Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-3551
EQT CORPORATION
(Exact name of registrant as specified in its charter)
PENNSYLVANIA
25-0464690
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)
625 Liberty Avenue, Suite 1700, Pittsburgh, Pennsylvania
15222
(Address of principal executive offices)
(Zip code)
(412) 553-5700
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
Accelerated Filer
Non-Accelerated Filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
As of September 30, 2013, 150,716,288 shares of common stock, no par value, of the registrant were outstanding.
EQT CORPORATION AND SUBSIDIARIES
Index
Page No.
Part I.
Financial Information:
Item 1.
Financial Statements (Unaudited):
Statements of Consolidated Income for the Three and Nine Months Ended September 30, 2013 and 2012
3
Statements of Consolidated Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012
4
Statements of Condensed Consolidated Cash Flows for the Nine Months Ended September 30, 2013 and 2012
5
Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012
6 – 7
Statements of Condensed Consolidated Equity for the Nine Months Ended September 30, 2013 and 2012
8
Notes to Condensed Consolidated Financial Statements
9 – 21
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
22 – 36
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
37 – 39
Item 4.
Controls and Procedures
39
Part II.
Other Information:
Legal Proceedings
40
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.
Exhibits
41
Signature
42
Index to Exhibits
43
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Consolidated Income (Unaudited)
Three Months Ended
Nine Months Ended
September 30,
2013
2012
(Thousands, except per share amounts)
Operating revenues
$
506,598
364,057
1,585,350
1,151,821
Operating expenses:
Purchased gas costs
37,265
34,394
188,199
158,127
Operation and maintenance
36,861
36,259
105,124
105,464
Production
28,076
23,201
80,712
72,796
Exploration
5,256
1,163
15,124
4,878
Selling, general and administrative
52,944
51,481
162,372
136,201
Depreciation, depletion and amortization
175,648
131,611
493,341
354,817
Total operating expenses
336,050
278,109
1,044,872
832,283
Operating income
170,548
85,948
540,478
319,538
Other income
2,405
2,801
6,846
13,841
Interest expense
35,554
40,460
110,690
122,341
Income before income taxes
137,399
48,289
436,634
211,038
Income taxes
34,789
11,585
130,625
70,853
Net income
102,610
36,704
306,009
140,185
Less: Net income attributable to noncontrolling interests
14,354
4,831
30,642
Net income attributable to EQT Corporation
88,256
31,873
275,367
135,354
Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common shares outstanding
150,679
149,604
150,509
149,555
0.59
0.21
1.83
0.91
Diluted:
151,663
150,388
151,365
150,270
0.58
1.82
0.90
Dividends declared per common share
0.03
0.22
0.09
0.66
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
Statements of Consolidated Comprehensive Income (Unaudited)
Three Months Ended September 30,
Nine Months Ended September 30,
(Thousands)
Other comprehensive income (loss), net of tax:
Net change in cash flow hedges:
Natural gas, net of tax benefit of ($5,448), $(62,383), $(15,595) and $(65,488)
(8,287
)
(96,680
(23,782
(101,394
Interest rate, net of tax expense (benefit) of $25, ($1,322), $75 and ($4,487)
36
(1,734
108
(5,902
Pension and other post-retirement benefits liability adjustment, net of tax expense of $307, $369, $920 and $583
433
455
1,302
1,891
Other comprehensive loss
(7,818
(97,959
(22,372
(105,405
Comprehensive income (loss)
94,792
(61,255
283,637
34,780
Less: Comprehensive income attributable to noncontrolling interests
Comprehensive income (loss) attributable to EQT Corporation
80,438
(66,086
252,995
29,949
Statements of Condensed Consolidated Cash Flows (Unaudited)
Cash flows from operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes
14,869
45,473
Depreciation, depletion, and amortization
Provision for (recovery of) losses on accounts receivable
986
(3,187
(6,846
(13,841
Stock-based compensation expense
37,108
28,752
Unrealized (gains) losses on derivatives and inventory
(2,310
3,140
Lease impairment
12,132
1,159
Noncash financial instrument put premiums
–
8,227
Changes in other assets and liabilities:
Dividend from Nora Gathering, LLC
9,000
7,750
Accounts receivable and unbilled revenues
37,826
50,870
Inventory
13,014
35,981
Prepaid expenses and other
12,473
(6,479
Accounts payable
17,168
(10,001
Accrued interest
27,030
28,285
Other items, net
35,300
(1,161
Net cash provided by operating activities
1,007,100
669,970
Cash flows from investing activities:
Capital expenditures
(1,259,634
(1,023,503
Proceeds from sale of assets
4,842
Net cash used in investing activities
(1,018,661
Cash flows from financing activities:
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs
529,442
276,780
Dividends paid
(13,565
(98,840
Distributions to noncontrolling interests
(21,160
Repayments and retirements of long-term debt
(23,204
(19,315
Proceeds and tax benefits from exercises under employee compensation plans
22,863
1,831
Revolving credit facility origination fees
(4,022
Net cash provided by financing activities
494,376
156,434
Net change in cash and cash equivalents
241,842
(192,257
Cash and cash equivalents at beginning of period
182,055
831,251
Cash and cash equivalents at end of period
423,897
638,994
Cash paid during the period for:
Interest, net of amount capitalized
83,660
93,872
Income taxes, net
76,669
17,193
Condensed Consolidated Balance Sheets (Unaudited)
December 31,
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable (less accumulated provision for doubtful accounts of $10,104 at September 30, 2013 and $12,586 at December 31, 2012)
186,061
205,479
Unbilled revenues
8,305
27,699
67,911
76,787
Derivative instruments, at fair value
203,002
304,237
44,115
56,588
Total current assets
933,291
852,845
Equity in nonconsolidated investments
127,185
130,368
Property, plant and equipment
11,374,145
10,139,903
Less: accumulated depreciation and depletion
2,897,981
2,424,605
Net property, plant and equipment
8,476,164
7,715,298
Regulatory assets
113,475
111,915
Other assets
32,137
39,436
Total assets
9,682,252
8,849,862
6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt
6,162
23,204
306,200
289,032
18,353
75,562
Other current liabilities
209,967
182,667
Total current liabilities
540,682
570,465
Long-term debt
2,495,717
2,502,969
Deferred income taxes and investment tax credits
1,670,562
1,666,029
Other credits
239,968
221,597
Total liabilities
4,946,929
4,961,060
Equity:
Stockholders’ equity:
Common stock, no par value, authorized 320,000 shares, shares issued: 175,684 at September 30, 2013 and December 31, 2012
1,827,413
1,770,545
Treasury stock, shares at cost: 24,968 at September 30, 2013 and 25,575 at December 31, 2012
(450,786
(461,774
Retained earnings
2,457,304
2,195,502
Accumulated other comprehensive income
77,175
99,547
Total common stockholders’ equity
3,911,106
3,603,820
Noncontrolling interests in consolidated subsidiaries
824,217
284,982
Total equity
4,735,323
3,888,802
Total liabilities and equity
7
Statements of Condensed Consolidated Equity (Unaudited)
Accumulated
Noncontrolling
Common Stock
Other
Interests in
Shares
No
Retained
Comprehensive
Consolidated
Total
Outstanding
Par Value
Earnings
Income
Subsidiaries
Equity
Balance, January 1, 2012
149,477
1,261,779
2,143,910
188,141
3,593,830
Dividends on common stock ($0.66 per share)
Stock-based compensation plans, net
136
35,688
162
35,850
Issuance of common units of EQT Midstream Partners, LP
Deferred taxes related to initial public offering of EQT Midstream Partners, LP
5,371
Balance, September 30, 2012
149,613
1,302,838
2,180,424
82,736
281,773
3,847,771
Balance, January 1, 2013
150,109
1,308,771
Dividends on common stock ($0.09 per share)
607
69,497
311
69,808
Distributions to noncontrolling interests ($1.12 per common unit)
Deferred taxes related to public offering of common units of EQT Midstream Partners, LP
(1,641
Balance, September 30, 2013
150,716
1,376,627
EQT Corporation and Subsidiaries
Notes to Condensed Consolidated Financial Statements (Unaudited)
A. Financial Statements
The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) 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 GAAP for complete financial statements. In the opinion of management, these statements include all adjustments (consisting of only normal recurring accruals, unless otherwise disclosed in this Form 10-Q) necessary for a fair presentation of the financial position of EQT Corporation and subsidiaries as of September 30, 2013 and December 31, 2012, the results of its operations for the three and nine month periods ended September 30, 2013 and 2012 and its cash flows for the nine month periods ended September 30, 2013 and 2012. In this Form 10-Q, references to “we,” “us,” “our,” “EQT,” “EQT Corporation,” and the “Company” refer collectively to EQT Corporation and its consolidated subsidiaries.
The balance sheet at December 31, 2012 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 GAAP for complete financial statements.
Due to the seasonal nature of the Company’s natural gas distribution and storage businesses and the volatility of commodity prices, the interim financial statements for the three and nine month periods ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.
For further information, refer to the consolidated financial statements and footnotes thereto included in EQT Corporation’s Annual Report on Form 10-K for the year ended December 31, 2012 as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q.
B. EQT Midstream Partners, LP
On July 2, 2012, EQT Midstream Partners, LP (the Partnership), a subsidiary of the Company, completed an underwritten initial public offering (IPO) of 14,375,000 common units representing limited partner interests in the Partnership, which represented 40.6% of the Partnership’s outstanding equity. The Company retained a 59.4% equity interest in the Partnership, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest. Prior to the IPO, the Company contributed to the Partnership 100% of Equitrans, L.P. (Equitrans, the Company’s Federal Energy Regulatory Commission regulated transmission, storage and gathering subsidiary). An indirect wholly-owned subsidiary of the Company serves as the general partner of the Partnership, and the Company continues to operate the Equitrans business pursuant to contractual arrangements entered into in connection with the closing of the IPO. The Company continues to consolidate the results of the Partnership but records an income tax provision only as to the Company’s ownership percentage. The Company records the noncontrolling interest of the public limited partners in the Company’s financial statements.
On July 15, 2013, the Company and Sunrise Pipeline, LLC (Sunrise), a subsidiary of the Company, entered into an Agreement and Plan of Merger with the Partnership and Equitrans. Effective July 22, 2013, Sunrise merged with and into Equitrans, with Equitrans continuing as the surviving company. The Company received consideration consisting of a $507.5 million cash payment, 479,184 common units of the Partnership and 267,942 general partner units of the Partnership. Prior to the merger, Sunrise entered into a precedent agreement with a third party for firm transportation service over a twenty-year term. If a transportation agreement pursuant to this precedent agreement becomes effective on its current terms by December 31, 2014, the Partnership will make an additional payment of approximately $110 million to the Company. The transportation agreement is subject to review by regulatory authorities, which is expected to be completed by the end of 2013. The Partnership will also pay the Company additional consideration in the event certain other transportation agreements on the Sunrise system become effective prior to December 31, 2014. While the Company did not record a gain for accounting purposes as a result of the Sunrise transaction, the Company recognized a taxable gain for federal income tax purposes of approximately $475 million in 2013. After offsetting the federal income tax gain with intangible drilling cost deductions and accelerated tax depreciation from 2013 and net operating losses from prior years, the Company’s cash taxes will increase by approximately $57 million in 2013 as a result of the transaction.
On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units representing limited partner interests in the Partnership. Following the offering and the closing of the merger, the
9
Company retained a 44.6% equity interest in the Partnership, which includes 3,443,902 common units, 17,339,718 subordinated units and a 2% general partner interest. The Partnership received net proceeds of $529.4 million from the offering, after deducting the underwriters’ discount and offering expenses of approximately $21 million.
Net income to noncontrolling interests, (i.e. the limited partnership units not owned by the Company) was $14.4 million and $30.6 million for the three and nine month periods ended September 30, 2013, respectively, and $4.8 million for the three and nine month periods ended September 30, 2012. The Partnership paid distributions of $10.8 million to noncontrolling interests of $0.40 per common unit and $21.2 million to noncontrolling interests of $1.12 per common unit during the three and nine month periods ended September 30, 2013, respectively.
C. Segment Information
Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and which are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources.
The Company reports its operations in three segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids (NGLs) and a limited amount of crude oil in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, transportation, storage and marketing activities of the Company, including ownership and operation of the Partnership. Distribution’s operations primarily comprise the state-regulated natural gas distribution activities of the Company.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income, interest and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based on a fixed allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarter expenses are not allocated to the operating segments.
As described in Note I, the Company and its direct wholly-owned subsidiary, Distribution Holdco, LLC (Holdco), executed a definitive agreement (the Master Purchase Agreement) with PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC (Peoples), pursuant to which the Company and Holdco will transfer 100% of their ownership interests of Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Homeworks and Equitable Gas are direct wholly-owned subsidiaries of Holdco and comprise substantially all of the Distribution segment. The transaction is subject to approval by a number of federal and state regulatory agencies. Once the Company makes satisfactory progress in the regulatory process, the Distribution operating segment is expected to be classified as a discontinued operation in the Company’s financial statements.
Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States.
10
Revenues from external customers:
EQT Production
304,231
195,289
860,874
549,334
EQT Midstream
155,677
120,484
452,731
362,630
Distribution
36,118
35,649
246,281
219,343
Third-party transportation costs (a)
34,316
33,947
104,884
91,624
Less intersegment revenues, net (b)
(23,744)
(21,312)
(79,420)
(71,110
Operating income:
97,600
38,528
276,753
115,270
78,533
51,021
224,993
166,907
(87)
685
58,359
43,831
Unallocated expenses (c)
(5,498)
(4,286)
(19,627)
(6,470
Total operating income
Reconciliation of operating income to net income:
As of September 30,
As of December 31,
Segment assets:
6,123,994
5,675,534
2,210,574
2,046,558
857,421
860,029
Total operating segments
9,191,989
8,582,121
Headquarters assets, including cash and short-term investments
490,263
267,741
(a) EQT Production’s segment results are reported with third-party transportation costs reflected as a deduction from operating revenues. Third-party transportation costs are reported as a component of purchased gas costs in the consolidated results. This amount reflects the reclassification of third-party transportation costs from operating revenues to purchased gas costs at the consolidation level.
(b) Includes entries to eliminate intercompany natural gas sales from EQT Production to EQT Midstream and transportation activities between EQT Midstream and both EQT Production and Distribution.
(c) Unallocated expenses consist primarily of incentive compensation expenses, general and administrative costs and expenses related to the pending sale of Equitable Gas and Homeworks for the three and nine months ended September 30, 2013.
11
Depreciation, depletion and amortization:
150,637
108,204
419,619
289,176
18,930
17,172
55,601
46,864
6,096
6,237
18,216
18,767
(15)
(2)
(95)
Expenditures for segment assets:
EQT Production (d)
332,370
255,223
977,394
703,834
111,593
97,135
254,205
296,698
9,710
8,164
24,873
21,066
942
661
3,162
1,905
454,615
361,183
1,259,634
1,023,503
(d) Expenditures for segment assets in the EQT Production segment include $20.5 million and $20.6 million for property acquisitions during the three months ended September 30, 2013 and 2012, respectively, and $162.1 million and $95.2 million for property acquisitions during the nine months ended September 30, 2013 and 2012, respectively.
D. Derivative Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily at EQT Production and the storage, marketing and other activities at EQT Midstream. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
The Company uses over the counter (OTC) derivative commodity instruments that are primarily placed with major financial institutions whose creditworthiness is regularly monitored. The Company also uses exchange traded futures contracts that 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 two prices 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. The Company may also engage in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances.
The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (OCI), net of tax, and is subsequently reclassified into the Statements of Consolidated Income in the same period or periods during which the forecasted transaction affects earnings.
Most of the 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. Some of the derivative commodity instruments used by the Company to hedge its exposure to adverse changes in the market price of natural gas stored in the ground have been designated and qualify as fair value hedges.
For a derivative instrument that has been designated and qualifies as a fair value hedge, the change in the fair value of the instrument is recognized as a portion of operating revenues in the Statements of Consolidated Income each period. In addition, the change in the fair value of the hedged item (natural gas inventory) is recognized as a portion
12
of operating revenues in the Statements of Consolidated Income. The Company has elected to exclude the spot/forward differential for the assessment of effectiveness of the fair value hedges. Any hedging ineffectiveness and any change in fair value of derivative instruments that have not been designated as hedges are recognized in the Statements of Consolidated Income each period.
The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and sales exception and are not accounted for as derivative instruments.
Exchange-traded instruments are generally settled with offsetting positions. OTC arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Condensed Consolidated Cash Flows.
In addition, the Company enters into a limited number of energy trading contracts to leverage its assets and limit its exposure to shifts in market prices and has a limited number of other derivative instruments not designated as hedges. In 2008, the Company effectively settled certain derivative commodity swaps scheduled to mature during the period 2010 through 2013 by de-designating the instruments and entering into directly counteractive instruments. These transactions resulted in offsetting positions which are the majority of the derivative asset and liability balances not designated as hedging instruments.
All derivative instrument assets and liabilities are reported in the Condensed Consolidated Balance Sheets as derivative instruments at fair value. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time.
Commodity derivatives designated as cash flow hedges
Amount of gain (loss) recognized in OCI (effective portion), net of tax
17,733
(51,397
38,561
47,159
Amount of gain reclassified from accumulated OCI into operating revenues (effective portion), net of tax
26,020
45,283
62,343
148,553
Amount of gain (loss) recognized in operating revenues (ineffective portion) (a)
3,436
166
(4,518
(76
Interest rate derivatives designated as cash flow hedges
Amount of loss recognized in OCI (effective portion), net of tax
(1,800
(6,097
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)
(36
(66
(108
(195
Commodity derivatives designated as fair value hedges (b)
Amount of (loss) gain recognized in operating revenues for fair value commodity contracts
(502
(3,051
(1,341
1,644
Fair value (loss) gain recognized in operating revenues for inventory designated as hedged item
1,491
386
(52
Derivatives not designated as hedging instruments
Amount of (loss) gain recognized in operating revenues
(943
(632
307
1,041
(a) No amounts have been excluded from effectiveness testing of cash flow hedges.
(b) For the three months ended September 30, 2013, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $1.6 million loss which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $1.0 million gain due to changes in basis. For the three months ended September 30, 2012, the net impact on operating revenues associated with commodity derivatives designated as fair value
13
hedges was a $1.1 million loss which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $0.5 million loss due to changes in basis. For the nine months ended September 30, 2013, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $0.5 million gain which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $1.5 million loss due to changes in basis. For the nine months ended September 30, 2012, the net impact on operating revenues associated with commodity derivatives designated as fair value hedges was a $1.6 million gain which resulted from the Company’s election to exclude the spot/forward differential from the assessment of effectiveness of the fair value hedges and a $0.1 million gain due to changes in basis.
Asset derivatives
Commodity derivatives designated as hedging instruments
190,053
259,459
Commodity derivatives not designated as hedging instruments
12,949
44,778
Total asset derivatives
Liability derivatives
6,655
27,946
11,698
47,616
Total liability derivatives
The net fair value of commodity derivative instruments changed during the first nine months of 2013 primarily as a result of settlements. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 380 Bcf and 365 Bcf as of September 30, 2013 and December 31, 2012, respectively, and are primarily related to natural gas swaps and collars. The open positions at September 30, 2013 and December 31, 2012 had maturities extending through December 2017. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as fair value hedges totaled 3 Bcf and 8 Bcf as of September 30, 2013 and December 31, 2012, respectively. The open positions at September 30, 2013 had maturities extending through August 2014, and the open positions at December 31, 2012 had maturities extending through January 2014.
The Company deferred net gains of $114.4 million and $138.2 million in accumulated OCI, net of tax, as of September 30, 2013 and December 31, 2012, respectively, associated with the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Assuming no change in price or new transactions, the Company estimates that approximately $67.4 million of net unrealized gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of September 30, 2013 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions.
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company believes that New York Mercantile Exchange (NYMEX) traded futures contracts have limited credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from potential financial instability of the exchange members. The Company’s OTC swap and collar derivative instruments are primarily with financial institutions and thus are subject to events that would impact those companies individually as well as that industry as a whole.
The Company utilizes various processes and analyses to monitor and evaluate its credit risk exposures. These include closely monitoring current market conditions, counterparty credit fundamentals and credit default swap rates. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security.
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When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the financial institution acting as counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Condensed Consolidated Balance Sheets as of September 30, 2013 or December 31, 2012.
When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. The Company 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 Company records these deposits as a current asset in the Condensed Consolidated Balance Sheets. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the related contract. The margin requirements are subject to change at the exchanges’ discretion. The Company recorded a current asset of $0.4 million as of September 30, 2013 and a current asset of $0.7 million as of December 31, 2012 for such deposits in its Condensed Consolidated Balance Sheets.
The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. Margin deposits remitted to financial counterparties or received from financial counterparties related to OTC natural gas swap agreements and options and any funds remitted to or deposits received from the Company’s brokers related to exchange-traded natural gas contracts are also recorded on a gross basis. The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of September 30, 2013 and December 31, 2012.
As of September 30, 2013
Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross
Derivative instruments subject to master netting agreements
Margin deposits remitted to counterparties
Derivative instruments, net
Asset derivatives:
(17,824)
185,178
Liability derivatives:
(428)
101
As of December 31, 2012
(73,753)
230,484
(736)
1,073
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Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by Standard & Poor’s Rating Services (S&P) or Moody’s Investor Services (Moody’s) are lowered below investment grade, additional collateral must be deposited with the counterparty. The additional collateral can be up to 100% of the derivative liability. As of September 30, 2013, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $0.4 million, for which the Company had no collateral posted on September 30, 2013. If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on September 30, 2013, the Company would have been required to post additional collateral of $0.3 million in respect of the liability position. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s senior unsecured debt was rated BBB by S&P and Baa3 by Moody’s at September 30, 2013. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade.
E. Fair Value Measurements
The Company records its financial instruments, principally derivative instruments, at fair value in its Condensed Consolidated Balance Sheets. The Company has an established process for determining fair value which is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, volatilities and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk-free instrument. The Company also considers credit default swaps rates where applicable.
The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities included in Level 1 include the Company’s futures contracts. Assets and liabilities in Level 2 include the majority of the Company’s swap agreements. Assets and liabilities in Level 3 include the Company’s collars and a limited number of the Company’s swap agreements. Since the adoption of fair value accounting, the Company has not made any changes to its classification of assets and liabilities in each category.
The fair value of assets and liabilities included in Level 2 is based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves and LIBOR-based discount rates. Collars included in Level 3 are valued using standard industry income approach models. The primary significant unobservable input to the valuation of assets and liabilities in Level 3 is the volatility assumption to the option pricing model used to value commodity collars. The Company’s Corporate Risk Control Group (CRCG), which reports to the Chief Financial Officer, is responsible for calculating the volatilities. The CRCG considers current market information about option trading and historical averages. The Company prepares an analytical review of all derivative instruments for reasonableness on at least a quarterly basis. At September 30, 2013, derived market volatilities used to value Level 3 assets and liabilities ranged from 21% to 30%. The fair value of the collar agreements is sensitive to changes in the volatility assumption. Significant changes in this assumption might result in significantly higher or lower fair values for these assets and liabilities. As of September 30, 2013, an increase in the volatility assumption would increase the value of the derivative asset and a decrease in the volatility assumption would decrease the value of the derivative asset.
The Company uses NYMEX forward curves to value futures, commodity swaps and collars. The NYMEX forward curves and LIBOR-based discount rates are validated to external sources at least monthly.
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The following derivative instrument assets and liabilities were measured at fair value on a recurring basis during the applicable period:
Fair value measurements at reporting date using
Description
September 30, 2013
Quoted prices in active markets for identical assets (Level 1)
Significant other observable inputs (Level 2)
Significant unobservable inputs (Level 3)
Assets
453
133,413
69,136
Liabilities
647
16,891
815
December 31, 2012
1,228
204,592
98,417
1,609
66,250
7,703
Fair value measurements using significant unobservable inputs (Level 3)
Derivative instruments, at fair value, net Three Months Ended September 30,
Derivative instruments, at fair value, net Nine Months Ended September 30,
Beginning of period
74,688
129,436
90,714
143,260
Total gains or losses:
Included in earnings
414
(90)
(341)
(90
Included in OCI
2,067
(13,839)
3,459
13,554
Purchases
(79
22
(7)
(994
Settlements
(8,769
(18,558)
(25,504)
(58,759
Transfers in and/or out of Level 3
End of period
68,321
96,971
Gains of $0.4 million and losses of $0.8 million are included in earnings in the table above for the three and nine months ended September 30, 2013, respectively, attributable to the change in unrealized gains or losses relating to assets held as of September 30, 2013. There were no gains or losses included in earnings in the table above for the
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three and nine months ended September 30, 2012 attributable to the change in unrealized gains or losses relating to assets and liabilities held as of September 30, 2012.
The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments; these are considered Level 1 fair values.
The Company estimates the fair value of its debt using its established fair value methodology. Because not all of the Company’s debt is actively traded, the fair value of the debt is a Level 2 fair value measurement. Fair value for non-traded debt obligations is estimated using a standard industry income approach model which utilizes a discount rate based on market rates for debt with similar remaining time to maturity and credit risk. The estimated fair value of long-term debt on the Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012 was approximately $2.8 billion and $2.9 billion, respectively.
F. 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. However, while all of the Partnership’s earnings are included in the Company’s net income, the Company is not required to record income tax expense with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners, which reduces the Company’s effective tax rate for periods following the IPO. Any refinements made due to subsequent information that affects the estimated annual effective income tax rate are reflected as adjustments in the current period.
The Company’s effective income tax rate for the nine months ended September 30, 2013 was 29.9%, compared to 33.6% for the nine months ended September 30, 2012. The decrease in the first nine months of 2013 was primarily attributable to unfavorable state net operating loss adjustments recorded in 2012, a reduction in a state net operating loss valuation allowance related to bonus depreciation recorded in 2013 and the impact of the Partnership’s ownership structure, partially offset by increased state tax expense in 2013 due to higher natural gas prices and production sales volumes.
During the third quarter of 2013, as a result of the Sunrise transaction described in Note B, the Company reversed $1.6 million of net deferred tax assets to account for the related temporary differences between book and tax basis that will no longer impact the Company.
There were no material changes to the Company’s methodology for determining unrecognized tax benefits during the three months ended September 30, 2013. The Company’s consolidated federal income tax liability has been settled with the Internal Revenue Service (IRS) through 2009. During the second quarter of 2013, the IRS began its examination of the Company’s 2010 and 2011 tax years. The Company believes that it is appropriately reserved for any federal and state uncertain tax positions.
On July 9, 2013, Pennsylvania House Bill 465 was signed into law by the Governor of the Commonwealth of Pennsylvania (the Commonwealth). This legislation adopted multiple changes to the Commonwealth’s tax code, including an intangible expense addback provision effective in 2015, an increase of the cap on the net operating loss deduction in 2014 and 2015 and an extension of the franchise tax through 2015. This law change did not have a material impact on the Company’s financial statements.
In September 2013, the United States Treasury Department issued final tax regulations regarding the deduction and capitalization of expenditures related to tangible property and proposed regulations addressing the disposition of tangible property. The regulations do not address the tax treatment for network assets such as natural gas pipelines. The final regulations are effective for tax years beginning January 1, 2014, with optional adoption in 2013, and replace previously issued temporary regulations. The Company performed an initial analysis of the final and proposed regulations and believes that they will not have a material impact on its financial statements.
G. Revolving Credit Facilities
As of September 30, 2013 and December 31, 2012, the Company did not have any loans or letters of credit outstanding under its $1.5 billion revolving credit facility. The Company incurred commitment fees averaging
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approximately 6 basis points and 18 basis points in the three and nine months ended September 30, 2013, respectively, and approximately 5 basis points and 19 basis points in the three and nine months ended September 30, 2012, respectively, to maintain credit availability under its revolving credit facility.
The maximum amount of the Company’s outstanding short-term loans at any time was $140.5 million and $178.5 million during the three and nine months ended September 30, 2013, respectively. The average daily balance of short-term loans outstanding was approximately $21.5 million and $16.1 million during the three and nine months ended September 30, 2013, respectively, at weighted average interest rates of 0.60% and 0.70%, respectively.
As of September 30, 2013 and December 31, 2012, the Partnership had no loans or letters of credit outstanding under its $350 million revolving credit facility. The Partnership incurred commitment fees averaging approximately 6 basis points and 19 basis points in the three and nine months ended September 30, 2013, respectively, and approximately 6 basis points in the three months ended September 30, 2012, to maintain credit availability under its revolving credit facility. The Partnership did not have any short-term loans outstanding at any time during the three and nine months ended September 30, 2013 and 2012.
H. Long-Term Debt
7.76% notes, due 2013 thru 2016
18,679
32,973
5.00% notes, due October 1, 2015
150,000
5.15% notes, due March 1, 2018
200,000
6.50% notes, due April 1, 2018
500,000
8.13% notes, due June 1, 2019
700,000
4.88% notes, due November 15, 2021
750,000
7.75% debentures, due July 15, 2026
115,000
Medium-term notes:
7.3% to 7.6% Series B, due 2013 thru 2023
20,000
30,000
8.7% to 9.0% Series A, due 2014 thru 2021
40,200
7.6% Series C, due 2018
8,000
2,501,879
2,526,173
Less debt payable within one year
Total long-term debt
The indentures and other agreements governing the Company’s indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict the Company’s ability to incur indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in the Company’s debt rating would not trigger a default under the indentures and other agreements governing the Company’s indebtedness.
Aggregate maturities of long-term debt are zero for the remainder of 2013, $11.2 million in 2014, $166.0 million in 2015, $3.0 million in 2016 and zero in 2017.
I. Proposed Sale of Properties
On December 19, 2012, the Company and its direct wholly-owned subsidiary, Holdco, executed the Master Purchase Agreement with PNG Companies, the parent company of Peoples, pursuant to which the Company and Holdco will transfer 100% of their ownership interests of Equitable Gas and Homeworks to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Peoples is a portfolio company of SteelRiver Infrastructure Fund North America LP.
The Company has submitted filings with the Pennsylvania Public Utility Commission (PA PUC), the West Virginia Public Service Commission (WV PSC) and the Federal Energy Regulatory Commission (FERC) – each must approve the transaction in whole or in part as part of the regulatory process. The Company expects to complete the regulatory review process by the end of 2013. The Company also submitted a filing with the Kentucky Public Service
19
Commission (KY PSC), which issued a ruling that it is not asserting jurisdiction with regard to the assets being conveyed. Therefore, approval by the KY PSC is not required. The transaction was also subject to review by the Federal Trade Commission (FTC) under the Hart-Scott Rodino Antitrust Improvements Act (HSR Act). The waiting period under the HSR Act expired on April 22, 2013, without a request for additional information. This expiration indicates that the FTC has not objected to the transaction and that, from an HSR Act perspective, the parties may complete the transaction. As the transaction is still subject to approval by the PA PUC, the WV PSC and, in some respects, the FERC, the Company has not classified Equitable Gas and Homeworks as held for sale in its financial statements as of September 30, 2013 and will not do so until the Company makes satisfactory progress in the regulatory process.
The Company incurred $0.4 million and $3.3 million in expenses during the three and nine months ended September 30, 2013, respectively, related to the proposed sale of Equitable Gas and Homeworks, which expenses are reported in selling, general and administrative expenses in the Statements of Consolidated Income.
J. Earnings Per Share
Potentially dilutive securities, consisting of options and restricted stock awards, which were included in the calculation of diluted earnings per share, totaled 984,388 and 784,079 for the three months ended September 30, 2013 and 2012, respectively, and 856,112 and 715,512 for the nine months ended September 30, 2013 and 2012, respectively. There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the three and nine months ended September 30, 2013. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 3,228 and 281,528 for the three and nine months ended September 30, 2012, respectively.
The Partnership’s dilutive units did not have a material impact on the Company’s earnings per share calculation for any of the periods presented.
K. Changes in Accumulated Other Comprehensive Income by Component
The following tables explain the changes in accumulated OCI by component for the three and nine months ended September 30, 2013:
Three Months Ended September 30, 2013
Natural gas cash flow hedges, net of tax
Interest rate cash flow hedges, net of tax
Pension and other post-retirement benefits liability adjustment, net of tax
Accumulated OCI (loss), net of tax
Accumulated OCI (loss), net of tax, as of July 1, 2013
122,693
(1,204)
(36,496)
84,993
Gains recognized in accumulated OCI, net of tax
(a)
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax
(26,020)
(b)
(25,551
Change in accumulated OCI, net of tax
(8,287)
Accumulated OCI (loss), net of tax, as of September 30, 2013
114,406
(1,168)
(36,063)
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Nine Months Ended September 30, 2013
Pension and other post- retirement benefits liability adjustment, net of tax
Accumulated OCI (loss), net of tax, as of January 1, 2013
138,188
(1,276)
(37,365)
(62,343)
(60,933)
Change in accumulated other comprehensive (loss) income, net of tax
(23,782)
(22,372)
(a) See Note D for additional information.
(b) This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 14 to the Consolidated Financial Statements in the Company’s Form 10-K for the year ended December 31, 2012 for additional information.
L. Acquisitions
On June 3, 2013, the Company acquired approximately 99,000 net acres in southwestern Pennsylvania and ten horizontal Marcellus wells, located in Washington County, Pennsylvania, from Chesapeake Energy Corporation and its partners (Chesapeake) for approximately $114.6 million. The acreage includes 67,000 Marcellus acres, of which 42,000 acres are unlikely to be developed due to near-term lease expirations or a scattered footprint. Of the total purchase price, $56.7 million was allocated to the undeveloped acreage and $57.9 million was allocated to the acquired Marcellus wells. The Marcellus wells are expected to add approximately 2.0 Bcfe of production sales volumes in 2013 and represent approximately 54.0 Bcfe of proved developed reserves.
As the transaction qualifies as a business combination under United States GAAP, the fair value of the acquired assets was determined using a market approach for the undeveloped acreage and a discounted cash flow model under the income approach for the wells. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and NYMEX forward pricing, which classify the acquired assets as a Level 3 measurement.
M. Recently Issued Accounting Standards
In July 2013, the Financial Accounting Standards Board issued a standard update on the presentation of certain unrecognized tax benefits in the financial statements. The standard requires unrecognized tax benefits to be offset against deferred tax assets for a net operating loss carryforward, similar tax loss or tax credit carryforward in certain situations. The Company early adopted this standard in its financial statements during the quarter ended September 30, 2013. The standard did not have a material impact on the Company’s financial statements.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
CAUTIONARY STATEMENTS
Disclosures in this Quarterly Report on Form 10-Q contain certain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Statements that do not relate strictly to historical or current facts are forward-looking and usually identified by the use of words such as “anticipate,” “estimate,” “could,” “would,” “will,” “may,” “forecast,” “approximate,” “expect,” “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 Quarterly Report on Form 10-Q include the matters discussed in the section captioned “Outlook” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the expectations of plans, strategies, objectives and growth and anticipated financial and operational performance of the Company and its subsidiaries, including guidance regarding the Company’s strategy to develop its Marcellus and other reserves; drilling plans and programs (including the number, type, feet of pay and location of wells to be spud and the availability of capital to complete these plans and programs); production and sales volumes and growth rates (including liquids sales volumes and the projected additional production sales volumes attributable to the Marcellus wells acquired in the second quarter of 2013); gathering and transmission growth and volumes; infrastructure programs (including the timing, cost and capacity of the transmission and gathering expansion projects); technology (including drilling techniques); monetization transactions, including midstream asset sales (dropdowns) to EQT Midstream Partners, LP, the Company’s publicly-traded master limited partnership formed in 2012 (the Partnership), and other asset sales, and joint ventures or other transactions involving the Company’s assets (including the timing of receipt, if at all, of any additional consideration from the Partnership for new transportation agreements entered into by the Partnership in connection with the Company’s sale of its Sunrise Pipeline); the proposed transfer of Equitable Gas Company, LLC (Equitable Gas) to PNG Companies LLC; the timing of receipt of required approvals for the proposed Equitable Gas transaction; natural gas prices; reserves; projected capital expenditures; liquidity and financing requirements, including funding sources and availability; hedging strategy; the effects of government regulation and litigation; and tax position (including the Company’s ability to complete like-kind exchanges). The forward-looking statements in this Quarterly Report on Form 10-Q involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The Company has based these forward-looking statements on current expectations and assumptions about future events. While the Company considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. With respect to the proposed Equitable Gas transaction, these risks and uncertainties include, among others, the ability to obtain regulatory approvals for the transaction on the proposed terms and schedule; disruption to the Company’s business, including customer, employee and supplier relationships resulting from the transaction; and risks that the conditions to closing may not be satisfied. 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” in the Company’s Form 10-K for the year ended December 31, 2012.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company does not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
In reviewing any agreements incorporated by reference in or filed with this Quarterly Report on Form 10-Q, please remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about the Company. The agreements may contain representations and warranties by the Company, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties should those statements prove to be inaccurate. The representations and warranties were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.
CORPORATE OVERVIEW
Three Months Ended September 30, 2013 vs. Three Months Ended September 30, 2012
Net income attributable to EQT Corporation for the three months ended September 30, 2013 was $88.3 million, $0.58 per diluted share, compared with $31.9 million, $0.21 per diluted share, for the three months ended September 30, 2012. The $56.4 million increase in net income attributable to EQT Corporation between periods resulted primarily from a 42% increase in natural gas volumes sold, a 4% increase in the average effective sales price for natural gas and natural gas liquids (NGLs) and increases in transmission pipeline throughput and gathered volumes. These increases were partially offset by higher depreciation, depletion and amortization (DD&A) expense and higher income tax expense.
The average effective sales price to EQT Corporation for production sales volumes was $4.20 per Mcfe during the three months ended September 30, 2013 compared to $4.04 per Mcfe in the same period of 2012. The Company’s average New York Mercantile Exchange (NYMEX) natural gas sales price increased to $3.58 per Mcf for the three months ended September 30, 2013 compared to $2.81 per Mcf for the three months ended September 30, 2012. Hedging activities resulted in an increase in the effective sales price of $0.55 per Mcfe in the third quarter of 2013 compared to an increase of $1.10 per Mcfe in the third quarter of 2012. The $0.55 per Mcfe decrease in the impact of hedging activities from 2012 to 2013 was the result of the differential in the NYMEX natural gas sales prices between periods and lower average hedge prices in 2013. Due to the increased supply of natural gas in the Northeast region, average basis was negative $0.26 per Mcfe during the three months ended September 30, 2013, a decrease of $0.23 per Mcfe compared to the three months ended September 30, 2012.
Interest expense was $4.9 million lower during the three months ended September 30, 2013 compared to the three months ended September 30, 2012, primarily as a result of the Company’s repayment of $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $23.2 million of debentures that matured in the first nine months of 2013. The Company also had higher capitalized interest during the third quarter of 2013 from increased Marcellus well development.
Income tax expense increased $23.2 million during the three months ended September 30, 2013 compared to the three months ended September 30, 2012, primarily as a result of higher pre-tax income and a higher effective tax rate in the third quarter of 2013. The Company’s effective tax rate was 25.3% and 24.0% for the three month periods ended September 30, 2013 and 2012, respectively. The overall rates were favorably impacted by the Partnership’s ownership structure. While all of the Partnership’s earnings are included in the Company’s net income for both periods, the Company was not required to record income tax expense with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners. The effective income tax rate was also favorably impacted in 2013 by the reversal of state tax reserves. In 2012, the effective income tax rate was favorably impacted by lower income on state tax paying entities and a tax benefit recorded to reflect a 2011 tax return that was filed during the third quarter of 2012.
Net income attributable to noncontrolling interests of the Partnership was $14.4 million for the three months ended September 30, 2013 compared to $4.8 million for the three months ended September 30, 2012. The increase resulted from increased capacity reservation revenues, as well as increased noncontrolling interests. Noncontrolling interests in the Partnership increased from 40.6% to 55.4% during the three months ended September 30, 2013 as a result of the public offering of additional commons units representing limited partnership interests in the Partnership in July 2013.
Nine Months Ended September 30, 2013 vs. Nine Months Ended September 30, 2012
Net income attributable to EQT Corporation for the nine months ended September 30, 2013 was $275.4 million, $1.82 per diluted share, compared with $135.4 million, $0.90 per diluted share, for the nine months ended September 30, 2012. The $140.0 million increase in net income attributable to EQT Corporation between periods was primarily attributable to a 47% increase in natural gas volumes sold, increases in transmission pipeline throughput and gathered volumes and colder weather. The increases were partially offset by higher DD&A expense, higher income tax expense and higher selling, general and administrative (SG&A) expense due to higher compensation expenses.
The average effective sales price to EQT Corporation for production sales volumes was $4.28 per Mcfe during the nine months ended September 30, 2013 compared to $4.21 per Mcfe in the same period of 2012. The Company’s
23
average NYMEX natural gas sales price increased to $3.67 per Mcf for the nine months ended September 30, 2013 from $2.59 per Mcf for the nine months ended September 30, 2012. Hedging activities resulted in an increase in the effective sales price of $0.40 per Mcfe in the first nine months of 2013 compared to an increase of $1.30 per Mcfe in the first nine months of 2012. The $0.90 per Mcfe decrease in the impact of hedging activities from 2012 to 2013 was the result of the differential in the NYMEX natural gas sales prices between periods and the lower average hedge prices in 2013.
Other income was $6.8 million for the nine months ended September 30, 2013 compared to $13.8 million for the nine months ended September 30, 2012. The $7.0 million decrease is primarily attributable to a decrease in the allowance for funds used during construction, as a result of the Sunrise Pipeline being placed into service during the third quarter of 2012, and a gain recognized on the sale of leases in the nine months ended September 30, 2012.
Interest expense was $11.7 million lower in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, primarily as a result of the Company’s repayment of $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $23.2 million of debentures that matured in the first nine months of 2013. The Company also had higher capitalized interest during the first nine months of 2013 from increased Marcellus well development.
Income tax expense increased $59.8 million during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, primarily as a result of higher pre-tax income. The Company’s effective income tax rate also decreased to 29.9% from 33.6%. This decrease in the first nine months of 2013 was primarily attributable to unfavorable state net operating loss adjustments recorded in 2012, a reduction in a state net operating loss valuation allowance related to bonus depreciation recorded in 2013 and the impact of the Partnership’s ownership structure, partially offset by increased state tax expense in 2013 due to higher production sales volumes and natural gas prices.
Net income attributable to noncontrolling interests of the Partnership, which completed its initial public offering (IPO) in the third quarter of 2012, was $30.6 million for the nine months ended September 30, 2013 compared to $4.8 million for the nine months ended September 30, 2012. The increase resulted from increased capacity reservation revenues during the nine months ended September 30, 2013, as well as increased noncontrolling interests. Noncontrolling interests in the Partnership increased from 40.6% to 55.4% during the nine months ended September 30, 2013 as a result of the public offering of additional common units representing limited partnership interests in the Partnership in July 2013.
See “Investing Activities” under the caption “Capital Resources and Liquidity” for a discussion of capital expenditures.
Consolidated Operational Data
Revenues earned by the Company at the wellhead from the sale of natural gas are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average effective sales price. The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist the understanding of the Company’s consolidated operations.
24
%
in thousands (unless noted)
LIQUIDS
NGLs:
Sales Volume (MMcfe) (a)
4,391
3,190
37.6
13,623
9,364
45.5
Sales Volume (Mbbls)
1,150
853
34.8
3,578
2,490
43.7
Gross Price ($/Bbl)
38.06
39.33
(3.2
40.38
45.30
(10.9
Gross NGL Revenue
43,786
33,545
30.5
144,469
112,807
28.1
BTU Premium (Ethane sold as natural gas):
Sales Volume (MMbtu)
8,244
5,889
40.0
21,364
15,602
36.9
Price ($/MMbtu)
3.58
2.81
27.4
3.69
2.59
42.5
BTU Premium Revenue
29,494
16,524
78.5
78,741
40,477
94.5
Oil:
473
384
23.2
1,169
1,152
1.5
79
64
23.4
195
192
1.6
Net Price ($/Bbl)
94.78
80.25
18.1
87.43
83.43
4.8
Net Oil Revenue
7,488
5,136
45.8
17,049
16,020
6.4
Total Liquids Revenue
80,768
55,205
46.3
240,259
169,304
41.9
GAS
Sales Volume (MMcf)
92,076
64,639
42.4
253,956
171,764
47.9
NYMEX Price ($/Mcf) (b)
Gas Revenue
329,416
181,377
81.6
936,013
445,322
110.2
Basis
(25,117
(1,952
1,186.7
(26,250
(1,705
1,439.6
Gross Gas Revenue (unhedged)
304,299
179,425
69.6
909,763
443,617
105.1
Total Gross Gas & Liquids Revenue (unhedged)
385,067
234,630
64.1
1,150,022
612,921
87.6
Hedge impact (c)
53,424
75,074
(28.8
106,650
237,218
(55.0
Total Gross Gas & Liquids Revenue
438,491
309,704
41.6
1,256,672
850,139
47.8
Total Sales Volume (MMcfe)
96,940
68,213
42.1
268,748
182,280
47.4
Average hedge adjusted price ($/Mcfe)
4.52
4.54
(0.4
4.68
4.66
0.4
Midstream Revenue Deductions ($ / Mcfe)
Gathering to EQT Midstream
(0.84
(1.00
(16.0
(0.85
(1.04
(18.3
Transmission to EQT Midstream
(0.23
(0.19
21.1
(0.24
(0.18
33.3
Third-party gathering and transmission (d)
(0.22
(0.40
(45.0
(0.29
(0.35
(17.1
Third-party processing
(0.10
0.0
(0.11
10.0
Total midstream revenue deductions
(1.39
(1.69
(17.8
(1.49
(1.67
(10.8
Average effective sales price to EQT Production
3.13
2.85
9.8
3.19
2.99
6.7
EQT Revenue ($ / Mcfe)
Revenues to EQT Midstream
1.07
1.19
(10.1
1.09
1.22
(10.7
Revenues to EQT Production
Average effective sales price to EQT Corporation
4.20
4.04
4.0
4.28
4.21
1.7
(a) NGLs were converted to Mcfe at the rates of 3.82 Mcfe per barrel and 3.74 Mcfe per barrel based on the liquids content for the three months ended September 30, 2013 and 2012, respectively, and 3.81 Mcfe per barrel and 3.76 Mcfe per barrel based on the liquids content for the nine months ended September 30, 2013 and 2012, respectively. Crude oil was converted to Mcfe at the rate of six Mcfe per barrel for all periods.
25
(b) The Company’s volume weighted NYMEX natural gas price (actual average NYMEX natural gas price ($/Mcf) was $3.58 and $2.81 for the three months ended September 30, 2013 and 2012, respectively, and $3.67 and $2.59 for the nine months ended September 30, 2013 and 2012, respectively).
(c) Includes gains of $6.4 million, $0.07 per Mcfe, and $6.4 million, $0.02 per Mcfe for the three and nine months ended September 30, 2013, respectively, related to the sale of fixed price natural gas.
(d) Due to the sale of unused capacity on the El Paso 300 line that was not under long-term resale agreements at prices below the capacity charge, third-party gathering and transmission rates increased by $0.05 per Mcfe and $0.06 per Mcfe for the three and nine months ended September 30, 2013, respectively. The unused capacity on the El Paso 300 line not under long-term resale agreements was sold at prices below the capacity charge, increasing third-party gathering and transmission rates by $0.07 per Mcfe and $0.03 per Mcfe for the three and nine months ended September 30, 2012, respectively.
Business Segment Results
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. The Company’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 the Company’s business segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and other income. In addition, management uses these measures for budget planning purposes. The Company’s management reviews and reports the EQT Production segment results with third-party transportation costs reflected as a deduction from operating revenues, as management believes this presentation provides a more useful view of net effective price and is consistent with industry practices. Third-party transportation costs are reported as a component of purchased gas costs in the consolidated results. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note C to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income, interest 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 headquarter expenses totaling $5.5 million and $19.6 million were not allocated to the operating segments for the three and nine months ended September 30, 2013, respectively. The unallocated expenses for both periods consist primarily of incentive compensation expenses, and general and administrative costs and expenses related to the pending sale of Equitable Gas and Equitable Homeworks, LLC (Homeworks).
26
EQT PRODUCTION
RESULTS OF OPERATIONS
OPERATIONAL DATA
Sales volume detail (MMcfe):
Horizontal Marcellus Play (a)
72,361
41,486
74.4
194,928
100,551
93.9
Horizontal Huron Play
7,293
8,934
(18.4
22,824
28,452
(19.8
CBM Play
3,108
3,282
(5.3
9,340
9,868
(5.4
14,178
14,511
(2.3
41,656
43,409
(4.0
Total production sales volumes
Average daily sales volumes (MMcfe/d)
1,054
741
42.2
984
665
48.0
Average effective sales price to EQT Production ($/Mcfe)
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)
0.15
0.18
(16.7
0.16
0.19
(15.8
Production taxes ($/Mcfe) (b)
0.14
(12.5
0.17
(17.6
Production depletion ($/Mcfe)
1.53
1.56
(1.9
1.55
(1.3
DD&A (thousands):
Production depletion
148,362
106,196
39.7
412,514
283,152
45.7
Other DD&A
2,275
2,008
13.3
7,105
6,024
17.9
Total DD&A (thousands)
39.2
45.1
Capital expenditures (thousands) (c)
30.2
38.9
FINANCIAL DATA (thousands)
Total net operating revenues
55.8
56.7
LOE, excluding production taxes
14,801
12,257
20.8
42,452
34,991
21.3
Production taxes (b)
13,275
10,944
38,260
37,805
1.2
Exploration expense
351.9
210.0
SG&A
22,662
24,193
(6.3
68,666
67,214
2.2
DD&A
206,631
156,761
31.8
584,121
434,064
34.6
153.3
140.1
(a) Includes Upper Devonian wells.
(b) Production taxes include severance and production-related ad valorem and other property taxes and the Pennsylvania impact fee. The Pennsylvania impact fee for the nine months ended September 30, 2013 totaled $8.8 million. The Pennsylvania impact fee for the nine months ended September 30, 2012 totaled $13.2 million, of which $6.7 million represented the retroactive fee for pre-2012 Marcellus wells. The production taxes unit rate for the nine months ended September 30, 2012 excludes the impact of the accrual for pre-2012 Marcellus wells.
(c) Includes $2.1 million and $114.6 million of capital expenditures for the purchase of acreage and Marcellus wells from Chesapeake Energy Corporation and its partners (Chesapeake) during the three and nine months ended September 30, 2013, respectively.
27
EQT Production’s operating income totaled $97.6 million for the three months ended September 30, 2013 compared to $38.5 million for the three months ended September 30, 2012. The $59.1 million increase in operating income was primarily due to an increase in sales of produced natural gas and a higher average effective sales price partially offset by an increase in operating expenses.
Total net operating revenues were $304.2 million for the three months ended September 30, 2013 compared to $195.3 million for the three months ended September 30, 2012. The $108.9 million increase in net operating revenues was primarily due to a 42% increase in production sales volumes and a 10% increase in the average effective sales price to EQT Production. The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.
The $0.28 per Mcfe increase in the average effective sales price to EQT Production was primarily due to a 27% increase in the average NYMEX natural gas price, increase in margins from fixed priced sales and lower gathering rates and midstream charges partially offset by a smaller hedge gain and lower NGL and basis prices compared to the same period of 2012. During the third quarter of 2013, hedging gains included a gain for ineffectiveness of $3.6 million as a result of the change in basis.
Operating expenses totaled $206.6 million for the three months ended September 30, 2013 compared to $156.8 million for the three months ended September 30, 2012. The increase in operating expenses was the result of increases in DD&A expense, exploration expense, LOE and production taxes partially offset by a decrease in SG&A expense. DD&A expense increased as a result of higher production sales volumes in the current year partially offset by a lower overall depletion rate in 2013. The increase in exploration expense was due to increased impairments of unproved lease acreage resulting from lease expirations during the third quarter of 2013. The increase in LOE was mainly due to increased Marcellus activity. The decrease in SG&A expense was primarily a result of a decrease in franchise taxes offset by higher personnel costs including incentive compensation expenses.
Production taxes increased in the third quarter of 2013 compared to the third quarter of 2012 primarily due to a $2.4 million increase in severance taxes as the result of higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes and a $1.2 million increase in the Pennsylvania impact fee. The increase in severance taxes and the Pennsylvania impact fee were partially offset by a $1.3 million decrease in property taxes.
EQT Production’s operating income totaled $276.8 million for the nine months ended September 30, 2013 compared to $115.3 million for the nine months ended September 30, 2012. The $161.5 million increase in operating income was primarily due to an increase in sales of produced natural gas and a higher average effective sales price partially offset by an increase in operating expenses.
Total net operating revenues were $860.9 million for the nine months ended September 30, 2013 compared to $549.3 million for the nine months ended September 30, 2012. The $311.6 million increase in net operating revenues was primarily due to a 47% increase in production sales volumes and a 7% increase in the average effective sales price to EQT Production. The increase in production sales volumes was the result of increased production from the 2011 and 2012 drilling programs, primarily in the Marcellus play. This increase was partially offset by the normal production decline in the Company’s producing wells.
The $0.20 per Mcfe increase in the average effective sales price to EQT Production was primarily due to a 42% increase in the average NYMEX natural gas price, increase in margins from fixed priced sales and lower midstream charges and gathering rates partially offset by a smaller hedge gain and lower NGL and basis prices compared to the same period of 2012. During the first nine months of 2013, hedging gains included a loss for ineffectiveness of $4.5 million as a result of the change in basis. The first nine months of 2012 included an unfavorable adjustment of $8.2 million to recognize financial instrument put premiums that should have been recorded ratably over 2010 and 2011.
Operating expenses totaled $584.1 million for the nine months ended September 30, 2013 compared to $434.1 million for the nine months ended September 30, 2012. The increase in operating expenses was the result of
28
increases in DD&A expense, exploration expense, LOE, SG&A expense and production taxes. DD&A expense increased as a result of higher production sales volumes in the current year partially offset by a slightly lower overall depletion rate. The increase in exploration expense was due to increased impairments of unproved lease acreage resulting from lease expirations during the nine months ended September 30, 2013, partially offset by a reduction in geophysical activity compared to the prior year. The increase in LOE was mainly due to increased Marcellus activity. The increase in SG&A expense was primarily a result of higher personnel costs, including incentive compensation expenses, higher environmental reserves for remediation and higher commercial allocations partially offset by a decrease in professional services and franchise taxes.
Production taxes increased in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, primarily due to an $8.4 million increase in severance taxes related to higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes. Severance taxes were offset by a $4.4 million decrease in the Pennsylvania impact fee and a $3.5 million decrease in property taxes as a result of lower assessments received during 2013. During the first nine months of 2013, the Pennsylvania impact fee was $8.8 million compared to $13.2 million in the first nine months of 2012, of which $6.7 million represented a retroactive fee for pre-2012 Marcellus wells.
EQT MIDSTREAM
Gathered volumes (BBtu)
125,139
87,318
43.3
342,502
235,877
45.2
Average gathering fee ($/MMBtu)
0.73
0.88
(17.0
0.76
0.93
Gathering and compression expense ($/MMBtu)
0.24
(29.2
0.26
(30.8
Transmission pipeline throughput (BBtu)
111,309
59,746
86.3
297,126
148,870
99.6
Net operating revenues (thousands):
Gathering
91,825
77,034
19.2
260,631
218,411
19.3
Transmission
39,962
26,563
50.4
116,105
71,018
63.5
Storage, marketing and other
8,165
5,362
52.3
23,426
34,956
(33.0
139,952
108,959
28.4
400,162
324,385
Unrealized gains (losses) on derivatives and inventory (thousands) (a)
3,449
(3,018)
214.3
6,411
(4,946)
229.6
Capital expenditures (thousands)
14.9
(14.3
Total operating revenues
29.2
24.8
15,725
11,525
36.4
52,569
38,245
37.5
Operating and maintenance (O&M)
25,720
25,441
1.1
72,329
73,245
16,769
15,325
9.4
47,239
37,369
26.4
10.2
18.6
61,419
57,938
6.0
175,169
157,478
11.2
53.9
(a) Included within storage, marketing and other net operating revenues.
29
EQT Midstream’s operating income totaled $78.5 million for the three months ended September 30, 2013 compared to $51.0 million for the three months ended September 30, 2012. The increase in operating income was primarily the result of increased gathering and transmission net operating revenues, partially offset by increased operating expenses.
Total net operating revenues were $140.0 million for the three months ended September 30, 2013 compared to $109.0 million for the three months ended September 30, 2012. The $14.8 million increase in gathering net operating revenues was due to a 43% increase in gathered volumes partially offset by a 17% decrease in the average gathering fee. The increase in gathered volumes was driven primarily by higher volumes gathered for EQT Production in the Marcellus play. The average gathering fee decreased primarily from lower gathered volumes in the Huron play and increased gathered volumes in the Marcellus play, as the Marcellus gathering rate is lower than the rate in the Huron and other areas. In addition, during the three months ended September 30, 2013, the Marcellus gathering rate charged to affiliates decreased by $0.11 per unit as compared to the same period in 2012 due to greater economies of scale achieved in recent periods.
Transmission net operating revenues increased $13.4 million primarily as a result of an additional $13.0 million of firm capacity reservation revenues and usage charges.
Storage, marketing and other net operating revenues increased due to unrealized gains on derivatives and inventory, partially offset by lower realized margins and reduced activity.
Total operating revenues increased $35.2 million primarily as a result of increased gathered volumes and increased transmission revenues. Purchased gas costs increased $4.2 million primarily as a result of an increase in commodity prices.
Operating expenses totaled $61.4 million for the three months ended September 30, 2013 compared to $57.9 million for the three months ended September 30, 2012. The increase in operating expenses was primarily due to increased DD&A expense as a result of additional assets placed in-service and increased personnel costs including incentive compensation expenses.
EQT Midstream’s operating income totaled $225.0 million for the nine months ended September 30, 2013 compared to $166.9 million for the nine months ended September 30, 2012. The increase in operating income was primarily the result of increased transmission and gathering net operating revenues partially offset by increased operating expenses and a decrease in storage, marketing and other net operating revenues.
Total net operating revenues were $400.2 million for the nine months ended September 30, 2013 compared to $324.4 million for the nine months ended September 30, 2012.
Transmission net operating revenues increased $45.1 million primarily as a result of $32.7 million of additional firm capacity reservation revenues and usage charges, $10.3 million of fees associated with transported volumes in excess of firm capacity and increased pipeline safety revenues.
Gathering net operating revenues increased due to a 45% increase in gathered volumes partially offset by an 18% decrease in the average gathering fee. The increase in gathered volumes was driven primarily by higher volumes gathered for EQT Production in the Marcellus play. The average gathering fee decreased primarily from lower gathered volumes in the Huron play and increased gathered volumes in the Marcellus play, as the Marcellus gathering rate is lower than the rate in the Huron and other areas. In addition, during the nine months ended September 30, 2013, the Marcellus gathering rate charged to affiliates decreased by $0.09 per unit as compared to the same period in 2012 due to greater economies of scale achieved in recent periods.
Storage, marketing and other net operating revenues decreased primarily as a result of lower realized margins and reduced activity due to lower price spreads. In addition, revenues on NGLs marketed for non-affiliated producers decreased by $2.9 million primarily as a result of lower liquids pricing partially offset by slightly higher liquids
30
volumes. These decreases were partially offset by an $11.4 million favorable change in unrealized gains (losses) on derivatives and inventory.
Total operating revenues increased $90.1 million primarily as a result of increased transmission and gathering revenues. Purchased gas costs increased $14.3 million primarily as a result of an increase in commodity prices.
Operating expenses totaled $175.2 million for the nine months ended September 30, 2013 compared to $157.5 million for the nine months ended September 30, 2012. The increase in operating expenses was primarily due to increased DD&A expense as a result of additional assets placed in-service, increased personnel costs of $6.3 million including incentive compensation expenses, increased allocated expenses from affiliates in 2013 and increased property taxes partially offset by decreases in compressor operating expenses in 2013. Additionally, operating expenses were unfavorably impacted by lower recoveries of $1.1 million from Lehman Brothers in 2013 compared to $2.5 million in 2012.
DISTRIBUTION
Heating degree days (30 year average: QTD – 114; YTD – 3,649)
98
115
(14.8
3,507
2,836
23.7
Residential sales and transportation volumes (MMcf)
1,363
1,266
7.7
15,907
12,726
25.0
Commercial and industrial volumes (MMcf)
4,648
4,939
(5.9
19,879
20,051
(0.9
Total throughput (MMcf)
6,011
6,205
(3.1
35,786
32,777
9.2
Residential
14,687
14,221
3.3
88,614
72,855
21.6
Commercial and industrial
6,179
6,499
(4.9
33,823
32,182
5.1
Off-system and energy services
4,295
4,706
(8.7
13,707
14,968
(8.4
25,161
25,426
(1.0
136,144
120,005
13.4
18.9
1.3
12.3
10,957
10,223
7.2
110,137
99,338
10.9
Net operating revenues
O&M
11,034
10,549
4.6
32,087
31,010
3.5
8,118
7,955
2.0
27,482
26,397
4.1
(2.9
25,248
24,741
77,785
76,174
2.1
Operating (loss) income
(112.7
33.1
31
Distribution’s operating income decreased $0.8 million for the three months ended September 30, 2013 as compared to the same period in 2012. The decrease was primarily due to higher operating expenses and slightly lower gathering revenues.
Operating expenses totaled $25.2 million for the three months ended September 30, 2013 compared to $24.7 million for the three months ended September 30, 2012. The increase in operating expenses was primarily due to higher bad debt expense of $0.6 million partially offset by lower DD&A expense. Bad debt expense increased as a result of increased gas sales due to significantly colder weather in the 2013 winter as compared to 2012. The Company continues to closely monitor its collection rates and adjusts its reserve for uncollectible accounts as necessary.
Distribution’s operating income totaled $58.4 million for the nine months ended September 30, 2013 compared to $43.8 million for the nine months ended September 30, 2012. The increase in 2013 operating income was primarily due to colder winter weather and a favorable change in estimated recoverable costs due to the completion of the Company’s regulatory gas cost audit.
Net operating revenues were $136.1 million for the nine months ended September 30, 2013 compared to $120.0 million for the nine months ended September 30, 2012. The increase in net operating revenues was the result of several factors. Net operating revenues from residential customers increased $10.8 million as a result of favorable winter weather that was 24% colder than 2012 and related customer usage patterns. Residential net operating revenues also increased $5.0 million as a result of the completion of the Company’s regulatory gas cost audit which resulted in a favorable change to estimated recoverable costs. Commercial and industrial net operating revenues increased $1.6 million due to favorable weather and related customer usage, partially offset by lower revenues associated with a contract that terminated and competitive contract renewals in 2012. Commercial and industrial volumes increased due to favorable weather in the first nine months of 2013 but were more than offset by decreased usage by one industrial customer. These high volume industrial sales have low margins and did not significantly impact total net operating revenues. Off-system and energy services net operating revenues decreased primarily as a result of lower gathered volumes and gathering rates in the first nine months of 2013 as compared to the same period in 2012 partially offset by favorable asset optimization opportunities.
The increases in both total operating revenues and purchased gas costs were primarily due to higher customer throughput as a result of colder weather during the nine months ended September 30, 2013 partially offset by a decrease in asset optimization off-system and energy services transactions. The increase in purchased gas costs was also partially offset by the favorable change in estimated recoverable costs due to the completion of the Company’s regulatory gas cost audit.
Operating expenses totaled $77.8 million for the nine months ended September 30, 2013 compared to $76.2 million for the nine months ended September 30, 2012. The increase in operating expenses was primarily due to higher bad debt expense of $3.2 million as a result of increased gas sales partially offset by the reversal of a $1.0 million operating reserve resulting from the completion of the Company’s regulatory gas cost audit and lower DD&A expense. The Company continues to closely monitor its collection rates and adjusts its reserve for uncollectible accounts as necessary.
OUTLOOK
The Company is committed to profitably developing its natural gas, NGL and oil reserves through environmentally responsible, cost-effective and technologically advanced horizontal drilling. The market price for natural gas can be volatile and these fluctuations can impact the Company’s revenues, earnings and liquidity. The Company is unable to predict future movements in the market price for natural gas and thus cannot predict the ultimate impact of prices on its operations; however, the Company monitors the market for natural gas and adjusts its strategy and operations appropriately. Due to the increased supply of natural gas in the Northeast region, pricing relative to Henry Hub was negative during the third quarter. The Company expects this trend in basis to continue to be negative prospectively.
32
Total capital investment, excluding acquisitions, is expected to be approximately $1.6 billion in 2013. Capital spending for well development (primarily drilling and completion) in 2013 is expected to be approximately $1.1 billion to support the drilling of approximately 176 gross wells, including 146 Marcellus wells, 22 Upper Devonian wells and eight wells in the Utica Shale of Ohio. The Company plans to spud seven fewer Marcellus wells and 11 more Upper Devonian wells than originally planned to take advantage of operational efficiencies of drilling more total wells per pad. All of the Upper Devonian wells are being spud on Marcellus multi-well pads. Estimated sales volumes for 2013 are expected to be 366 Bcfe, approximately 42% higher than in 2012, while NGL volumes are expected to be 4,875 Mbbls. In addition, the Company plans to invest approximately $400 million on midstream infrastructure in 2013, which includes projected capital expenditures for the Partnership of approximately $80 million, primarily to support production growth and expects gathering and transmission volumes to increase as a result of this expansion. EQT Midstream expects to add approximately 400 MMcf per day of incremental gathering capacity and approximately 450 MMcf per day of transmission capacity in 2013. The balance of the 2013 capital spending plan is expected to be funded by cash on hand and cash flow generated from operations.
On December 19, 2012, the Company and its direct wholly-owned subsidiary, Distribution Holdco, LLC (Holdco), executed a definitive agreement with PNG Companies LLC (PNG Companies), the parent company of Peoples Natural Gas Company LLC (Peoples), pursuant to which the Company and Holdco will transfer 100% of their ownership interests of Equitable Gas and Homeworks to PNG Companies in exchange for cash and other assets of, and new commercial arrangements with, PNG Companies and its affiliates. Peoples is a portfolio company of SteelRiver Infrastructure Fund North America LP.
The Company has submitted filings with the Pennsylvania Public Utility Commission, the West Virginia Public Service Commission and the Federal Energy Regulatory Commission – each must approve the transaction in whole or in part as part of the regulatory process. The Company expects to complete the regulatory review process by the end of 2013. The Company also submitted a filing with the Kentucky Public Service Commission (KY PSC), which issued a ruling that it is not asserting jurisdiction with regard to the assets being conveyed. Therefore, approval by the KY PSC is not required. The transaction was also subject to review by the Federal Trade Commission (FTC) under the Hart-Scott Rodino Antitrust Improvements Act (HSR Act). The waiting period under the HSR Act expired on April 22, 2013, without a request for additional information. This expiration indicates that the FTC has not objected to the transaction and that, from an HSR Act perspective, the parties may complete the transaction.
The Company continues to focus on achieving its objective of maximizing shareholder value via a strategy of economically accelerating the monetization of its asset base and prudent pursuit of investment opportunities, all while maintaining a strong balance sheet with solid cash flow. While the tactics continue to evolve based on market conditions, the Company is considering arrangements, including asset sales and joint ventures, to monetize the value of mature assets for re-deployment into higher-value Marcellus Shale development.
CAPITAL RESOURCES AND LIQUIDITY
Overview
The Company’s primary source of cash for the nine months ended September 30, 2013 was from operating activities and the underwritten public offering of common units of the Partnership, while the primary use of cash was for capital expenditures.
Operating Activities
Cash flows provided by operating activities totaled $1,007.1 million for the nine months ended September 30, 2013 compared to $670.0 million for the nine months ended September 30, 2012. The $337.1 million increase was primarily a result of a 47% increase in natural gas volumes sold, increases in transmission pipeline throughput and gathered volumes, colder weather and lower interest payments due to the repayment of long-term debt that matured in 2012, partially offset by higher income tax payments.
Investing Activities
Net cash flows used in investing activities totaled $1,259.6 million for the nine months ended September 30, 2013 compared to $1,018.7 million for the nine months ended September 30, 2012. Capital expenditures totaled $1,259.6 million for the first nine months of 2013 compared to $1,023.5 million for the first nine months of 2012.
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Capital expenditures for EQT Production totaled $977.4 million for the nine months ended September 30, 2013 compared to $703.8 million for the nine months ended September 30, 2012. The $273.6 million increase was partially attributable to the acquisition of acreage and wells from Chesapeake for approximately $114.6 million in the first half of 2013, while the remaining increase was due to the increase in the number of completed frac stages primarily in the Marcellus play, with approximately 2,811 frac stages completed in the first nine months of 2013 compared to approximately 1,658 frac stages completed in the first nine months of 2012. The Company spud 131 gross horizontal wells during the first nine months of 2013; 105 targeting the Marcellus play, 22 targeting the Upper Devonian play and 4 targeting the Utica play. The Company spud 106 gross horizontal wells during the first nine months of 2012; 98 targeting the Marcellus play, 1 targeting the Upper Devonian play and 7 targeting the Huron play.
Capital expenditures for EQT Midstream totaled $254.2 million for the first nine months of 2013 compared to $296.7 million for the first nine months of 2012. The $42.5 million decrease was primarily due to the completion of the Sunrise Pipeline, which was placed into service during the third quarter of 2012, and a decrease in gathering compression projects in the Marcellus region. This decrease was partially offset by increased expenditures for gathering pipeline projects in the Marcellus region.
Capital expenditures for Distribution totaled $24.9 million for the nine months ended September 30, 2013 compared to $21.1 million for the nine months ended September 30, 2012. The $3.8 million increase was primarily due to increased pipeline replacements.
Financing Activities
Cash flows provided by financing activities totaled $494.4 million for the nine months ended September 30, 2013 compared to $156.4 million for the nine months ended September 30, 2012, a difference of $338.0 million between periods. On July 22, 2013, the Company received net proceeds of $529.4 million from the Partnership’s underwritten public offering of common units. In July 2012, the Company received net proceeds of $276.8 million in connection with the Partnership’s IPO. The Company paid dividends of $13.6 million in the first nine months of 2013 compared to $98.8 million in the first nine months of 2012. The increase in cash flows provided by financial activities was partially offset by $21.2 million in distributions paid to noncontrolling interests during 2013.
Security Ratings and Financing Triggers
The table below reflects the credit ratings for debt instruments of the Company at September 30, 2013. Changes in credit ratings may affect the Company’s cost of short-term and long-term debt (including interest rates and fees under its lines of credit), collateral requirements under derivative instruments and access to the credit markets.
Rating Service
Senior
Notes
Outlook
Moody’s Investors Service
Baa3
Stable
Standard & Poor’s Ratings Services
BBB
Fitch Ratings
BBB-
The Company’s credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. The Company cannot ensure that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a credit rating agency if, in its judgment, circumstances so warrant. If the credit rating agencies downgrade the Company’s ratings, particularly below investment grade, the Company’s access to the capital markets may be limited, borrowing costs and margin deposits on derivative contracts would increase, counterparties may request additional assurances and the potential pool of investors and funding sources may decrease. The required margin on derivative instruments is also subject to significant change as a result of factors other than credit rating, such as gas prices and credit thresholds set forth in agreements between the hedging counterparties and the Company.
The Company’s debt agreements and other financial obligations contain various provisions that, if not complied with, could result in termination of the agreements, require early payment of amounts outstanding or similar actions.
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The most significant covenants and events of default under the debt agreements relate to maintenance of a debt-to-total capitalization ratio, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s credit facility contains financial covenants that require a total debt-to-total capitalization ratio of no greater than 65%. The calculation of this ratio excludes the effects of accumulated other comprehensive income. As of September 30, 2013, the Company was in compliance with all debt provisions and covenants.
The Partnership’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the credit facility relate to maintenance of permitted leverage coverage and interest coverage ratios, limitations on transactions with affiliates, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. Under the credit facility, the Partnership is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or, after the Partnership obtains an investment grade rating, not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions) and, until the Partnership obtains an investment grade rating, a consolidated interest coverage ratio of not less than 3.00 to 1.00. As of September 30, 2013, the Partnership was in compliance with all credit facility provisions and covenants.
Commodity Risk Management
The substantial majority of the Company’s commodity risk management program is related to hedging sales of the Company’s produced natural gas. The Company’s overall objective in this hedging program is to protect cash flow from undue exposure to the risk of changing commodity prices. The Company’s risk management program may include 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. The derivative commodity instruments currently utilized by the Company are primarily fixed price swaps, collars and futures. The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery.
As of October 23, 2013, the approximate volumes and prices of the Company’s total hedge position for October 2013 through 2015 production were:
2013**
2014
2015
Fixed Price
Total Volume (Bcf)
51
163
70
Average Price per Mcf (NYMEX)*
4.56
4.43
4.57
Collars
Average Floor Price per Mcf (NYMEX)*
4.95
5.05
5.03
Average Cap Price per Mcf (NYMEX)*
9.09
8.85
8.97
* The average price is based on a conversion rate of 1.05 MMBtu/Mcf
** October through December
Commitments and Contingencies
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the Company’s financial position, results of operations or liquidity.
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Dividend
On October 16, 2013, the Board of Directors of the Company declared a regular quarterly cash dividend of three cents per share, payable December 1, 2013, to the Company’s shareholders of record at the close of business on November 15, 2013.
On October 22, 2013, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s common and subordinated unitholders of $0.43 per unit for the third quarter of 2013, together with the corresponding distribution to the general partner of $0.4 million related to its 2% general partner interest and $0.2 million related to its incentive distribution rights. The cash distribution is payable on November 14, 2013, to unitholders of record at the close of business on November 4, 2013, and to the general partner.
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, 2012 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 contained in this Form 10-Q for the three and nine month periods ended September 30, 2013. 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. Different amounts could be reported using different assumptions and estimates.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Derivative Instruments
The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily at EQT Production and the storage, marketing and other activities at EQT Midstream. The Company’s use of derivatives to reduce the effect of this volatility is described in Note D 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 derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. The Company also enters into derivative instruments to hedge other forecasted natural gas purchases and sales, to hedge natural gas inventory and to hedge exposure to fluctuations in interest rates. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Corporate Risk Committee and reviewed by the Audit Committee of the Board of Directors.
Commodity Price Risk
For the derivative commodity instruments used to hedge the Company’s forecasted production, the Company sets policy limits relative to the expected production and sales levels which are exposed to price risk. For the derivative commodity instruments used to hedge forecasted natural gas purchases and sales which are exposed to price risk and to hedge natural gas inventory which is exposed to changes in fair value, the Company sets limits related to acceptable exposure levels.
The financial instruments currently utilized by the Company are primarily fixed price futures contracts, swap agreements and collar agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company also considers other contractual agreements in implementing its commodity hedging strategy.
The Company monitors price and production levels on a continuous basis and makes adjustments to quantities hedged as warranted. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices.
With respect to the derivative commodity instruments held by the Company for purposes other than trading as of September 30, 2013 and December 31, 2012, the Company hedged portions of expected equity production, portions of forecasted purchases and sales and portions of natural gas inventory by utilizing futures contracts, swap agreements and collar agreements covering approximately 363 Bcf and 356 Bcf of natural gas, respectively. See the “Commodity Risk Management” section in the “Capital Resources and Liquidity” section in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Form 10-Q for further discussion.
A hypothetical decrease of 10% in the market price of natural gas from the September 30, 2013 and December 31, 2012 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $134.2 million and $131.0 million, respectively. A hypothetical increase of 10% in the market price of natural gas from the September 30, 2013 and December 31, 2012 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $133.7 million and $130.2 million, respectively.
The Company determined the change in the fair value of the derivative commodity instruments using a method similar to its normal determination of fair value as described in Note E to the Condensed Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at September 30, 2013 and December 31, 2012. The price change was then applied to the non-trading natural gas derivative commodity instruments recorded on the Company’s Condensed Consolidated Balance Sheets, resulting in the change in fair value.
The above analysis of the derivative commodity instruments held by the Company for purposes other than trading does not include the offsetting impact that the same hypothetical price movement may have on the Company’s physical sales of natural gas. The portfolio of derivative commodity instruments held for risk management purposes approximates the notional quantity of a portion of the expected or committed transaction volume of physical commodities with commodity price risk for the same time periods. Furthermore, the derivative commodity
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instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, an adverse impact to the fair value of the portfolio of derivative commodity instruments held for risk management purposes associated with the hypothetical changes in commodity prices referenced above should be offset by a favorable impact on the underlying hedged physical transactions, assuming the derivative commodity instruments are not closed out in advance of their expected term, the derivative commodity instruments continue to function effectively as hedges of the underlying risk and the anticipated transactions occur as expected.
If the underlying physical transactions or positions are liquidated prior to the maturity of the derivative commodity instruments, a loss on the financial instruments may occur or the derivative commodity instruments might be worthless as determined by the prevailing market value on their termination or maturity date, whichever comes first.
Interest Rate Risk
Changes in interest rates affect the amount of interest the Company and the Partnership earn on cash, cash equivalents and short-term investments and the interest rates the Company and the Partnership pay on borrowings under their respective revolving credit facilities. All of the Company’s long-term borrowings are fixed rate and thus do not expose the Company to fluctuations in its results of operations or liquidity from changes in market interest rates. Changes in interest rates do affect the fair value of the Company’s fixed rate debt. See Notes G and H to the Condensed Consolidated Financial Statements for further discussion of the Company’s borrowings and Note E to the Condensed Consolidated Financial Statements for a discussion of fair value measurements, including the fair value of long-term debt.
Other Market Risks
The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company believes that NYMEX-traded futures contracts have limited credit risk because Commodity Futures Trading Commission regulations are in place to protect exchange participants, including the Company, from potential financial instability of the exchange members. The Company’s OTC swap and collar derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as that industry as a whole.
Approximately 92%, or $202.5 million, of the Company’s OTC derivative contracts outstanding at September 30, 2013 had a positive fair value. Approximately 80%, or $303.0 million, of the Company’s OTC derivative contracts at December 31, 2012 had a positive fair value.
As of September 30, 2013, the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company will continue to monitor market conditions that may impact the fair value of derivative contracts reported in the Condensed Consolidated Balance Sheets.
The Company is also exposed to the risk of nonperformance by credit customers on physical sales of natural gas. A significant amount of revenues and related accounts receivable from EQT Production are generated from the sale of produced natural gas, NGLs and crude oil to certain marketers, utility and industrial customers located mainly in the Appalachian area and a gas processor in Kentucky and West Virginia. Additionally, a significant amount of revenues and related accounts receivable from EQT Midstream are generated from the gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia.
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The Company has a $1.5 billion revolving credit facility that expires on December 8, 2016. The credit facility is underwritten by a syndicate of financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company. As of September 30, 2013, the Company had no loans or letters of credit outstanding under the facility. No one lender of the large group of financial institutions in the syndicate holds more than 10% of the facility. The Company’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Company’s exposure to problems or consolidation in the banking industry.
The Partnership has a $350 million revolving credit facility that expires on July 2, 2017. The credit facility is underwritten by a syndicate of financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Partnership. As of September 30, 2013, the Partnership had no loans or letters of credit outstanding under the facility. No one lender of the large group of financial institutions in the syndicate holds more than 10% of the facility. The Partnership’s large syndicate group and relatively low percentage of participation by each lender is expected to limit the Partnership’s exposure to problems or consolidation in the banking industry. The Company is not a guarantor of the Partnership’s revolving credit obligations under the credit facility.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management, including the Company’s Principal Executive Officer and Principal Financial Officer, an evaluation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), was conducted as of the end of the period covered by this report. Based on that evaluation, the Principal Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred during the third quarter of 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company and its subsidiaries. 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 accrues legal and other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the Company’s financial position, results of operations or liquidity.
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, 2012. 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 September 30, 2013:
Period
Total number of shares (or units) purchased (a)
Average price paid per share (or unit)
Total number of shares (or units) purchased as part of publicly announced plans or programs
Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs
July 2013 (July 1 – July 31)
1,117
80.48
August 2013 (August 1 – August 31)
2,130
83.63
September 2013 (September 1 – September 30)
3,247
82.55
(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.
Item 6. Exhibits
31.1
Rule 13(a)-14(a) Certification of Principal Executive Officer
31.2
Rule 13(a)-14(a) Certification of Principal Financial Officer
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
Interactive Data File
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
By:
/s/ Philip P. Conti
Philip P. Conti
Senior Vice President and Chief Financial Officer
Date: October 24, 2013
INDEX TO EXHIBITS
Exhibit No.
Method of Filing
Filed herewith as Exhibit 31.1
Filed herewith as Exhibit 31.2
Filed herewith as Exhibit 32
Filed herewith as Exhibit 101