 through 2013. The Company’s exposure to a $0.10 change in average NYMEX natural gas price is less than $0.01 per diluted share for 2006 and ranges from $0.01 to $0.02 per diluted share per year for 2007 and 2008. 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.
Commitments and Contingencies
In the ordinary course of business, various legal 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 for pending litigation, which it believes are adequate, 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 of the Company.
Incentive Compensation
The Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R) on January 1, 2006, which results in the Company recognizing compensation cost for all forms of share-based payments to employees, including employee stock options, as an expense in its income statement. The Company previously applied Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25) in accounting for its share-based compensation and consequently did not recognize any compensation cost for its stock option awards. The Company’s estimate of compensation cost for stock options is based on the use of the Black-Scholes option-pricing model. The Black-Scholes model is considered a “theoretical” or probability model used to estimate the price an option would sell for in the market today. The Company does not represent that this method yields an exact value of what an unrelated third party (i.e., the market) would be willing to pay to acquire such options.
The Company adopted SFAS No. 123R using the modified prospective method, under which the Company is recording compensation expense for its unvested stock options beginning January 1, 2006. As such, the Company did not restate any prior period income statement amounts. In addition, the adoption of SFAS No. 123R did not result in any significant changes to the Company’s method for valuing its stock options from that previously used for pro forma disclosures under SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123).
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The adoption of SFAS No. 123R did not have a significant impact on the Company’s operating results for the first six months of 2006, as the Company has shifted its compensation focus to the issuance of time-restricted stock awards and performance-based units for which it already recognized compensation expense under generally accepted accounting principles. Management and the Board of Directors believe that such an incentive compensation approach more closely aligns management’s incentives with shareholder rewards than is the case with traditional stock options. No new stock options have been awarded since 2003; all stock options granted subsequent to 2003 have comprised options granted for reload rights associated with previously-awarded options.
The Company recorded approximately $0.7 million of compensation expense related to stock options in the first six months of 2006, the majority of which related to stock option reloads which immediately vested under the terms of the related stock option award agreements. The majority of the Company’s previously issued stock options were already vested at the time of adoption of SFAS No. 123R, and associated compensation expense yet to be recognized was insignificant. All stock options outstanding as of June 30, 2006 are fully vested, and as such, the Company does not anticipate incurring any additional compensation expense related to currently outstanding stock options.
Had compensation cost been determined based on the fair value at the grant date for prior periods’ stock option grants consistent with the methodology prescribed in SFAS No. 123R, net income for the first six months of 2005 would have been reduced by an estimated $1.2 million, or approximately $0.01 per diluted share.
The Company recorded the following incentive compensation expense in continuing operations for the periods indicated below:
(Millions)
Short-term incentive compensation expense
5.9
5.1
Long-term incentive compensation expense
16.1
Total incentive compensation expense
18.7
21.2
The long-term incentive compensation expenses are primarily associated with Executive Performance Incentive Programs (“the Programs”) that were instituted starting in 2002. The long-term incentive compensation expenses during the first six months of 2005 were higher than during the same period in 2006 due to a greater number of unvested units outstanding during 2005 than during the current year.
Dividend
On July 18, 2006, the Board of Directors declared a regular quarterly cash dividend of 22 cents per share payable September 1, 2006, to shareholders of record on August 11, 2006.
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, 2005 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 have been included in the notes to the Company’s Condensed Consolidated Financial Statements for the period ended June 30, 2006. 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.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risk exposure is the volatility of future prices for natural gas, which can affect the operating results of the Company primarily through the Equitable Supply segment and the unregulated marketing group within the Equitable Utilities segment. 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 simple, 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 the 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.
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. The financial instruments currently utilized by the Company include forward contracts, swap agreements and collar agreements, 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 options and 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. In general, the Company’s strategy is to hedge production at prices considered to be favorable to the Company. The Company attempts to take advantage of price fluctuations by hedging more aggressively when market prices move above recent historical averages and by taking more price risk when prices are significantly below these levels. The goal of these actions is to earn a return above the cost of capital and to lower the cost of capital by reducing cash flow volatility.
For derivative commodity instruments held for trading purposes, the marketing group will engage in financial transactions also subject to policies that limit the net positions to specific value at risk limits. The financial instruments currently utilized by the Company include forward contracts and swap agreements. The Company also considers options and other contractual agreements in determining its commodity hedging strategy.
With respect to the derivative commodity instruments held by the Company for purposes other than trading as of June 30, 2006, the Company continued to execute its hedging strategy by utilizing forward contracts, swap agreements and collar agreements covering approximately 339.0 Bcf of natural gas. These derivatives have hedged a portion of expected equity production through 2013. 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 decrease of 10% in the market price of natural gas from the June 30, 2006 levels would increase the fair value of natural gas instruments by approximately $276.5 million. An increase of 10% in the market price of natural gas would decrease the fair value by approximately $276.9 million.
With respect to the derivative commodity instruments held by the Company for trading purposes as of June 30, 2006, an increase or decrease of 10% in the market price of natural gas from the June 30, 2006 levels would not have a significant impact on the fair value.
The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal change in fair value as described in Note 1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. The Company assumed a 10% change in the price of natural gas from its levels at June 30, 2006. 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 Company is exposed to credit loss in the event of nonperformance by counterparties to derivative commodity contracts. This credit exposure is limited to derivative commodity instruments with a positive fair value. The Company believes that NYMEX traded futures contracts have minimal credit risk because futures exchanges are the counterparties. The Company manages the credit risk of the other derivative commodity instruments by limiting dealings to those counterparties who meet the Company’s criteria for credit and liquidity strength.
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 Officers, an evaluation of the Company’s disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officers 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 Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) that occurred during the second quarter of 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II. OTHER INFORMATION
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, 2005. 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 have occurred in the three months ended June 30, 2006.
Period
Total number ofshares (or units)purchased(a)
Averageprice paidper share(or unit)
Total number ofshares (or units)purchased as partof publicly announced plansor programs
Maximum number (orapproximate dollarvalue) of shares (orunits) that may yet bepurchased under theplans or programs (b)
April 2006 (April 1 — April 30)
6,344
36.35
8,385,400
May 2006 (May 1 — May 31)
7,403
34.03
June 2006 (June 1 — June 30)
10,043
32.45
23,790
(a) Includes 9,096 shares delivered in exchange for the exercise of stock options to cover award cost and 14,694 shares for Company-directed purchases made by the Company’s 401(k) plans.
(b) Equitable’s Board of Directors previously authorized a share repurchase program with a maximum of 50.0 million shares and no expiration date. The program was initially publicly announced on October 7, 1998 with subsequent amendments announced on November 12, 1999, July 20, 2000, April 15, 2004 and July 13, 2005.
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Item 4. Submission of Matters to a Vote of Security Holders
a)
The Annual Meeting of Shareholders was held on April 12, 2006.
b)
Brief description of matters voted upon:
(1)
Elected the named directors to serve a three-year term expiring 2009 as follows:
Director
Shares Voted For
Shares Withheld
Thomas A. McConomy
97,909,127
1,413,583
Barbara S. Jeremiah
98,480,188
842,522
Lee T. Todd, Jr., Ph.D.
98,583,349
739,361
The following Directors’ terms continued after the Annual Meeting of Shareholders:
until 2007 - Murry S. Gerber, George L. Miles, Jr., James W. Whalen and Vicky A. Bailey
until 2008 - Phyllis A. Domm, Ed.D., David L. Porges, James E. Rohr and David S. Shapira
(2)
Ratified appointment of Ernst & Young, LLP, as independent auditors for the year ended December 31, 2006. Vote was 98,241,076 shares for; 931,355 shares against and 150,278 shares abstained.
(3)
Approved the amendment and continuation of the Equitable Resources, Inc. Executive Short-Term Incentive Plan. Vote was 81,355,800 shares for; 3,790,116 shares against and 587,920 shares abstained.
Item 5. Other Information
The Company implemented the Equitable Resources, Inc. 2006 Payroll Deduction and Contribution Program, effective as of July 25, 2006. The program provides executive officers and certain others with the ability to invest a limited portion of their salary in a personal retirement annuity. The Company also provides a contribution on behalf of program participants equal to the matching and the performance contributions that the participant would otherwise receive under the Equitable Resources, Inc. Employee Savings Plan, originally adopted September 1, 1985, as amended, beyond certain limitations imposed by the Internal Revenue Code of 1986, as amended. A copy of the Program is attached hereto as Exhibit 10.1.
Item 6. Exhibits
10.1
Equitable Resources, Inc. 2006 Payroll Deduction and Contribution Program
31.1
Rule 13(a)-14(a) Certification of Principal Executive Officer
31.2
Rule 13(a)-14(a) Certification of Co-Principal Financial Officer
Section 1350 Certification of Principal Executive Officer and Co-Principal Financial Officers
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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
By:
/s/ Philip P. Conti
Philip P. Conti
Vice President and Chief Financial Officer
Date: July 27, 2006
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INDEX TO EXHIBITS
Exhibit No
Document Description
Incorporated by Reference
Filed Herewith
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