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 MARCH 31, 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 ý
Accelerated Filer
o
Non-Accelerated Filer o
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 March 31, 2013, 150,435,175 shares of common stock, no par value, of the registrant were outstanding.
EQT CORPORATION AND SUBSIDIARIES
Index
Page No.
Part I. Financial Information:
Item 1.
Financial Statements (Unaudited):
Statements of Consolidated Income for the Three Months Ended March 31, 2013 and 2012
3
Statements of Consolidated Comprehensive Income for the Three Months Ended March 31, 2013 and 2012
4
Statements of Condensed Consolidated Cash Flows for the Three Months Ended March 31, 2013 and 2012
5
Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012
6 – 7
Statements of Condensed Consolidated Equity for the Three Months Ended March 31, 2013 and 2012
8
Notes to Condensed Consolidated Financial Statements
9 – 19
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
20 – 32
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
33 – 35
Item 4.
Controls and Procedures
35
Part II. Other Information:
Legal Proceedings
36
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Item 6.
Exhibits
37
Signature
38
Index to Exhibits
39
2
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Consolidated Income (Unaudited)
Three Months Ended
March 31,
2013
2012
(Thousands, except per share amounts)
Operating revenues
$
558,660
449,960
Operating expenses:
Purchased gas costs
100,569
84,066
Operation and maintenance
33,223
34,390
Production
24,889
27,023
Exploration
3,730
1,828
Selling, general and administrative
48,498
42,942
Depreciation, depletion and amortization
149,116
107,525
Total operating expenses
360,025
297,774
Operating income
198,635
152,186
Other income
2,330
5,791
Interest expense
37,752
41,252
Income before income taxes
163,213
116,725
Income taxes
53,932
44,690
Net income
109,281
72,035
Less: Net income attributable to noncontrolling interests
9,026
–
Net income attributable to EQT Corporation
100,255
Earnings per share of common stock attributable to EQT Corporation:
Basic:
Weighted average common shares outstanding
150,327
149,494
0.67
0.48
Diluted:
150,949
150,216
0.66
Dividends declared per common share
0.03
0.22
The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.
Statements of Consolidated Comprehensive Income (Unaudited)
(Thousands)
Other comprehensive (loss) income, net of tax:
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of ($51,583) and $38,492
(78,434
)
59,502
Interest rate, net of tax expense of $25 and $1,801
2,438
Pension and other post-retirement benefits liability adjustment, net of tax expense of $307 and $122
433
947
Other comprehensive (loss) income
(77,965
62,887
Comprehensive income
31,316
134,922
Less: Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to EQT Corporation
22,290
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
34,347
39,363
Depreciation, depletion, and amortization
Provision for losses on accounts receivable
1,962
196
(2,330
(5,791
Stock-based compensation expense
10,334
8,256
Unrealized (gains) losses on derivatives and inventory
(1,326
5,484
Lease impairment
2,980
692
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues
(8,825
36,251
Inventory
37,789
55,628
Accounts payable
(18,025
(55,969
Other items, net
(10,063
(41,546
Net cash provided by operating activities
305,240
222,124
Cash flows from investing activities:
Capital expenditures
(304,257
(269,587
Proceeds from sale of assets
2,391
Net cash used in investing activities
(267,196
Cash flows from financing activities:
Dividends paid
(4,516
(32,938
Distributions to noncontrolling interests
(5,031
Repayments and retirements of long-term debt
(20,161
(9,532
Proceeds and tax benefits from exercises under employee compensation plans
6,995
1,499
Net cash used in financing activities
(22,713
(40,971
Net change in cash and cash equivalents
(21,730
(86,043
Cash and cash equivalents at beginning of period
182,055
831,251
Cash and cash equivalents at end of period
160,325
745,208
Cash paid during the period for:
Interest, net of amount capitalized
10,446
13,044
Income taxes, net
3,661
2,214
Condensed Consolidated Balance Sheets (Unaudited)
December 31,
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable (less accumulated provision for doubtful accounts of $14,696 at March 31, 2013 and $12,586 at December 31, 2012)
219,705
205,479
Unbilled revenues
20,335
27,699
41,405
76,787
Derivative instruments, at fair value
183,727
304,237
Prepaid expenses and other
31,587
56,588
Total current assets
657,084
852,845
Equity in nonconsolidated investments
127,851
130,368
Property, plant and equipment
10,436,556
10,139,903
Less: accumulated depreciation and depletion
2,567,762
2,424,605
Net property, plant and equipment
7,868,794
7,715,298
Regulatory assets
110,557
111,915
Other assets
38,198
39,436
Total assets
8,802,484
8,849,862
6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt
6,212
23,204
271,007
289,032
92,107
75,562
Other current liabilities
130,032
182,667
Total current liabilities
499,358
570,465
Long-term debt
2,499,437
2,502,969
Deferred income taxes and investment tax credits
1,651,737
1,666,029
Other credits
224,916
221,597
Total liabilities
4,875,448
4,961,060
Equity:
Stockholders’ equity:
Common stock, no par value, authorized 320,000 shares, shares issued: 175,684 at March 31, 2013 and December 31, 2012
1,780,966
1,770,545
Treasury stock, shares at cost: 25,249 at March 31, 2013 and 25,575 at December 31, 2012
(455,872
(461,774
Retained earnings
2,291,241
2,195,502
Accumulated other comprehensive income
21,582
99,547
Total common stockholders’ equity
3,637,917
3,603,820
Noncontrolling interests in consolidated subsidiaries
289,119
284,982
Total equity
3,927,036
3,888,802
Total liabilities and equity
7
Statements of Condensed Consolidated Equity (Unaudited)
Common Stock
Accumulated Other
Noncontrolling Interests in
Shares Outstanding
No Par Value
Retained Earnings
Comprehensive Income
Consolidated Subsidiaries
Total Equity
Balance, January 1, 2012
149,477
1,261,779
2,143,910
188,141
3,593,830
Other comprehensive income
Dividends on common stock ($0.22 per share)
(32,938)
Stock-based compensation plans, net
98
10,320
Balance, March 31, 2012
149,575
1,272,099
2,183,007
251,028
3,706,134
Balance, January 1, 2013
150,109
1,308,771
Other comprehensive loss
(77,965)
Dividends on common stock ($0.03 per share)
(4,516)
326
16,323
142
16,465
Distributions to noncontrolling interests ($0.35 per common unit)
(5,031)
Balance, March 31, 2013
150,435
1,325,094
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 March 31, 2013 and December 31, 2012 and the results of its operations and cash flows for the three month periods ended March 31, 2013 and 2012. Certain previously reported amounts have been reclassified to conform to the current year presentation. 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 statements for the three month period ended March 31, 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” on page 20 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 (FERC) regulated transmission, storage and gathering subsidiary). An indirect wholly-owned subsidiary of EQT 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 its ownership percentage. EQT records the noncontrolling interest of the public limited partners in EQT’s financial statements.
The Partnership paid distributions of $5.0 million to noncontrolling interests at $0.35 per common unit during the three months ended March 31, 2013.
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
9
to the operating segments based upon an allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ 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 EQT 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 review and/or 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 held for sale 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.
Revenues from external customers:
EQT Production
250,511
195,396
EQT Midstream
146,688
122,048
Distribution
153,818
135,421
Third-party transportation costs (a)
35,741
27,207
Less intersegment revenues, net (b)
(28,098
(30,112
Total
Operating income:
74,097
59,038
74,214
56,136
52,276
36,770
Unallocated expenses
(1,952
242
Total operating income
Reconciliation of operating income to net income:
As of March 31,
As of December 31,
Segment assets:
5,668,742
5,675,534
2,063,049
2,046,558
842,331
860,029
Total operating segments
8,574,122
8,582,121
Headquarters assets, including cash and short-term investments
228,362
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 consolidated level.
10
(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.
Depreciation, depletion and amortization:
124,909
86,567
18,219
14,708
6,048
6,243
Other
(60
Expenditures for segment assets:
EQT Production (c)
246,946
183,685
51,358
79,638
5,605
5,463
348
801
304,257
269,587
(c) Expenditures for segment assets in the EQT Production segment include $12.7 million and $18.1 million for undeveloped property acquisitions during the three months ended March 31, 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 through 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 derivative commodity instruments that are purchased from or placed with major financial institutions whose creditworthiness is regularly monitored. Futures contracts obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between 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 also engages in a limited number of basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on 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.
Some 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 of operating revenues in the Statements of Consolidated Income. The Company has elected to exclude the
11
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.
Exchange-traded instruments are generally settled with offsetting positions. Over the counter (OTC) arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Condensed Consolidated Cash Flows.
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 (loss) gain recognized in OCI (effective portion), net of tax
(52,601
107,488
Amount of gain reclassified from accumulated OCI into operating revenues (effective portion), net of tax
25,833
47,986
Amount of loss recognized in operating revenues (ineffective portion) (a)
(481
(31
Interest rate derivatives designated as cash flow hedges
Amount of gain recognized in OCI (effective portion), net of tax
2,373
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)
(36
(65
Commodity derivatives designated as fair value hedges (b)
Amount of (loss) gain recognized in operating revenues for fair value commodity contracts
(3,539
7,072
Fair value gain (loss) recognized in operating revenues for inventory designated as hedged item
4,537
(9,931
Derivatives not designated as hedging instruments
Amount of (loss) gain recognized in operating revenues
(262
2,463
(a) No amounts have been excluded from effectiveness testing of cash flow hedges.
(b) For the three months ended March 31, 2013, the net impact on operating revenues associated with commodity derivatives as fair value hedges was a $1.3 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 $0.3 million loss due to changes in basis. For the three months ended March 31, 2012, the net impact on operating revenues associated with commodity derivatives as fair value hedges was a $3.3 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 $0.4 million gain due to changes in basis.
12
Asset derivatives
Commodity derivatives designated as hedging instruments
153,741
259,459
Commodity derivatives not designated as hedging instruments
29,986
44,778
Total asset derivatives
Liability derivatives
59,209
27,946
32,898
47,616
Total liability derivatives
The net fair value of commodity derivative instruments changed during the first quarter of 2013 primarily as a result of increased commodity prices and settlements. The absolute quantities of the Company’s derivative commodity instruments that have been designated and qualify as cash flow hedges totaled 428 Bcf and 365 Bcf as of March 31, 2013 and December 31, 2012, respectively, and are primarily related to natural gas swaps and collars. The open positions at March 31, 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 7 Bcf and 8 Bcf as of March 31, 2013 and December 31, 2012, respectively. The open positions at March 31, 2013 had maturities extending through April 2014 and open positions at December 31, 2012 had maturities extending through January 2014.
The Company deferred net gains of $59.8 million and $138.2 million in accumulated OCI, net of tax, as of March 31, 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 $30.7 million of net unrealized gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of March 31, 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.
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 March 31, 2013 or December 31, 2012.
13
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 $1.1 million as of March 31, 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 March 31, 2013 and December 31, 2012.
As of March 31, 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:
(66,428)
117,299
Liability derivatives:
(1,125)
24,554
As of December 31, 2012
Derivative instruments subject to master netting
agreements
(73,753)
230,484
(736)
1,073
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 March 31, 2013, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $29.4 million, for which the Company had no collateral posted on March 31, 2013. If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on March 31, 2013, the Company would have been required to post additional collateral of $1.6 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 March 31, 2013. In order to be considered investment grade, the Company must be rated BBB-
14
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 March 31, 2013, derived market volatilities used to value Level 3 assets and liabilities ranged from 22% to 31%. 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 March 31, 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.
15
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
March 31, 2013
Quoted prices in active markets for identical assets (Level 1)
Significant other observable inputs (Level 2)
Significant unobservable inputs (Level 3)
Assets
1,588
105,620
76,519
Liabilities
2,382
83,071
6,654
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 March 31,
Balance at January 1
90,714
143,260
Total gains or losses:
Included in earnings
423
Included in OCI
(11,733
31,596
Purchases
72
Settlements
(9,611
(18,790
Transfers in and/or out of Level 3
Balance at March 31
69,865
156,066
Gains of $0.5 million are included in earnings in the table above for the three months ended March 31, 2013 attributable to the change in unrealized gains or losses relating to assets still held as of March 31, 2013. There are no material gains or losses included in earnings in the table above for the three months ended March 31, 2012 attributable to the change in unrealized gains or losses relating to assets and liabilities still held as of March 31, 2012.
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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. 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 March 31, 2013 and December 31, 2012 was approximately $2.9 billion.
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. 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 three months ended March 31, 2013 was 33.0%, compared to 38.3% for the three months ended March 31, 2012. The decrease in the effective income tax rate from the first quarter of 2012 is primarily attributable to unfavorable state net operating loss adjustments recorded in 2012 and the impact of the Partnership’s IPO. The effective income tax rate is impacted by the recent IPO which modified the Midstream ownership structure and now reflects Partnership earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes.
There were no material changes to the Company’s methodology for unrecognized tax benefits during the three months ended March 31, 2013. The Company’s consolidated federal income tax liability has been settled with the IRS through 2009. The Company is the subject of various state income tax examinations. The Company believes that it is appropriately reserved for any uncertain tax positions.
G. Revolving Credit Facilities
As of March 31, 2013 and December 31, 2012, neither the Company nor the Partnership had loans or letters of credit outstanding under their respective revolving credit facilities. Commitment fees averaging approximately 5 basis points in the three months ended March 31, 2013 and 7.5 basis points in the three months ended March 31, 2012 were paid to maintain credit availability under the Company’s revolving credit facility. The Partnership incurred commitment fees averaging approximately 6.25 basis points in the three months ended March 31, 2013 to maintain credit availability under its revolving credit facility.
Neither the Company nor the Partnership had any short-term loans outstanding at any time during the three months ended March 31, 2013 and 2012.
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H. Long-Term Debt
7.76% notes, due 2013 thru 2016
22,449
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
2,505,649
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 $3.0 million in 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 EQT 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. Homeworks and Equitable Gas are direct wholly-owned subsidiaries of Holdco. Peoples is a portfolio company of SteelRiver Infrastructure Partners. The transaction is subject to review and/or approval by a number of federal and state regulatory agencies. As a result, the Company has not classified Equitable Gas and Homeworks as held for sale in its financial statements as of March 31, 2013 and will not do so until the Company makes satisfactory progress in the regulatory process.
The Company incurred $2.1 million in expenses during the three months ended March 31, 2013 related to the pending sale of Equitable Gas and Homeworks, which expenses are reported in selling, general & 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 622,006 and 721,641 for the three months ended March 31, 2013 and 2012, respectively. There were no options to purchase common stock which were not included in potentially dilutive securities because they were anti-dilutive for the three months ended March 31, 2013. Options to purchase common stock which were not included in potentially dilutive securities because they were anti-dilutive totaled 214,392 for the three months ended March 31, 2012. The impact of the Partnership’s dilutive units did not have a material impact on the Company’s earnings per share calculation for the three month period ended March 31, 2013.
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K. Changes in Accumulated Other Comprehensive Income by Component
The following table explains the changes in accumulated OCI by component for the three months ended March 31, 2013:
Three Months Ended March 31, 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 January 1, 2013
138,188
(1,276)
(37,365)
Losses recognized in accumulated OCI, net of tax
(52,601)
(a)
Amounts reclassified from accumulated OCI into realized (income) expense, net of tax
(25,833)
(b)
(25,364)
Change in accumulated other comprehensive (loss) income, net of tax
(78,434)
Accumulated OCI (loss), net of tax, as of March 31, 2013
59,754
(1,240)
(36,932)
(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.
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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 drilled and the availability of capital to complete these plans and programs); production and sales volumes and growth rates; 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; the proposed transfer of Equitable Gas Company, LLC (Equitable Gas) to PNG Companies LLC (PNG Companies); the timing of receipt of required approvals for the proposed Equitable Gas transaction; natural gas prices; reserves; capital expenditures, including funding sources and availability; financing requirements and availability; hedging strategy; the effects of government regulation and pending and future litigation; and tax position. 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 March 31, 2013 vs. Three Months Ended March 31, 2012
Net income attributable to EQT Corporation for the three months ended March 31, 2013 was $100.3 million, $0.66 per diluted share, compared with $72.0 million, $0.48 per diluted share, for the three months ended March 31, 2012. The $28.3 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 gathered volumes and transmission pipeline
20
throughput and colder weather. The increases were partially offset by higher depreciation, depletion and amortization expense, lower average effective sales prices for natural gas and natural gas liquids and higher income tax expense.
The average effective sales price to EQT Corporation for production sales volumes was $4.27 per Mcfe during the first quarter of 2013 compared to $4.84 per Mcfe in the same period 2012. The Company’s average NYMEX natural gas sales price increased to $3.34 per Mcf for the three months ended March 31, 2013 from $2.74 per Mcf for the three months ended March 31, 2012. Hedging activities resulted in an increase in the price of production sales volumes of $0.58 per Mcf in the first quarter of 2013 compared to $1.52 per Mcf in the first quarter of 2012 as a result of lower average hedge prices and the increase in NYMEX natural gas sales prices in the current year.
Interest expense was $3.5 million lower in the three months ended March 31, 2013 compared to the three months ended March 31, 2012 primarily as a result of the Company’s repayment of the $200 million of 5.15% senior notes that matured in the fourth quarter of 2012 and $20.2 million of debentures that matured in the first quarter of 2013.
Income tax expense increased $9.2 million in 2013 from 2012 primarily as a result of higher pre-tax income. The Company’s effective income tax rate decreased to 33.0% from 38.3%. This decrease in the effective income tax rate was primarily attributable to state net operating loss adjustments recorded in 2012 and the impact of the Partnership’s initial public offering (IPO). The effective income tax rate is impacted by the recent IPO which modified the Midstream ownership structure and now reflects Partnership earnings for which the noncontrolling public limited partners are directly responsible for the related income taxes.
Net income attributable to noncontrolling interests of the Partnership, which held its IPO in the third quarter of 2012, was $9.0 million for the three months ended March 31, 2013.
See “Investing Activities” under the caption “Capital Resources and Liquidity” for a discussion of capital expenditures.
Consolidated Operational Data
Revenues earned by the Company at the wellhead from the sale of natural gas are split between EQT Production and EQT Midstream. The split is reflected in the calculation of EQT Production’s average effective sales price. The following operational information presents detailed gross liquid and natural gas operational information as well as midstream deductions to assist the understanding of the Company’s consolidated operations.
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Three Months Ended March 31,
in thousands (unless noted)
%
LIQUIDS
Natural Gas Liquids (NGLs):
Sales Volume (MMcfe) (a)
4,370
2,969
47.2
Sales Volume (Mbbls)
1,194
787
51.7
Gross Price ($/Mbbls)
43.07
55.83
(22.9
Gross NGL Revenue
51,423
43,939
17.0
BTU Premium (Ethane sold as natural gas):
Sales Volume (MMbtu)
6,417
4,645
38.1
Price ($/MMbtu)
3.34
2.74
21.9
BTU Premium Revenue
21,406
12,708
68.4
Oil:
368
327
12.5
61
54
13.0
Net Price ($/Mbbls)
81.74
85.32
(4.2
Net Oil Revenue
4,986
4,607
8.2
Total Liquids Revenue
77,815
61,254
27.0
GAS
Sales Volume (MMcf)
74,654
50,773
47.0
NYMEX Price ($/Mcf)
Gas Revenues
249,021
138,916
79.3
Basis
(193
(118
63.6
Gross Gas Revenue (unhedged)
248,828
138,798
Total Gross Gas & Liquids Revenue (unhedged)
326,643
200,052
63.3
Hedge impact
43,498
76,747
(43.3
Total Gross Gas & Liquids Revenue
370,141
276,799
33.7
Total Sales Volume (MMcfe)
79,392
54,070
46.8
Average hedge adjusted price ($/Mcfe)
4.66
5.12
(9.0
Midstream Revenue Deductions ($ / Mcfe)
Gathering to EQT Midstream
(0.90
(1.08
(16.7
Transmission to EQT Midstream
(0.23
(0.17
35.3
Third-party gathering and transmission (b)
(0.27
58.8
Third-party processing
(0.12
(0.11
9.1
Total midstream revenue deductions
(1.52
(1.53
(0.7
Average effective sales price to EQT Production
3.14
3.59
(12.5
EQT Revenue ($ / Mcfe)
Revenues to EQT Midstream
1.13
1.25
(9.6
Revenues to EQT Production
Average effective sales price to EQT Corporation
4.27
4.84
(11.8
(a) NGLs were converted to Mcfe at the rates of 3.66 Mcfe per barrel and 3.77 Mcfe per barrel based on the liquids content for the three months ended March 31, 2013 and 2012, respectively. Crude oil was converted to Mcfe at the rate of six Mcfe per barrel for all periods.
(b) 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 for the three months ended March 31, 2013. In 2012, the unused capacity on the El Paso 300 line not under long-term resale agreements was sold at prices above the capacity charge, decreasing third-party gathering and transmission rates by $0.12 per Mcfe for the three months ended March 31, 2012.
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Business Segment Results
The Company has reported the components of each segment’s operating income and various operational measures in the sections below, and where appropriate, has provided information describing how a measure was derived. EQT’s management believes that presentation of this information provides useful information to management and investors regarding the financial condition, operations and trends of each of EQT’s business segments without being obscured by the financial condition, operations and trends for the other segments or by the effects of corporate allocations of interest, income taxes and other income. In addition, management uses these measures for budget planning purposes. The Company’s management reviews and reports the EQT Production segment results with third-party transportation costs reflected as a deduction from operating revenues as management believes this presentation provides a more useful view of net effective price and is consistent with industry practices. Third-party transportation costs are reported as a component of purchased gas costs in the consolidated results. The Company has reconciled each segment’s operating income to the Company’s consolidated operating income and net income in Note C to the Condensed Consolidated Financial Statements of this Quarterly Report on Form 10-Q.
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EQT PRODUCTION
RESULTS OF OPERATIONS
OPERATIONAL DATA
Sales volume detail (MMcfe):
Horizontal Marcellus Play (a)
54,515
26,842
103.1
Horizontal Huron Play
8,031
9,666
(16.9
CBM Play
3,116
3,298
(5.5
Other (vertical non-CBM)
13,730
14,264
(3.7
Total production sales volumes
Average daily sales volumes (MMcfe/d)
882
594
48.5
Average effective sales price to EQT Production ($/Mcfe)
Lease operating expenses (LOE), excluding production taxes ($/Mcfe)
0.16
0.20
(20.0
Production taxes ($/Mcfe) (b)
0.15
0.18
Production depletion ($/Mcfe)
1.54
1.56
(1.3
Depreciation, depletion and amortization (DD&A) (thousands):
Production depletion
122,491
84,526
44.9
Other DD&A
2,418
2,041
18.5
Total DD&A (thousands)
44.3
Capital expenditures (thousands)
34.4
FINANCIAL DATA (thousands)
Total net operating revenues
28.2
LOE, excluding production taxes
13,039
10,936
19.2
Production taxes (b)
11,851
16,087
(26.3
Exploration expense
104.0
Selling, general and administrative (SG&A)
22,885
20,940
9.3
DD&A
176,414
136,358
29.4
25.5
(a) Includes Upper Devonian and Utica wells.
(b) Production taxes include severance and production-related ad valorem and other property taxes. Production taxes also include the Pennsylvania impact fee of $2.9 million for the three months ended March 31, 2013 compared to $8.2 million for the three months ended March 31, 2012, of which $6.2 million represented the retroactive fee for pre-2012 Marcellus wells. The production taxes unit rate for the three months ended March 31, 2012 excludes the impact of the $6.2 million accrual for pre-2012 Marcellus wells.
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EQT Production’s operating income totaled $74.1 million for the three months ended March 31, 2013 compared to $59.0 million for the three months ended March 31, 2012. The $15.1 million increase in operating income was primarily due to an increase in sales of produced natural gas partially offset by a lower average effective sales price and an increase in operating expenses.
Total operating revenues were $250.5 million for the three months ended March 31, 2013 compared to $195.4 million for the three months ended March 31, 2012. The $55.1 million increase in operating revenues was primarily due to a 47% increase in production sales volumes which more than offset a 13% decrease 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 $0.45 per Mcfe decrease in the average effective sales price to EQT Production was primarily due to a smaller hedge gain and lower NGL prices, which more than offset a 22% increase in the average NYMEX natural gas price and lower gathering rates compared to the first quarter of 2012. The average effective sales price was also impacted unfavorably in 2013 by an increase in the cost of third-party transmission capacity, net of excess capacity sales, primarily on the El Paso 300 line.
Operating expenses totaled $176.4 million for the three months ended March 31, 2013 compared to $136.4 million for the three months ended March 31, 2012. The increase in operating expenses was the result of increases in DD&A, LOE, SG&A and exploration expense partially offset by a decrease in production taxes. DD&A expense increased as a result of higher produced volumes in the current year. The increase in SG&A expense was primarily a result of higher environmental reserves for remediation. The increase in LOE was mainly due to increased Marcellus activity. The increase in exploration expense was due to increased impairments of unproved lease acreage resulting from lease expirations during the first quarter of 2013.
In February 2012, the Commonwealth of Pennsylvania passed legislation imposing a natural gas impact fee. The legislation, which covers a significant portion of EQT’s Marcellus acreage, imposes an annual fee for a period of fifteen years on each well drilled in Pennsylvania. The impact fee adjusts annually based on three factors: age of the well, changes in the Consumer Price Index and the average monthly NYMEX natural gas price. Production taxes decreased in the first quarter of 2013 compared to the first quarter of 2012, primarily due to a $5.3 million decrease in the Pennsylvania impact fee. During the first quarter of 2013, the Pennsylvania impact fee was $2.9 million compared to $8.2 million in the first quarter of 2012, of which $6.2 million represented a retroactive fee for pre-2012 Marcellus wells. Production taxes also decreased in the first quarter of 2013 compared to the first quarter of 2012 due to a $1.4 million decrease in property taxes primarily as a result of lower assessments received during the first quarter of 2013. The decreases in the Pennsylvania impact fee and property taxes were partially offset by a $2.5 million increase in severance taxes due to higher market sales prices and higher production sales volumes in certain jurisdictions subject to these taxes.
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EQT MIDSTREAM
Gathered volumes (BBtu)
101,231
71,166
42.2
Average gathering fee ($/MMBtu)
0.81
0.97
(16.5
Gathering and compression expense ($/MMBtu)
0.19
0.28
(32.1
Transmission pipeline throughput (BBtu)
80,971
42,075
92.4
Net operating revenues (thousands):
Gathering
81,814
69,253
18.1
Transmission
37,307
22,941
62.6
Storage, marketing and other
9,759
14,923
(34.6
128,880
107,117
20.3
Unrealized gains (losses) on derivatives and inventory (thousands) (a)
1,674
(5,447
(130.7
(35.5
Total operating revenues
20.2
17,808
14,931
19.3
Operating and maintenance (O&M)
22,673
24,104
(5.9
SG&A
13,774
12,169
13.2
23.9
54,666
50,981
7.2
32.2
(a) Included in storage, marketing and other net operating revenues.
EQT Midstream’s operating income totaled $74.2 million for the three months ended March 31, 2013 compared to $56.1 million for the three months ended March 31, 2012. The $18.1 million increase in operating income was primarily the result of increased transmission net operating revenues and increased gathering net operating revenues partially offset by a decrease in storage, marketing and other net operating revenues and increased operating expenses.
Total net operating revenues were $128.9 million for the three months ended March 31, 2013 compared to $107.1 million for the three months ended March 31, 2012. The increase in total net operating revenues was due to a $14.4 million increase in transmission net operating revenues and a $12.6 million increase in gathering net operating revenues partially offset by a $5.2 million decrease in storage, marketing and other net operating revenues.
Transmission net operating revenues increased $14.4 million in the first quarter of 2013 compared to the first quarter of 2012 primarily as a result of the addition of $7.0 million in capacity reservation revenues for the Sunrise Pipeline (which was placed into service in July 2012) and an additional $5.9 million of higher transportation firm service revenues from affiliated shippers due to increased Marcellus volumes.
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Gathering net operating revenues increased $12.6 million in the first quarter of 2013 compared to the same period in the prior year due to a 42% 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 volumes are charged a lower gathering rate than Huron and other volumes, and a $0.06 per unit decrease from 2012 to 2013 in the Marcellus gathering charge to affiliates, due to greater economies of scale achieved in recent periods.
Lower realized margins and reduced activity due to lower price spreads reduced storage, marketing and other net operating revenues by approximately $10.3 million. Storage, marketing and other net operating revenues related to NGLs marketed for non-affiliated producers decreased by $1.7 million primarily as a result of lower liquids pricing. The decreases in storage, marketing and other net operating revenues were partially offset by the $7.1 million favorable change in unrealized gains (losses) on derivatives and inventory.
Total operating revenues increased $24.6 million primarily as a result of increased transmission revenues and increased gathered volumes, which was partly offset by reduced total operating revenues for storage, marketing and other. Total purchased gas costs increased $2.9 million primarily as a result of an increase in commodity prices.
Operating expenses totaled $54.7 million for the three months ended March 31, 2013 compared to $51.0 million for the three months ended March 31, 2012. The $3.7 million increase in operating expenses was primarily due to increased DD&A expense as a result of additional assets placed in-service, increased personnel costs and allocated expenses from affiliates in 2013 partially offset by decreases in gathering business expenses in 2013.
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DISTRIBUTION
Heating degree days (30-year average = 2,870)
2,904
2,232
30.1
Residential sales and transportation volumes (MMcf)
11,652
9,055
28.7
Commercial and industrial volumes (MMcf)
10,041
9,359
7.3
Total throughput (MMcf)
21,693
18,414
17.8
Residential
54,067
40,660
33.0
Commercial and industrial
19,706
17,023
15.8
Off-system and energy services
4,938
5,708
(13.5
78,711
63,391
24.2
2.6
13.6
75,107
72,030
4.3
Net operating revenues
O&M
10,035
10,213
(1.7
10,352
10,165
1.8
(3.1
26,435
26,621
Distribution’s operating income totaled $52.3 million for the three months ended March 31, 2013 compared to $36.8 million for the three months ended March 31, 2012. The increase in 2013 operating income was primarily due to colder weather and a favorable change in estimated recoverable costs due to the completion of the Company’s most recent gas cost audit.
Net operating revenues were $78.7 million for the first quarter of 2013 compared to $63.4 million for the first quarter of 2012. The $15.3 million increase in net operating revenues was due to several factors. Net operating revenues from residential and commercial and industrial customers increased $11.9 million as a result of favorable weather and related customer usage patterns. Weather was 30% colder in the first quarter of 2013 as compared to the first quarter of 2012 and one percent colder compared to the 30-year National Oceanic and Atmospheric Administration average for the Company’s service territory. Residential net operating revenues also increased $5.0 million due to the completion of the Company’s most recent gas cost audit which resulted in a favorable change to estimated recoverable costs. Off-system and energy services net operating revenues decreased $0.8 million primarily due to lower gathered volumes in the first quarter of 2013 as compared to the same period in 2012. 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 first quarter of 2013 partly offset by a decrease in the commodity component of tariff rates
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and a decrease in asset optimization off-system and energy services transactions. The increase in purchased gas costs was also partly offset by the favorable change in estimated recoverable costs due to the completion of the Company’s most recent gas cost audit.
Operating expenses totaled $26.4 million for the three months ended March 31, 2013 compared to $26.6 million for the three months ended March 31, 2012. The $0.2 million decrease in operating expenses was primarily due to the reversal of a $1.0 million operating reserve resulting from the completion of the Company’s most recent gas cost audit, lower O&M costs, lower labor costs and lower DD&A expense. These decreases were partially offset by higher bad debt expense of $1.7 million as a result of increased gas sales due to colder weather. The Company will continue to closely monitor its collection rates and adjust its reserve for uncollectible accounts as necessary.
OUTLOOK
The Company is committed to profitably developing its Marcellus 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.
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 172 gross wells, including 153 Marcellus wells, 11 Upper Devonian wells and eight wells in the Utica Shale of Ohio. Sales volumes for 2013 are expected to be between 340 and 350 Bcfe, approximately 33% higher than in 2012, while NGL volumes are expected to be between 4,500 and 4,700 Mbbls. In addition, the Company plans to spend approximately $400 million on midstream infrastructure in 2013 primarily to support its 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 2013 capital spending plan is expected to be funded by cash on hand, cash flow generated from operations and proceeds from expected midstream dropdowns to the Partnership.
On December 19, 2012, 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 EQT and Holdco will transfer 100% of their ownership interests of 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. 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; and will soon file with the Kentucky Public Service Commission — each must approve the transaction as part of the regulatory process. The Company expects to receive all necessary approvals by year end. 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 to the Partnership or others and joint ventures, to monetize the value of mature assets for re-deployment into higher-value Marcellus Shale development.
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CAPITAL RESOURCES AND LIQUIDITY
Overview
The Company’s primary source of cash for the three months ended March 31, 2013 was cash flows from operating activities, while the primary use of cash was for capital expenditures.
Operating Activities
Cash flows provided by operating activities totaled $305.2 million for the first quarter of 2013 compared to $222.1 million for the first quarter of 2012, an increase of $83.1 million. This increase was primarily a result of a 47% increase in natural gas volumes sold, increases in gathered volumes and transmission pipeline throughput, colder weather and lower interest payments due to the repayment of long-term debt that matured in 2012, partially offset by lower average effective sales prices to EQT.
Investing Activities
Net cash flows used in investing activities totaled $304.3 million for the first quarter of 2013 compared to $267.2 million for the first quarter of 2012. Capital expenditures totaled $304.3 million for the first quarter of 2013 compared to $269.6 million for the first quarter of 2012.
Capital expenditures for EQT Production totaled $246.9 million for the first quarter of 2013 compared to $183.7 million for the first quarter of 2012. The $63.2 million increase was primarily attributable to the increase in the number of completed frac stages in the Marcellus play, with 1,097 frac stages completed in the first quarter of 2013 compared to 824 frac stages completed in the first quarter of 2012. The Company commenced drilling on (drilled) 41 gross horizontal wells during the first quarter of 2013; 33 targeting the Marcellus play, 6 targeting the Upper Devonian play and 2 targeting the Utica play. The Company commenced drilling on 40 gross horizontal wells during the first quarter of 2012; 32 targeting the Marcellus play, 1 targeting the Upper Devonian play and 7 targeting the Huron play.
Capital expenditures for EQT Midstream totaled $51.4 million for the first quarter of 2013 compared to $79.6 million for the first quarter of 2012. The $28.2 million decrease was primarily due to the completion of the Sunrise Pipeline project, which was placed into service during the third quarter of 2012. This decrease was partially offset by increased expenditures for gathering pipeline projects in the Marcellus region.
Capital expenditures for Distribution totaled $5.6 million for the first quarter of 2013 compared to $5.5 million for the first quarter of 2012, primarily for pipeline replacement.
Financing Activities
Cash flows used in financing activities totaled $22.7 million for the first quarter of 2013 compared to $41.0 million for the first quarter of 2012, a decrease of $18.3 million between periods. In December 2012, the Company announced a new annual dividend rate, effective January 2013, of $0.12 per share, which resulted in dividends paid of $4.5 million in the first quarter of 2013 compared to dividends paid of $32.9 million in the first quarter of 2012. The decrease in dividends paid was partially offset by a $10.6 million increase in repayments of long-term debt during the first quarter of 2013 compared to the first quarter of 2012.
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Security Ratings and Financing Triggers
The table below reflects the credit ratings for debt instruments of the Company at March 31, 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 its access to the credit markets.
Rating Service
Senior Notes
Short-Term Rating
Outlook
Moody’s Investors Service (Moody’s)
Baa3
P-3
Stable
Standard & Poor’s Ratings Services
BBB
A-2
Fitch Ratings
BBB-
F3
On March 21, 2013, Moody’s downgraded the Company’s ratings to Baa3/P-3, with a stable outlook, from Baa2/P-2. This action concluded the review that Moody’s initiated on December 20, 2012 following the Company’s announcement of the Master Purchase Agreement with PNG Companies.
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 instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. The most significant default events include maintaining covenants with respect to maximum debt-to-total capitalization ratio, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. The Company’s current credit facility 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 March 31, 2013, the Company was in compliance with all debt provisions and covenants.
The Partnership’s credit facility contains various covenants and restrictive provisions that, if not complied with, could require early payment or similar action, including a requirement 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 March 31, 2013, the Partnership was in compliance with all debt 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 result in physical delivery.
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As of April 24, 2013, the approximate volumes and prices of the Company’s total hedge position for April 2013 through 2015 production were:
2013**
2014
2015
Fixed Price
Total Volume (Bcf)
110
69
Average Price per Mcf (NYMEX)*
4.55
4.48
4.59
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.
**April 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 or 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 financial position, results of operations or liquidity of the Company.
Dividend
On April 17, 2013, the Board of Directors of the Company declared a regular quarterly cash dividend of three cents per share, payable June 1, 2013, to the Company’s shareholders of record at the close of business on May 17, 2013.
On April 23, 2013, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.37 per unit. The cash distribution is payable on May 15, 2013 to unitholders of record at the close of business on May 6, 2013.
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 month period ended March 31, 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.
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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 through 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 purchased from or 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 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 March 31, 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 418 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 March 31, 2013 and December 31, 2012 levels would increase the fair value of non-trading natural gas derivative instruments by approximately $166.3 million and $131.0 million, respectively. A hypothetical increase of 10% in the market price of natural gas from the March 31, 2013 and December 31, 2012 levels would decrease the fair value of non-trading natural gas derivative instruments by approximately $166.1 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 D to the Condensed Consolidated Financial Statements. The Company assumed a 10% change in the price of natural gas from its levels at March 31, 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 instrument portfolio is managed to complement the physical transaction portfolio, reducing overall risks within
33
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 67%, or $182.1 million, of the Company’s OTC derivative contracts outstanding at March 31, 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 March 31, 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.
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 March 31, 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
34
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 borrowing by the Partnership. As of March 31, 2013, the Partnership had no loans or letters of credit outstanding under the revolving credit 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 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 first 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 or 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 financial position, results of operations or liquidity of the Company.
Item 1A. Risk Factors
Information regarding risk factors is discussed in Item 1A, “Risk Factors” of the Company’s Form 10-K for the year ended December 31, 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 March 31, 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 to be purchased under the plans or programs
January 2013 (January 1 – January 31)
February 2013 (February 1 – February 28)
16,917
59.55
March 2013 (March 1 – March 31)
(a) Reflects shares withheld by the Company to pay taxes upon vesting of restricted stock.
Item 6. Exhibits
2.01
Amendment No. 1 to Master Purchase Agreement dated as of February 22, 2013 among the Company, Distribution Holdco, LLC and PNG Companies LLC
3.01
Restated Articles of Incorporation of the Company (amended through April 17, 2013)
3.02
Amended and Restated By-Laws of the Company (amended through April 17, 2013)
31.01
Rule 13(a)-14(a) Certification of Principal Executive Officer
31.02
Rule 13(a)-14(a) Certification of Principal Financial Officer
Section 1350 Certification of Principal Executive Officer and Principal Financial Officer
101
Interactive Data File
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
(Registrant)
By:
/s/ Philip P. Conti
Philip P. Conti
Senior Vice President and Chief Financial Officer
Date: April 25, 2013
INDEX TO EXHIBITS
Exhibit No.
Method of Filing
Filed herewith as Exhibit 2.01
Filed herewith as Exhibit 3.01
Filed as Exhibit 3.2 to Form 8-K filed on April 18, 2013
Filed herewith as Exhibit 31.01
Filed herewith as Exhibit 31.02
Filed herewith as Exhibit 32
Filed herewith as Exhibit 101