Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2009
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number 1-14365
El Paso Corporation
(Exact Name of Registrant as Specified in Its Charter)
Delaware | 76-0568816 | |
(State or Other Jurisdiction of | (I.R.S. Employer | |
Incorporation or Organization) | Identification No.) | |
El Paso Building | 77002 | |
1001 Louisiana Street | (Zip Code) | |
Houston, Texas | ||
(Address of Principal Executive Offices) |
Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com
Internet Website: www.elpaso.com
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.
Yesþ Noo
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yeso Noo
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. (Check one):
Large accelerated filerþ | Accelerated filero | Non-accelerated filero | Smaller reporting companyo | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Common stock, par value $3 per share. Shares outstanding on May 6, 2009: 701,004,510
EL PASO CORPORATION
TABLE OF CONTENTS
TABLE OF CONTENTS
Below is a list of terms that are common to our industry and used throughout this document:
/d | = per day | MMBtu | = million British thermal units | |||
Bbl | = barrels | MMcf | = million cubic feet | |||
BBtu | = billion British thermal units | MMcfe | = million cubic feet of natural gas equivalents | |||
Bcf | = billion cubic feet | GWh | = thousand megawatt hours | |||
LNG | = liquefied natural gas | GW | = gigawatts | |||
MBbls | = thousand barrels | NGL | = natural gas liquids | |||
Mcf | = thousand cubic feet | TBtu | = trillion British thermal units | |||
Mcfe | = thousand cubic feet of natural gas equivalents |
When we refer to natural gas and oil in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to “us”, “we”, “our”, “ours”, “the company” or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.
2
Table of Contents
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per common share amounts)
(Unaudited)
(In millions, except per common share amounts)
(Unaudited)
Quarter Ended | ||||||||
March 31, | �� | |||||||
2009 | 2008 | |||||||
Operating revenues | $ | 1,484 | $ | 1,269 | ||||
Operating expenses | ||||||||
Cost of products and services | 61 | 56 | ||||||
Operation and maintenance | 300 | 271 | ||||||
Ceiling test charges | 2,068 | — | ||||||
Depreciation, depletion and amortization | 256 | 313 | ||||||
Taxes, other than income taxes | 68 | 79 | ||||||
2,753 | 719 | |||||||
Operating income (loss) | (1,269 | ) | 550 | |||||
Earnings from unconsolidated affiliates | 19 | 37 | ||||||
Other income, net | 22 | 22 | ||||||
Interest and debt expense | (255 | ) | (233 | ) | ||||
Income (loss) before income taxes | (1,483 | ) | 376 | |||||
Income tax expense (benefit) | (526 | ) | 148 | |||||
Net income (loss) | (957 | ) | 228 | |||||
Net income attributable to noncontrolling interests | (12 | ) | (9 | ) | ||||
Net income (loss) attributable to El Paso Corporation | (969 | ) | 219 | |||||
Preferred stock dividends | 9 | 19 | ||||||
Net income (loss) attributable to El Paso Corporation’s common stockholders | $ | (978 | ) | $ | 200 | |||
Basic and diluted earnings per common share | ||||||||
Net income (loss) attributable to El Paso Corporation’s common stockholders | $ | (1.41 | ) | $ | 0.29 | |||
Dividends declared per El Paso Corporation’s common share | $ | 0.05 | $ | 0.08 | ||||
See accompanying notes.
3
Table of Contents
EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
(Unaudited)
(In millions, except share amounts)
(Unaudited)
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 1,841 | $ | 1,024 | ||||
Accounts and notes receivable | ||||||||
Customers, net of allowance of $9 in 2009 and 2008 | 360 | 466 | ||||||
Affiliates | 127 | 133 | ||||||
Other | 193 | 217 | ||||||
Materials and supplies | 192 | 187 | ||||||
Assets from price risk management activities | 678 | 876 | ||||||
Other | 159 | 148 | ||||||
Total current assets | 3,550 | 3,051 | ||||||
Property, plant and equipment, at cost | ||||||||
Pipelines | 18,301 | 18,042 | ||||||
Natural gas and oil properties, at full cost | 20,328 | 20,009 | ||||||
Other | 345 | 342 | ||||||
38,974 | 38,393 | |||||||
Less accumulated depreciation, depletion and amortization | 22,899 | 20,535 | ||||||
Total property, plant and equipment, net | 16,075 | 17,858 | ||||||
Other assets | ||||||||
Investments in unconsolidated affiliates | 1,764 | 1,703 | ||||||
Assets from price risk management activities | 195 | 201 | ||||||
Deferred income taxes | 145 | 2 | ||||||
Other | 695 | 853 | ||||||
2,799 | 2,759 | |||||||
Total assets | $ | 22,424 | $ | 23,668 | ||||
See accompanying notes.
4
Table of Contents
EL PASO CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except for share amounts)
(Unaudited)
(In millions, except for share amounts)
(Unaudited)
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | ||||||||
Trade | $ | 265 | $ | 372 | ||||
Affiliates | 11 | 6 | ||||||
Other | 477 | 674 | ||||||
Short-term financing obligations, including current maturities | 961 | 1,090 | ||||||
Liabilities from price risk management activities | 194 | 250 | ||||||
Accrued interest | 260 | 192 | ||||||
Other | 674 | 659 | ||||||
Total current liabilities | 2,842 | 3,243 | ||||||
Long-term financing obligations, less current maturities | 13,541 | 12,818 | ||||||
Other | ||||||||
Liabilities from price risk management activities | 646 | 767 | ||||||
Deferred income taxes | 182 | 565 | ||||||
Other | 1,687 | 1,679 | ||||||
2,515 | 3,011 | |||||||
Commitments and contingencies (Note 9) | ||||||||
Equity | ||||||||
El Paso Corporation stockholders’ equity: | ||||||||
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares of 4.99% convertible perpetual stock; stated at liquidation value | 750 | 750 | ||||||
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 712,760,115 shares in 2009 and 712,628,781 shares in 2008 | 2,138 | 2,138 | ||||||
Additional paid-in capital | 4,582 | 4,612 | ||||||
Accumulated deficit | (3,622 | ) | (2,653 | ) | ||||
Accumulated other comprehensive loss | (605 | ) | (532 | ) | ||||
Treasury stock (at cost); 14,106,447 shares in 2009 and 14,061,474 shares in 2008 | (280 | ) | (280 | ) | ||||
Total El Paso Corporation stockholders’ equity | 2,963 | 4,035 | ||||||
Noncontrolling interests | 563 | 561 | ||||||
Total equity | 3,526 | 4,596 | ||||||
Total liabilities and equity | $ | 22,424 | $ | 23,668 | ||||
See accompanying notes.
5
Table of Contents
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
(In millions)
(Unaudited)
Quarter Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
Cash flows from operating activities | ||||||||
Net income (loss) | $ | (957 | ) | $ | 228 | |||
Adjustments to reconcile net income (loss) to net cash from operating activities | ||||||||
Depreciation, depletion and amortization | 256 | 313 | ||||||
Ceiling test charges | 2,068 | — | ||||||
Deferred income tax expense (benefit) | (528 | ) | 146 | |||||
Earnings from unconsolidated affiliates, adjusted for cash distributions | (8 | ) | 23 | |||||
Other non-cash income items | 14 | 6 | ||||||
Asset and liability changes | (36 | ) | (82 | ) | ||||
Net cash provided by operating activities | 809 | 634 | ||||||
Cash flows from investing activities | ||||||||
Capital expenditures | (759 | ) | (531 | ) | ||||
Cash paid for acquisitions, net of cash acquired | — | (295 | ) | |||||
Net proceeds from the sale of assets and investments | 210 | 598 | ||||||
Other | 13 | 37 | ||||||
Net cash used in investing activities | (536 | ) | (191 | ) | ||||
Cash flows from financing activities | ||||||||
Net proceeds from issuance of long-term debt | 842 | 1,240 | ||||||
Payments to retire long-term debt and other financing obligations | (244 | ) | (1,430 | ) | ||||
Dividends paid | (44 | ) | (38 | ) | ||||
Distributions to noncontrolling interest holders | (10 | ) | (4 | ) | ||||
Other | — | 2 | ||||||
Net cash provided by (used in) financing activities | 544 | (230 | ) | |||||
Change in cash and cash equivalents | 817 | 213 | ||||||
Cash and cash equivalents | ||||||||
Beginning of period | 1,024 | 285 | ||||||
End of period | $ | 1,841 | $ | 498 | ||||
See accompanying notes.
6
Table of Contents
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
(Unaudited)
(In millions)
(Unaudited)
Quarter Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
El Paso Corporation stockholders’ equity: | ||||||||
Preferred stock: | ||||||||
Balance at beginning and end of period | $ | 750 | $ | 750 | ||||
Common stock: | ||||||||
Balance at beginning of period | 2,138 | 2,128 | ||||||
Other, net | — | 1 | ||||||
Balance at end of period | 2,138 | 2,129 | ||||||
Additional paid-in capital: | ||||||||
Balance at beginning of period | 4,612 | 4,699 | ||||||
Dividends | (44 | ) | (75 | ) | ||||
Other, including stock-based compensation | 14 | 15 | ||||||
Balance at end of period | 4,582 | 4,639 | ||||||
Accumulated deficit: | ||||||||
Balance at beginning of period | (2,653 | ) | (1,834 | ) | ||||
Net income (loss) attributable to El Paso Corporation | (969 | ) | 219 | |||||
Cumulative effect of adopting SFAS No. 158, net of income tax of $2 | — | 5 | ||||||
Balance at end of period | (3,622 | ) | (1,610 | ) | ||||
Accumulated other comprehensive income (loss): | ||||||||
Balance at beginning of period | (532 | ) | (272 | ) | ||||
Other comprehensive loss | (73 | ) | (118 | ) | ||||
Cumulative effect of adopting SFAS No. 158, net of income tax of $2 | — | 3 | ||||||
Balance at end of period | (605 | ) | (387 | ) | ||||
Treasury stock, at cost: | ||||||||
Balance at beginning of period | (280 | ) | (191 | ) | ||||
Stock-based and other compensation | — | (1 | ) | |||||
Balance at end of period | (280 | ) | (192 | ) | ||||
Total El Paso Corporation stockholders’ equity at end of period | 2,963 | 5,329 | ||||||
Noncontrolling interests: | ||||||||
Balance at beginning of period | 561 | 565 | ||||||
Distributions paid to noncontrolling interests | (10 | ) | (4 | ) | ||||
Net income attributable to noncontrolling interests | 12 | 9 | ||||||
Other | — | (23 | ) | |||||
Balance at end of period | 563 | 547 | ||||||
Total equity at end of period | $ | 3,526 | $ | 5,876 | ||||
See accompanying notes.
7
Table of Contents
EL PASO CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
(Unaudited)
(In millions)
(Unaudited)
Quarter Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
Net income (loss) | $ | (957 | ) | $ | 228 | |||
Pension and postretirement obligations: | ||||||||
Unrealized actuarial losses arising during period (net of income taxes of $1 in 2008) | — | (2 | ) | |||||
Reclassification of actuarial gains and losses during period (net of income taxes of $4 in 2009 and $2 in 2008) | 7 | 5 | ||||||
Cash flow hedging activities: | ||||||||
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $1 in 2009 and $70 in 2008) | 2 | (123 | ) | |||||
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $46 in 2009 and $1 in 2008) | (82 | ) | 2 | |||||
Other comprehensive loss | (73 | ) | (118 | ) | ||||
Comprehensive income (loss) | (1,030 | ) | 110 | |||||
Comprehensive income attributable to noncontrolling interests | (12 | ) | (9 | ) | ||||
Comprehensive income (loss) attributable to El Paso Corporation | $ | (1,042 | ) | $ | 101 | |||
See accompanying notes.
8
Table of Contents
EL PASO CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
1. Basis of Presentation and Significant Accounting Policies
Basis of Presentation
We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles. You should read this Quarterly Report on Form 10-Q along with our 2008 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2009, and for the quarters ended March 31, 2009 and 2008, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2008, from the audited balance sheet filed in our 2008 Annual Report on Form 10-K. As discussed below, certain amounts related to noncontrolling interests have been retrospectively adjusted within these consolidated financial statements to reflect the adoption of Statement of Financial Accounting Standards (SFAS) No. 160,Noncontrolling Interests in Consolidated Financial Statements. Our financial statements for prior periods also include certain reclassifications that were made to conform to the current period presentation. There were no reclassifications that impacted our reported net income (loss) or stockholders’ equity other than those required by SFAS No. 160. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of our operating results for the entire year.
Significant Accounting Policies
The information below provides an update of our significant accounting policies and accounting pronouncements issued but not yet adopted as discussed in our 2008 Annual Report on Form 10-K.
Fair Value Measurements.On January 1, 2009, we adopted the provisions of SFAS No. 157,Fair Value Measurements,for our non-financial assets and liabilities that are measured at fair value on a non-recurring basis, as further described in Note 6. The adoption did not have a material impact on our financial statements.
On January 1, 2009, we adopted the provisions of the Emerging Issues Task Force (EITF) Issue No. 08-5,Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement.EITF Issue No. 08-5 provides guidance to companies about how they should consider their own credit in determining the fair value of their liabilities that have third party credit enhancements related to them. Substantially all of our derivative liabilities in our Marketing segment are supported by letters of credit. This standard requires that non-cash credit enhancements, such as letters of credit, should not be considered in determining the fair value of these liabilities, including derivative liabilities Accordingly, we recorded a $34 million gain (net of $18 million of taxes), or $0.05 per share, as a result of adopting EITF Issue No. 08-5.
Business Combinations.On January 1, 2009, we adopted SFAS No. 141(R),Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, noncontrolling interests and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) applies to acquisitions that are effective after December 31, 2008.
9
Table of Contents
Noncontrolling Interests.Effective January 1, 2009, we adopted the provisions of SFAS No. 160, which provides guidance on the presentation of noncontrolling interests in the financial statements. This standard requires us to present our noncontrolling interests, which primarily relate to El Paso Pipeline Partners, L.P., our consolidated subsidiary, as a separate component of equity rather than as a “mezzanine” item between liabilities and equity in our balance sheets, and also requires us to present our noncontrolling interests as a separate caption in our income statements. Our financial statements for all periods presented have been adjusted to apply the provisions of this statement. This standard also requires all transactions with noncontrolling interest holders, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs.
New Accounting Pronouncements Issued But Not Yet Adopted
As of March 31, 2009, the following accounting standard had not yet been adopted by us:
Oil and Gas Reserves Reporting.In December 2008, the SEC issued a final rule adopting revisions to its oil and gas reporting requirements. The revisions will impact the determination and disclosures of oil and gas reserves information. Among other items, the new rules will revise the definition of proved reserves and will require full cost companies to use a twelve month average commodity price in determining future net revenues, rather than a period-end price as is currently required. These changes, along with other proposed changes, will impact the manner in which we perform our full cost ceiling test calculation and determine any related ceiling test charge. The provisions of this final rule are effective on December 31, 2009, and cannot be applied earlier than that date. We are currently assessing the impact that this final rule may have on our determination and disclosures of oil and gas reserves information.
2. Acquisitions and Divestitures
Acquisitions
Gulf LNG.In February 2008, we paid $295 million to complete the acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, an LNG terminal which is currently under construction in Pascagoula, Mississippi. The terminal is expected to be placed in service in late 2011 at an estimated total cost of $1.1 billion. In addition, we have a commitment to loan Gulf LNG up to $150 million for which we have advanced approximately $33 million as of March 31, 2009. Our partner in this project has a commitment to loan up to $64 million. We account for our investment in Gulf LNG using the equity method.
Divestitures
During the first quarter of 2009, we completed the sale of our interests in the Porto Velho power generation facility in Brazil for total consideration of $179 million (see Note 13) and the sale of non-core natural gas producing properties located in our Western and Central regions for approximately $93 million. During 2008, we sold natural gas and oil properties primarily in the Gulf of Mexico and Texas Gulf Coast regions for total proceeds of $637 million, of which approximately $600 million was sold during the first quarter of 2008.
3. Ceiling Test Charges
In the first quarter of 2009, we recorded a reduction to our property, plant and equipment due to non-cash ceiling test charges of $2.1 billion that resulted primarily from declines in natural gas prices. Capitalized costs exceeded the ceiling limit by approximately $2.0 billion for our domestic full cost pool, approximately $28 million for our Brazilian full cost pool and approximately $9 million for our Egyptian full cost pool. The calculation of these charges was based on the March 31, 2009 spot natural gas price of $3.63 per MMBtu and oil price of $49.66 per barrel. In calculating our ceiling test charges, we are required to hold these prices constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from period to period. We may be required to record additional ceiling test charges in the future if commodity prices continue to decrease from their current levels.
10
Table of Contents
4. Income Taxes
Income taxes for the quarters ended March 31 were as follows:
2009 | 2008 | |||||||
(In millions, except rates) | ||||||||
Income tax (benefit) expense | $ | (526 | ) | $ | 148 | |||
Effective tax rate | 35 | % | 39 | % |
Effective Tax Rate. We compute interim period income taxes by applying an anticipated annual effective tax rate to our year-to-date income or loss, except for significant unusual or infrequently occurring items. Significant tax items are recorded in the period that the item occurs. Our effective tax rate may be affected by items such as dividend exclusions on earnings from unconsolidated affiliates where we anticipate receiving dividends, the effect of state income taxes (net of federal income tax effects), and the effect of foreign income which can be taxed at different rates.
During the first quarter of 2009, our effective tax rate was relatively consistent with the statutory rate and the customary relationship between our pretax accounting income and income tax expense. During the first quarter of 2008, our effective tax rate was higher than the statutory rate primarily due to the tax impact of adjusting our postretirement benefit obligations, as discussed in Note 10.
Deferred Tax Asset. As of March 31, 2009, we have a net federal deferred tax asset of $179 million as a result of recognizing a deferred tax benefit attributable to the domestic ceiling test charge during the first quarter of 2009. We believe it is more likely than not that we will realize the benefit of this net deferred tax asset (net of existing valuation allowances) based on recognition of sufficient taxable income during periods in which those temporary differences or net operating losses are deductible.
5. Earnings Per Share
We calculated basic and diluted earnings per common share as follows for the quarters ended March 31:
2009 | 2008 | |||||||||||||||
Basic | Diluted | Basic | Diluted | |||||||||||||
(In millions, except per share amounts) | ||||||||||||||||
Net income (loss) attributable to El Paso Corporation | $ | (969 | ) | $ | (969 | ) | $ | 219 | $ | 219 | ||||||
Convertible preferred stock dividends | (9 | ) | (9 | ) | (19 | )(1) | (19 | )(1) | ||||||||
Net income (loss) attributable to El Paso | ||||||||||||||||
Corporation’s common stockholders | $ | (978 | ) | $ | (978 | ) | $ | 200 | $ | 200 | ||||||
Weighted average common shares outstanding | 695 | 695 | 697 | 697 | ||||||||||||
Effect of dilutive securities: | ||||||||||||||||
Options and restricted stock | — | — | — | 4 | ||||||||||||
Weighted average common shares outstanding and dilutive securities | 695 | 695 | 697 | 701 | ||||||||||||
Basic and diluted earnings per common share: | ||||||||||||||||
Net income (loss) attributable to El Paso | ||||||||||||||||
Corporation’s common stockholders | $ | (1.41 | ) | $ | (1.41 | ) | $ | 0.29 | $ | 0.29 | ||||||
(1) | Includes dividends declared in February 2008 and March 2008. |
We exclude potentially dilutive securities (as well as their related income statement impacts) from the determination of diluted earnings per share when their impact on income from continuing operations per common share is antidilutive. These potentially dilutive securities consist of our employee stock options, restricted stock, convertible preferred stock and trust preferred securities. For the quarter ended March 31, 2009, we incurred losses
11
Table of Contents
attributable to El Paso Corporation and, accordingly, excluded all of our potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. For the quarter ended March 31, 2008, certain of our employee stock options, our convertible preferred stock, and our trust preferred securities were antidilutive. For a further discussion of our potentially dilutive securities, see our 2008 Annual Report on Form 10-K.
6. Fair Value Measurements
We apply the provisions of SFAS No. 157,Fair Value Measurements, to our assets and liabilities that are measured at fair value. We adopted the provisions of SFAS No. 157 on January 1, 2009 for our non-financial assets and liabilities that are measured at fair value on a non-recurring basis, which primarily relates to any impairment of long-lived assets or investments. During the quarter ended March 31, 2009, we did not have any non-financial assets and liabilities that were recorded at fair value subsequent to their initial measurement.
We use various methods to determine the fair values of our financial instruments and other derivatives that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. We separate our financial instruments and other derivatives into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments.
Each of these levels and our corresponding instruments classified by level are further described below:
• | Level 1 instruments’ fair values are based on quoted prices for the instruments in actively traded markets. Included in this level are our marketable securities invested in non-qualified compensation plans whose fair value is determined using the quoted prices of these instruments. | ||
• | Level 2 instruments’ fair values are primarily based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). Included in this level are our foreign currency and interest rate swaps. Also included in this level are our production-related natural gas and oil derivatives and certain of our other natural gas derivatives (such as natural gas supply arrangements) whose fair values are based on commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions). | ||
• | Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 above, but their fair value also reflects adjustments for being in less liquid markets or having longer contractual terms. For these instruments, we obtain pricing data from third party pricing sources, adjust this data based on the liquidity of the underlying forward markets over the contractual terms and use the adjusted pricing data to develop an estimate of forward price curves that market participants would use. The curves are then used to estimate the value of settlements in future periods based on contractual settlement quantities and dates. Our valuation of these instruments considers specific contractual terms, statistical and simulation analysis, present value concepts and other internal assumptions related to (i) contract maturities that extend beyond the periods in which quoted market prices are available; (ii) the uniqueness of the contract terms; (iii) the limited availability of forward pricing information in markets where there is a lack of viable participants, such as in the PJM forward power market and the forward market for ammonia; and (iv) our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions). Since a significant portion of the fair value of our power-related derivatives and certain of our remaining natural gas derivatives with longer terms or in less liquid markets than similar Level 2 derivatives, rely on the techniques discussed above, we classify these instruments as Level 3 instruments. |
12
Table of Contents
Listed below are the fair values of our financial instruments that are recorded at fair value classified in each level at March 31, 2009 (in millions):
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Assets | ||||||||||||||||
Commodity-based derivatives | ||||||||||||||||
Production-related natural gas and oil derivatives | $ | — | $ | 625 | $ | — | $ | 625 | ||||||||
Other natural gas derivatives | — | 82 | 26 | 108 | ||||||||||||
Power-related derivatives | — | — | 53 | 53 | ||||||||||||
Interest rate and foreign currency derivatives | — | 87 | — | 87 | ||||||||||||
Marketable securities invested in non-qualified compensation plans | 19 | — | — | 19 | ||||||||||||
Total assets | 19 | 794 | 79 | 892 | ||||||||||||
Liabilities | ||||||||||||||||
Commodity-based derivatives | ||||||||||||||||
Production-related natural gas and oil derivatives | — | (52 | ) | — | (52 | ) | ||||||||||
Other natural gas derivatives | — | (167 | ) | (158 | ) | (325 | ) | |||||||||
Power-related derivatives | — | — | (445 | ) | (445 | ) | ||||||||||
Interest rate derivatives | — | (18 | ) | — | (18 | ) | ||||||||||
Other | — | — | (56 | ) | (56 | ) | ||||||||||
Total liabilities | — | (237 | ) | (659 | ) | (896 | ) | |||||||||
Total | $ | 19 | $ | 557 | $ | (580 | ) | $ | (4 | ) | ||||||
On certain derivative contracts recorded as assets we are exposed to the risk that our counterparties may not be able to perform or post the required collateral, if any, with us. We have assessed this counterparty risk in light of the collateral our counterparties have posted with us and the current instability in the credit markets. Based on this assessment, we have determined that our exposure is primarily related to our production-related derivatives and foreign currency swaps and is limited to five financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.
The following table presents the changes in our financial assets and liabilities included in Level 3 for the quarter ended March 31, 2009 (in millions):
Change in fair | Change in fair | |||||||||||||||||||
Balance at | value reflected in | value reflected in | ||||||||||||||||||
Beginning of | operating | operating | Settlements, | Balance at End of | ||||||||||||||||
Period | revenues(1) | expenses(2) | net | Period | ||||||||||||||||
Assets | $ | 103 | $ | (21 | ) | $ | — | $ | (3 | ) | $ | 79 | ||||||||
Liabilities | (751 | ) | 62 | (1 | ) | 31 | (659 | ) | ||||||||||||
Total | $ | (648 | ) | $ | 41 | $ | (1 | ) | $ | 28 | $ | (580 | ) | |||||||
(1) | Includes approximately $37 million of net gains that had not been realized through settlements as of March 31, 2009. | |
(2) | Includes approximately $1 million of net losses that had not been realized through settlements as of March 31, 2009. |
13
Table of Contents
7. Price Risk Management Activities
Our price risk management activities relate primarily to derivatives entered into to hedge or otherwise reduce the commodity exposure on our natural gas and oil production and interest rate and foreign currency exposure on our long-term debt. We also hold other derivatives not intended to hedge these exposures, including those related to our legacy trading activities. When we enter into derivative contracts, we may designate the derivative as either a cash flow hedge or a fair value hedge, at which time we prepare the documentation required under SFAS No. 133. Hedges of cash flow exposure are designed to hedge forecasted sales transactions or limit the variability of cash flows to be received or paid related to a recognized asset or liability. Hedges of fair value exposure are entered into to protect the fair value of a recognized asset, liability or firm commitment. A detailed discussion and analysis of our various price risk management activities follows below and in the related tables.
Production-Related Derivatives.We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. Our production-related derivatives do not mitigate all of the commodity price risks of our sales of natural gas and oil production and, as a result, we are subject to commodity price risks on our remaining forecasted natural gas and oil production. Prior to removing the hedging designation on all of our production-related derivatives during the fourth quarter of 2008, certain of these derivatives were designated as cash flow hedges. As of March 31, 2009 and December 31, 2008, we have production-related derivatives on 194 TBtu and 187 TBtu of natural gas and 1,348 MBbl and 3,431 MBbl of oil.
Other Commodity-Based Derivatives.In our Marketing segment, we have long-term natural gas and power derivative contracts that are primarily related to our legacy trading activities, which include forwards, swaps and options that we either intend to manage until their expiration or seek opportunities to liquidate to the extent it is economical and prudent. None of these derivatives are designated as accounting hedges. As of March 31, 2009 and December 31, 2008, our other commodity based derivative contracts include (i) natural gas contracts that obligate us to sell natural gas to power plants and have various expiration dates ranging from 2012 to 2019, with expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to 104,750 MMBtu/d and (ii) derivative power contracts that require us to swap locational differences in power prices between three power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub on approximately 3,700 GWh from 2009 to 2012, 2,400 GWh for 2013 and 1,700 GWh from 2014 to April 2016. Additionally, these contracts require us to provide approximately 1,700 GWh of power per year and approximately 71 GW of installed capacity per year in the PJM power pool through April 2016. For both the natural gas and power contracts discussed above, we have entered into contracts in previous years to economically offset our exposure to price changes on substantially all of these volumes.
Interest Rate and Foreign Currency Derivatives.We have fixed rate U.S. dollar and Euro-denominated debt that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps to protect the value of these debt instruments by converting the fixed amounts of interest due under the debt agreements to variable interest payments and have recorded changes in the fair value of these derivatives in interest expense. Certain of our interest rate derivatives were designated as cash flow hedges or fair value hedges based on whether the interest on the underlying debt was converted to a fixed or floating interest rate. As of March 31, 2009 and December 31, 2008, we have (i) interest rate swaps designated as cash flow hedges that converted the interest rate on approximately $178 million of debt from a LIBOR-based variable rate to a fixed rate of 4.56% and (ii) interest rate swaps designated as fair value hedges that converted the interest rate on approximately $218 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18% and (iii) interest rate swaps not designated as hedges with a notional amount of $222 million for which changes in the fair value of these swaps are substantially eliminated by offsetting swaps.
In addition, we use cross-currency swaps to mitigate a portion of the foreign currency risk related to our Euro-denominated debt, which exposes us to fluctuating foreign currency exchange rates. Our cross-currency swaps are designated as fair value hedges and these swaps converted approximately €330 million of our Euro-denominated debt to $379 million, and converted the interest rate on this debt from a fixed rate to a variable rate of LIBOR plus 4.23% as of March 31, 2009 and December 31, 2008.
14
Table of Contents
Balance Sheet Presentation.Our derivatives are reflected on our balance sheet at their fair value as assets and liabilities from price risk management activities. We net our derivative assets and liabilities for counterparties where we have a legal right of offset and classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. The following table presents the fair value of our derivatives on a gross basis by contract. The derivative asset and liability amounts presented below are summarized by contract type and have not been netted for counterparties where we have a legal right of offset or for cash collateral associated with these derivatives which is not significant to our financial statements.
Fair Value of Asset Derivatives | Fair Value of Liability Derivatives | |||||||||||||||
March 31, 2009 | December 31, 2008 | March 31, 2009 | December 31, 2008 | |||||||||||||
(In millions) | ||||||||||||||||
Derivatives Designated as Hedges: | ||||||||||||||||
Cash flow hedges | ||||||||||||||||
Interest rate derivatives | $ | — | $ | — | $ | (18 | ) | $ | (21 | ) | ||||||
Fair value hedges | ||||||||||||||||
Interest rate derivatives | 11 | 12 | — | — | ||||||||||||
Cross-currency derivatives | 76 | 94 | — | — | ||||||||||||
Total derivatives designated as hedges | 87 | 106 | (18 | ) | (21 | ) | ||||||||||
Derivatives not Designated as Hedges: | ||||||||||||||||
Commodity-based derivatives | ||||||||||||||||
Production-related | 643 | 738 | (70 | ) | (56 | ) | ||||||||||
Other natural gas | 667 | 853 | (884 | ) | (1,122 | ) | ||||||||||
Power-related | 80 | 111 | (472 | ) | (549 | ) | ||||||||||
Total commodity-based derivatives | 1,390 | 1,702 | (1,426 | ) | (1,727 | ) | ||||||||||
Interest rate derivatives | 12 | 12 | (12 | ) | (12 | ) | ||||||||||
Total derivatives not designated as hedges | 1,402 | 1,714 | (1,438 | ) | (1,739 | ) | ||||||||||
Impact of master netting arrangements(1) | (616 | ) | (743 | ) | 616 | 743 | ||||||||||
Total assets (liabilities) from price risk management activities | 873 | 1,077 | (840 | ) | (1,017 | ) | ||||||||||
Other derivatives(2) | — | — | (56 | ) | (55 | ) | ||||||||||
Total derivatives | $ | 873 | $ | 1,077 | $ | (896 | ) | $ | (1,072 | ) | ||||||
(1) | Includes adjustments to net assets or liabilities to reflect master netting arrangements we have with our counterparties. | |
(2) | Included in other current and noncurrent liabilities in our balance sheets. |
15
Table of Contents
Statements of Income, Comprehensive Income and Cash Flow Presentation.Derivatives that we have designated as accounting hedges impact our revenues or expenses based on the nature and timing of the transactions that they hedge. Changes in derivative fair values that are designated as cash flow hedges are deferred in accumulated other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur. Ineffectiveness related to our cash flow hedges is recognized in earnings as it occurs. Changes in the fair value of derivatives that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of the related hedged assets, liabilities or firm commitments.
Derivatives that we have not designated as accounting hedges are marked-to-market each period and changes in their fair value are generally reflected as operating revenues, except as indicated in the table below. In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows (other than those derivatives intended to hedge the principal amounts of our foreign currency denominated debt, which are recorded in financing activities). Listed below are the impacts to our income statement and statement of comprehensive income for the quarter ended March 31, 2009 (in millions):
Operating | Interest | Other | Other Comprehensive | |||||||||||||
Revenues | Expense | Income | Income (Loss) | |||||||||||||
Commodity-based derivatives | ||||||||||||||||
Production-related derivatives(1) | $ | 394 | $ | — | $ | — | $ | (128 | ) | |||||||
Other natural gas and power derivatives not designated as hedges | 55 | — | — | — | ||||||||||||
Total commodity-based derivatives | 449 | — | — | (128 | ) | |||||||||||
Interest rate derivatives(2) | ||||||||||||||||
Designated as cash flow hedges(3) | — | 1 | — | 3 | ||||||||||||
Designated as fair value hedges(4) | — | 1 | — | — | ||||||||||||
Cross-currency derivatives designated as fair value hedges(4) | — | 2 | (24 | ) | — | |||||||||||
Total interest rate and foreign currency derivatives | — | 4 | (24 | ) | 3 | |||||||||||
Total price risk management activities(5) | $ | 449 | $ | 4 | $ | (24 | ) | $ | (125 | ) | ||||||
(1) | Included in operating revenues in 2009 is $128 million representing the amount of accumulated other comprehensive income that was reclassified into income related to commodity-based derivatives for which we removed the hedging designation during the fourth quarter of 2008. We anticipate that approximately $275 million of our accumulated other comprehensive income will be reclassified to operating revenues during the next twelve months. | |
(2) | We have not reflected in this table approximately $2 million of losses recognized for the quarter ended March 31, 2009 related to interest rate derivatives not designated as hedges that were offset completely by the impact of certain swaps. Settlements related to these swaps were not material for the quarter ended March 31, 2009. | |
(3) | Included in these amounts is less than $1 million representing the amount of accumulated other comprehensive income that was reclassified into income related to these hedges. We anticipate that less than $2 million of our accumulated other comprehensive income will be reclassified to interest expense during the next twelve months. No ineffectiveness was recognized on our interest rate cash flow hedges for the quarter ended March 31, 2009. | |
(4) | Amounts only reflect the financial statement impact of these derivative contracts. The table does not reflect the offsetting impact of changes to the carrying value of the underlying debt hedged by these derivative instruments as a result of changes in fair value attributable to the risk being hedged, which is also recorded in other income and interest expense and substantially offsets the financial statement impact of these derivatives. We also recorded a decrease to interest expense of approximately $1 million during the quarter ended March 31, 2009 as a result of converting the interest rate on the underlying debt from a fixed rate to a floating rate. No ineffectiveness was recognized on our fair value hedges for the quarter ended March 31, 2009. | |
(5) | We also had approximately $1 million of losses for the quarter ended March 31, 2009 recognized in operating expenses related to other derivative instruments not associated with our price risk management activities. |
16
Table of Contents
8. Debt, Other Financing Obligations and Other Credit Facilities
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Short-term financing obligations, including current maturities | $ | 961 | $ | 1,090 | ||||
Long-term financing obligations | 13,541 | 12,818 | ||||||
Total | $ | 14,502 | $ | 13,908 | ||||
Changes in Long-Term Financing Obligations.During the quarter ended March 31, 2009, we had the following changes in our long-term financing obligations (in millions):
Cash | ||||||||||||
Book Value | Received / | |||||||||||
Company | Interest Rate | Increase (Decrease) | (Paid) | |||||||||
Issuances | ||||||||||||
El Paso Notes due 2016(1) | 8.25 | % | $ | 478 | $ | 473 | ||||||
Tennessee Gas Pipeline (TGP) notes due 2016(1) | 8.00 | % | 237 | 235 | ||||||||
Southern LNG notes due 2014 and 2016 | 9.60 | % | 135 | 134 | ||||||||
Increases through March 31, 2009 | $ | 850 | $ | 842 | ||||||||
Repayments, repurchases, and other | ||||||||||||
El Paso Corporation | ||||||||||||
Notes due 2009 | 6.375 | % | $ | (112 | ) | $ | (112 | ) | ||||
Revolving credit facilities | variable | (97 | ) | (97 | ) | |||||||
El Paso Pipeline Partners, L.P. (EPB) revolving credit facilities | variable | (10 | ) | (10 | ) | |||||||
El Paso Exploration and Production Company (EPEP) revolving credit facility | variable | (20 | ) | (20 | ) | |||||||
Other | variable | (17 | ) | (5 | ) | |||||||
Decreases through March 31, 2009 | $ | (256 | ) | $ | (244 | ) | ||||||
(1) | Principal amount of the notes is $500 million for El Paso Corporation and $250 million for TGP. |
Credit Facilities.As of March 31, 2009, we had total available capacity under various credit agreements (not including capacity available under the EPB $750 million revolving credit facility) of approximately $1.5 billion. In determining our available capacity, we have assessed our lender’s ability to fund under our various credit facilities, as further discussed in our 2008 Annual Report on Form 10-K.
In November 2008, we entered into an unsecured credit facility for which we were required to pay fixed facility fees at an annual rate of 7.91% on the total committed amount of the facility. As of March 31, 2009, we had capacity under this facility of $100 million. In April 2009, we entered into an additional $50 million 5-year letter of credit facility with a fixed facility fee of 5.95% maturing June 2014. We currently have a total letter of credit capacity under this program of $150 million with an average fixed facility fee of 7.26% and maturities ranging from December 2013 to June 2014.
The availability of borrowings under our $1.5 billion revolving credit agreement and our ability to incur additional debt is subject to various financial and non-financial covenants and restrictions. There have been no significant changes to our restrictive covenants from those disclosed in our 2008 Annual Report on Form 10-K.
Letters of Credit.We enter into letters of credit in the ordinary course of our operating activities as well as periodically in conjunction with the sales of assets or businesses. As of March 31, 2009, we had outstanding letters of credit issued under all of our facilities of approximately $1.6 billion. Included in this amount is approximately $0.8 billion of letters of credit securing our recorded obligations related to price risk management activities.
17
Table of Contents
9. Commitments and Contingencies
Legal Proceedings
ERISA Class Action Suit.In December 2002, a purported class action lawsuit entitledWilliam H. Lewis, III v. El Paso Corporation, et al.was filed in the U.S. District Court for the Southern District of Texas alleging that our communication with participants in our Retirement Savings Plan included various misrepresentations and omissions that caused members of the class to hold and maintain investments in El Paso stock in violation of the Employee Retirement Income Security Act (ERISA). We have insurance coverage for this lawsuit, subject to certain deductibles and co-pay obligations. We executed agreements to settle this matter and the court has approved the settlement. We have established accruals for this matter which we believe are adequate.
Cash Balance Plan Lawsuit.In December 2004, a purported class action lawsuit entitledTomlinson, et al. v. El Paso Corporation and El Paso Corporation Pension Planwas filed in U.S. District Court for Denver, Colorado. The lawsuit alleges various violations of ERISA and the Age Discrimination in Employment Act as a result of our change from a final average earnings formula pension plan to a cash balance pension plan. The trial court has dismissed the Plaintiffs’ claims. The Plaintiffs have filed a motion seeking to overturn the dismissal of the case. Our costs and legal exposure related to this lawsuit are not currently determinable.
Retiree Medical Benefits Matters.In 2002, a lawsuit entitledYolton et al. v. El Paso Tennessee Pipeline Co. and Case Corporationwas filed in a federal court in Detroit, Michigan.The lawsuit was filed on behalf of a group of retirees of Case Corporation (Case) that alleged they are entitled to retiree medical benefits under a medical benefits plan for which we serve as plan administrator pursuant to a merger agreement with Tenneco Inc. Although we had asserted that our obligations under the plan were subject to a cap pursuant to an agreement with the union for Case employees, in the first quarter of 2008, the trial court granted a summary judgment and ruled that the benefits were vested and not subject to the cap. As a result, we were obligated to pay the amounts above the cap and we adjusted our existing indemnification accrual using current actuarial assumptions and reclassified our liability as a postretirement benefit obligation. See Note 10 for a discussion of the impact of this matter. We intend to pursue appellate options following the determination by the trial court of any damages incurred by the plaintiffs during the period when premium payments above the cap were paid by the retirees. We believe our accruals established for this matter are adequate.
Price Reporting Litigation.Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. The first set of cases, involving similar allegations on behalf of commercial and residential customers, was transferred to a multi-district litigation proceeding (MDL) in the U.S. District Court for Nevada and styledIn re: Western States Wholesale Natural Gas Antitrust Litigation. These cases were dismissed. The U.S. Court of Appeals for the Ninth Circuit, however, reversed the dismissal and ordered that these cases be remanded to the trial court. The second set of cases also involve similar allegations on behalf of certain purchasers of natural gas. These includeFarmland Industries v. Oneok Inc., et al.(filed in state court in Wyandotte County, Kansas in July 2005) andMissouri Public Service Commission v. El Paso Corporation, et al. (filed in the circuit court of Jackson County, Missouri at Kansas City in October 2006), and the purported class action lawsuits styled:Leggett, et al. v. Duke Energy Corporation, et al.(filed in Chancery Court of Tennessee in January 2005);Ever-Bloom Inc., et al. v. AEP Energy Services Inc., et al.(filed in federal court for the Eastern District of California in September 2005);Learjet, Inc., et al. v. Oneok Inc., et al.(filed in state court in Wyandotte County, Kansas in September 2005);Breckenridge, et al. v. Oneok Inc., et al.(filed in state court in Denver County, Colorado in May 2006);Arandell, et al. v. Xcel Energy, et al.(filed in the circuit court of Dane County, Wisconsin in December 2006);Heartland, et al. v. Oneok Inc., et al.(filed in the circuit court of Buchanan County, Missouri in March 2007); andNewpage Wisconsin System, Inc., et al. (filed in the circuit court of Wood County, Wisconsin in March 2009). TheLeggettcase was dismissed by the Tennessee state court, but in October 2008, the Tennessee Court of Appeals reversed the dismissal, remanding the matter to the trial court. The decision has been appealed to the Tennessee Supreme Court. TheMissouri Public Servicecase was transferred to the MDL, but remanded back to state court, where a motion to dismiss has been granted. The dismissal has been appealed.Newpagewas recently filed. The remaining cases have all been transferred to the MDL proceeding. TheBreckenridge Casehas been dismissed as to El Paso and other Defendants, and a motion for reconsideration of this decision was denied. This ruling can still be appealed. Discovery is proceeding in the MDL cases. We reached an agreement in principle to settle theWestern StatesandEver-Bloomcases and have established accruals for those cases which we believe are adequate. Settlement documents have been executed, but court approval is still required. Our costs and legal exposure related to the remaining lawsuits and claims are not currently determinable.
18
Table of Contents
Gas Measurement Cases.A number of our subsidiaries were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation,U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. In March 2009, the Tenth Circuit Court of Appeals affirmed the dismissals.
Similar allegations were filed in a set of actions initiated in 1999 inWill Price, et al. v. Gas Pipelines and Their Predecessors, et al.,in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiff seeks an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
MTBE. Certain of our subsidiaries used, produced, sold or distributed methyl tertiary-butyl ether (MTBE) as a gasoline additive. Various lawsuits were filed throughout the U.S. regarding the potential impact of MTBE on water supplies. The lawsuits have been brought by different parties, including state attorney generals, water districts and individual water companies. They have sought different remedies, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. We settled 59 of these lawsuits, with our payments being made in October 2008. These payments were covered by insurance and all of the payments have been funded by our insurers. Following such settlements, there are 30 lawsuits that remain. Although there have been settlement discussions with other plaintiffs, such discussions have been unsuccessful to date. While the damages claimed in the remaining actions are substantial, there remains significant legal uncertainty regarding the validity of the causes of action asserted and the availability of the relief sought. We have or will tender these remaining cases to our insurers. It is likely that our insurers will assert denial of coverage on the nine most-recently filed cases. Our costs and legal exposure related to these remaining lawsuits are not currently determinable.
In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings and claims that arise in the ordinary course of our business. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of March 31, 2009, we had approximately $81 million accrued, which has not been reduced by $14 million of related insurance receivables, for our outstanding legal and governmental proceedings.
19
Table of Contents
Rates and Regulatory Matters
EPNG Rate Case.In June 2008, El Paso Natural Gas Company (EPNG) filed a rate case with the Federal Energy Regulatory Commission (FERC) as required under the settlement of its previous rate case. The filing proposed an increase in EPNG’s base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of EPNG’s proposals in the technical conference proceeding. The FERC appointed an administrative law judge who will decide the remaining issues should EPNG be unable to reach a settlement with its customers in upcoming negotiations.
SNG Rate Case.In March 2009, Southern Natural Gas Company (SNG) filed a rate case with the FERC as permitted under the settlement of its previous rate case. The filing proposed an increase in SNG’s base tariff rates. In April 2009, the FERC issued an order accepting the proposed rates effective September 1, 2009, subject to refund and the outcome of a hearing and a technical conference on certain tariff proposals. The FERC appointed an administrative law judge who will decide the rate case issues should SNG be unable to reach a settlement with its customers.
Notice of Proposed Rulemaking.On October 3, 2007, the Minerals Management Service (MMS) issued a Notice of Proposed Rulemaking for Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS) — Pipelines and Pipeline Rights-of-Way. If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of: (1) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights-of-way in the OCS; and (3) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.
Other Matter
Navajo Nation. Approximately 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on lands held in trust by the United States for the benefit of the Navajo Nation. Our rights-of-way on lands crossing the Navajo Nation are the subject of a pending renewal application filed in 2005 with the Department of the Interior’s Bureau of Indian Affairs. In March 2009, representatives of the Navajo Nation and EPNG executed an agreement setting forth the terms and conditions of the Nation’s consent to EPNG’s rights-of-way. Under this agreement, we will make annual payments of approximately $18 million for our rights-of-way beginning in 2009 and continuing through 2025, subject to annual adjustments. EPNG submitted the Navajo Nation’s consent agreement in support of EPNG’s pending application to the United States Department of the Interior (the Department) for an extension of the Department’s current right-of-way grant. We expect that the submission of the consent agreement will result in the Department’s final processing of our application. EPNG has filed with the FERC for recovery of these amounts in its recent rate case.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At March 31, 2009, we had accrued approximately $201 million for environmental matters, which has not been reduced by $24 million for amounts to be paid directly under government sponsored programs or through settlement arrangements. Our accrual includes approximately $195 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $6 million for related environmental legal costs. Of the $201 million accrual, $17 million was reserved for facilities we currently operate and $184 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.
20
Table of Contents
Our estimates of potential liability range from approximately $201 million to approximately $383 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($12 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($189 million to $371 million) and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:
March 31, 2009 | ||||||||
Sites | Expected | High | ||||||
(In millions) | ||||||||
Operating | $ | 17 | $ | 23 | ||||
Non-operating | 165 | 318 | ||||||
Superfund | 19 | 42 | ||||||
Total | $ | 201 | $ | 383 | ||||
Below is a reconciliation of our accrued liability from January 1, 2009 to March 31, 2009 (in millions):
Balance as of January 1, 2009 | $ | 204 | ||
Additions/adjustments for remediation activities | 6 | |||
Payments for remediation activities | (9 | ) | ||
Balance as of March 31, 2009 | $ | 201 | ||
For the remainder of 2009, we estimate that our total remediation expenditures will be approximately $59 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $9 million in the aggregate for the years 2009 through 2013. These expenditures primarily relate to compliance with clean air regulations.
CERCLA Matters.As part of our environmental remediation projects, we have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to 30 active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements, which provide for payment of our allocable share of remediation costs. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these issues are included in the previously indicated estimates for Superfund sites.
21
Table of Contents
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Greenhouse Gas (GHG) Emissions.Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. These measures include the Kyoto Protocol, which has been ratified by some of the international countries in which we have operations such as Mexico, Brazil, and Egypt. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the United States Environmental Protection Agency (EPA) is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Furthermore, the EPA recently issued proposed regulations requiring monitoring and reporting of GHG emissions on an annual basis economy wide, including extensive new monitoring and reporting requirements applicable to our industry. The EPA has also recently proposed findings that GHGs in the atmosphere endanger public health and welfare and that emissions from mobile sources cause or contribute to GHGs in the atmosphere. These proposed findings, if finalized as proposed, would not immediately affect our operations, but standards eventually promulgated pursuant to these findings could affect our operations and ability to obtain air permits for new or modified facilities. Legislation and regulation are also in various stages of discussion or implementation in many of the states in which we operate. These measures include recommendations released by the Western Climate Initiative regarding a cap-and-trade program and targeted emission reductions in several states in which we operate in the western United States. In California, recently enacted legislation and proposed rules would impose GHG emission reduction targets on our operations there. Meanwhile, lawsuits have been filed seeking to force the federal government to regulate GHG emissions under the Clean Air Act and to require individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.
Guarantees and Other Contractual Commitments
Guarantees and Indemnifications.We are involved in various joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
Our potential exposure under guarantee and indemnification agreements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $811 million, which primarily relates to indemnification arrangements associated with the sale of ANR Pipeline Company in 2007, our Macae power facility in Brazil, and other legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 8. Included in the above maximum stated value are certain indemnification agreements that have expired; however, claims were made prior to the expiration of the related claim periods. We are unable to estimate a maximum exposure of our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
22
Table of Contents
As of March 31, 2009, we have recorded obligations of $78 million related to our indemnification arrangements. Our liability consists primarily of an indemnification that one of our subsidiaries provided related to its sale of an ammonia facility that is reflected in our financial statements at its estimated fair value. We have provided a partial parental guarantee of our subsidiary’s obligations under this indemnification. We believe that our guarantee and indemnification agreements for which we have not recorded a liability are not probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, among other considerations.
Commitments, Purchase Obligations and Other Matters.On April 13, 2009, TGP filed an amendment to a 1995 FERC settlement that, if approved by the FERC, would provide for interim refunds to its customers of approximately $157 million of amounts collected related to certain environmental costs. These refunds are recorded as other liabilities on our balance sheet and are expected to be paid over a three year period with interest commencing the later of July 1, 2009 or within 20 days of the FERC’s approval.
10. Retirement Benefits
Net Benefit Cost (Income).The components of net benefit cost (income) for our pension and postretirement benefit plans for the quarters ended March 31, are as follows:
Other | ||||||||||||||||
Pension | Postretirement | |||||||||||||||
Benefits | Benefits | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
(In millions) | ||||||||||||||||
Service cost | $ | 4 | $ | 4 | $ | — | $ | — | ||||||||
Interest cost | 30 | 30 | 9 | 7 | ||||||||||||
Expected return on plan assets | (43 | ) | (47 | ) | (3 | ) | (4 | ) | ||||||||
Amortization of net actuarial loss (gain) | 11 | 6 | — | (1 | ) | |||||||||||
Amortization of prior service credit(1) | — | (1 | ) | — | — | |||||||||||
Net benefit cost (income) | $ | 2 | $ | (8 | ) | $ | 6 | $ | 2 | |||||||
(1) | As permitted, the amortization of any prior service credit is determined using a straight-line amortization of the credit over the average remaining service period of employees expected to receive benefits under the plan, or in the case of retired participants, over the average remaining life. |
Other Matter.In various court rulings prior to March 2008, we were required to indemnify Case for certain benefits paid to a closed group of Case retirees as further discussed in Note 9. In conjunction with those rulings, we recorded a liability for estimated amounts due under the indemnification using actuarial methods similar to those used in estimating our postretirement benefit plan obligations. This liability, however, was not included in our postretirement benefit obligations or disclosures prior to March 2008.
In March 2008, we received a summary judgment from the trial court on this matter, and thus became the primary party that is obligated to pay these benefit payments. As a result of the judgment, we adjusted our obligation using current actuarial assumptions and recorded a $65 million reduction to operation and maintenance expense. We also reclassified this obligation from an indemnification liability to a postretirement benefit obligation.
23
Table of Contents
11. Equity
Common and Preferred Stock Dividends.The table below shows the amount of dividends paid and declared (dollars in millions, except per share amount):
Common Stock | Convertible Preferred Stock | |||||||
($0.05/Share) | (4.99%/Year) | |||||||
Amount paid through March 31, 2009 | $ | 35 | $ | 9 | ||||
Amount paid in April 2009 | $ | 34 | $ | 9 | ||||
Declared in May 2009: | ||||||||
Date of declaration | May 6, 2009 | May 6, 2009 | ||||||
Payable to shareholders on record | June 5, 2009 | June 15, 2009 | ||||||
Date payable | July 1, 2009 | July 1, 2009 |
Dividends on our common stock and preferred stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. For the remainder of 2009, we expect dividends paid on our common and preferred stock will be taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes.
The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock provide for the conversion ratio on our preferred stock to increase when we pay quarterly dividends to our common shareholders in excess of $0.04 per share, as we did in January 2009. The terms of these preferred shares also prohibit the payment of dividends on our common stock unless we have paid or set aside for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restriction on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If we are unable to comply with our fixed charge coverage ratio, our ability to pay additional dividends would be restricted.
Noncontrolling Interests.In November 2007, we issued common units in our subsidiary (EPB), a master limited partnership, and recorded noncontrolling interests in our balance sheet of $537 million. During the quarters ended March 31, 2009 and 2008, EPB made cash distributions of $10 million and $4 million to its non-affiliated common unitholders.
12. Business Segment Information
As of March 31, 2009, our business consists of two core segments, Pipelines and Exploration and Production. We also have Marketing and Power segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses and various other contracts and assets, all of which are immaterial. A further discussion of each segment follows.
Pipelines.Provides natural gas transmission, storage, and related services, primarily in the United States. As of March 31, 2009, we conducted our activities primarily through seven wholly or majority owned interstate pipeline systems and equity interests in four transmission systems. We also own or have interests in two underground natural gas storage facilities, and two LNG terminalling facilities, one of which is under construction.
Exploration and Production.Engaged in the exploration for and the acquisition, development and production of natural gas, oil and NGL, in the United States, Brazil and Egypt.
Marketing.Markets and manages the price risks associated with our natural gas and oil production as well as manages our remaining legacy trading portfolio.
Power.Manages the risks associated with our remaining international power and pipeline assets and investments located primarily in South America and Asia. We continue to pursue the sale of these assets.
24
Table of Contents
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business segments which consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate more effectively the operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for items such as (i) interest and debt expense (ii) income taxes and (iii) net income attributable to noncontrolling interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT to our net income (loss) for the periods ended March 31:
2009 | 2008 | |||||||
(In millions) | ||||||||
Segment EBIT | $ | (1,233 | ) | $ | 561 | |||
Corporate and other | (7 | ) | 39 | |||||
Interest and debt expense | (255 | ) | (233 | ) | ||||
Income taxes | 526 | (148 | ) | |||||
Net income (loss) attributable to El Paso Corporation | (969 | ) | 219 | |||||
Net income attributable to noncontrolling interests | 12 | 9 | ||||||
Net income (loss) | $ | (957 | ) | $ | 228 | |||
The following table reflects our segment results for the quarters ended March 31:
Segments | ||||||||||||||||||||||||
Exploration | ||||||||||||||||||||||||
and | Corporate | |||||||||||||||||||||||
Pipelines | Production | Marketing | Power | and Other(1) | Total | |||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||
Revenue from external customers | $ | 721 | $ | 574 | (2) | $ | 188 | $ | — | $ | 1 | $ | 1,484 | |||||||||||
Intersegment revenue | 12 | 126 | (2) | (135 | ) | — | (3 | ) | — | |||||||||||||||
Operation and maintenance | 183 | 109 | 1 | 2 | 5 | 300 | ||||||||||||||||||
Ceiling test charges | — | 2,068 | — | — | — | 2,068 | ||||||||||||||||||
Depreciation, depletion and amortization | 104 | 150 | — | — | 2 | 256 | ||||||||||||||||||
Earnings (losses) from unconsolidated affiliates | 21 | (9 | ) | — | 6 | 1 | 19 | |||||||||||||||||
EBIT | 396 | (1,685 | ) | 52 | 4 | (7 | ) | (1,240 | ) | |||||||||||||||
2008 | ||||||||||||||||||||||||
Revenue from external customers | $ | 707 | $ | 83 | (2) | $ | 469 | $ | — | $ | 10 | $ | 1,269 | |||||||||||
Intersegment revenue | 13 | 520 | (2) | (526 | ) | — | (7 | ) | — | |||||||||||||||
Operation and maintenance | 195 | 108 | 2 | 5 | (39 | ) | 271 | |||||||||||||||||
Depreciation, depletion and amortization | 99 | 212 | — | — | 2 | 313 | ||||||||||||||||||
Earnings from unconsolidated affiliates | 21 | 10 | — | 5 | 1 | 37 | ||||||||||||||||||
EBIT | 381 | 242 | (60 | ) | (2 | ) | 39 | 600 |
(1) | Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. During the quarters ended March 31, 2009 and 2008, we recorded an intersegment revenue elimination of $3 million and $6 million in the “Corporate and Other” column to remove intersegment transactions. | |
(2) | Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties. |
25
Table of Contents
Total assets by segment are presented below:
March 31, | December 31, | |||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Pipelines | $ | 15,504 | $ | 15,121 | ||||
Exploration and Production | 4,070 | 6,142 | ||||||
Marketing | 303 | 465 | ||||||
Power | 313 | 417 | ||||||
Total segment assets | 20,190 | 22,145 | ||||||
Corporate and Other | 2,234 | 1,523 | ||||||
Total consolidated assets | $ | 22,424 | $ | 23,668 | ||||
13. Investments in, Earnings from and Transactions with Unconsolidated Affiliates
We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. The earnings from unconsolidated affiliates reflected in our income statement include (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) any impairments and other adjustments recorded by us. The information below related to our unconsolidated affiliates includes (i) our net investment and earnings (losses) we recorded from these investments, (ii) summarized financial information of our proportionate share of these investments, and (iii) revenues and charges with our unconsolidated affiliates.
Earnings (Losses) from | ||||||||||||||||
Investment | Unconsolidated Affiliates | |||||||||||||||
March 31, | December 31, | Quarter Ended March 31, | ||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||
(In millions) | (In millions) | |||||||||||||||
Net Investment and Earnings (Losses) | ||||||||||||||||
Four Star(1) | $ | 512 | $ | 525 | $ | (10 | ) | $ | 10 | |||||||
Citrus | 578 | 564 | 14 | 13 | ||||||||||||
Gulf LNG(2) | 278 | 279 | — | — | ||||||||||||
Gasoductos de Chihuahua | 180 | 174 | 6 | 7 | ||||||||||||
Porto Velho(3) | — | (64 | ) | — | — | |||||||||||
Bolivia-to-Brazil Pipeline | 113 | 119 | 4 | 3 | ||||||||||||
Argentina to Chile Pipeline | 29 | 27 | 2 | 1 | ||||||||||||
Other | 74 | 79 | 3 | 3 | ||||||||||||
Total | $ | 1,764 | $ | 1,703 | $ | 19 | $ | 37 | ||||||||
(1) | Amortization of our purchase cost in excess of the underlying net assets of Four Star was $12 million and $14 million for the quarters ended March 31, 2009 and 2008. | |
(2) | In February 2008, we acquired a 50 percent interest in Gulf LNG. See Note 2. | |
(3) | As of December 31, 2008, we had outstanding advances and receivables of $242 million, not included above, related to our investment in Porto Velho. In February 2009, we completed the sale of our investment in and receivables from Porto Velho as further discussed inOther Investment-Related Mattersbelow. |
Quarter Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Summarized Financial Information | ||||||||
Operating results data: | ||||||||
Operating revenues | $ | 123 | $ | 186 | ||||
Operating expenses | 68 | 93 | ||||||
Income from continuing operations and net income | 35 | 56 |
We received distributions and dividends from our unconsolidated affiliates of $12 million and $60 million for the quarters ended March 31, 2009 and 2008. Included in these amounts for the quarter ended March 31, 2009 and 2008 are returns of capital of approximately $1 million and less than $1 million. Our revenues and charges with unconsolidated affiliates were not material during the quarters ended March 31, 2009 and 2008.
26
Table of Contents
Accounts Receivable Sales Program.Several of our pipeline subsidiaries have agreements to sell certain accounts receivable to qualifying special purpose entities (QSPEs) under SFAS No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. The QSPEs purpose is solely to invest in our pipeline receivables which are short-term assets that generally settle within 60 days.As of March 31, 2009 and December 31, 2008, we sold approximately $159 million and $174 million of receivables, received cash of approximately $79 million and $82 million, and received subordinated beneficial interests of approximately $80 million and $89 million. The QSPEs also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $79 million and $85 million as of March 31, 2009 and December 31, 2008. We recognized a loss of less than $1 million related to our transactions with these QSPEs during the quarters ended March 31, 2009 and 2008. We reflect the subordinated beneficial interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliates in our balance sheet. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectibility of the underlying receivables sold to the QSPEs. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPEs which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the periods ended March 31, 2009 and 2008.
Other Investment-Related Matters
Porto Velho.In February 2009, we completed the sale of our interests in Porto Velho to our partner in the project for $101 million of cash and $78 million of notes receivable from the buyer that have an 8.25% annual interest rate and mature in 2013.
Manaus/Rio Negro.In 2008, we transferred our ownership in the Manaus and Rio Negro facilities to the plants’ power purchaser as required by their power purchase agreements. As of March 31, 2009, we have approximately $50 million of Brazilian reais-denominated accounts receivable owed to us under the projects’ terminated power purchase agreements, which are guaranteed by the purchaser’s parent. The purchaser has withheld payment of these receivables in light of their Brazilian reais-denominated claims of approximately $48 million related to plant maintenance the purchaser claims should have been performed at the plants prior to the transfer, inventory levels and other items. We have been in discussions with the purchaser and have initiated regulatory proceedings to allow us to settle these outstanding claims and recover our accounts receivable. We may also initiate legal action against the purchaser’s parent to collect our receivables, under its guarantee to the projects. We have reviewed our obligations under the power purchase agreement in relation to the claims and have accrued an obligation for the uncontested claims. We believe the remaining contested claims are without merit. The ultimate resolution of each of these matters is unknown at this time, and adverse developments related to either our ability to collect amounts due to us or related to the dispute could require us to record additional losses in the future.
During 2009, the Brazilian taxing authorities began legal proceedings against the Manaus and Rio Negro projects for $47 million of ICMS taxes allegedly due on capacity payments received from the plants’ power purchaser from 1999 to 2001. By agreement, the power purchaser must indemnify the Manaus and Rio Negro projects for these ICMS taxes, along with related interest and penalties, and is therefore defending the projects against this lawsuit. In order to stay the taxing authorities’ collection efforts related to this matter and secure this potential liability, the power purchaser offered to pledge certain of its assets; however, this pledge was rejected by the Brazilian courts. We have called on the power purchaser’s parent to provide security satisfactory to the courts under its parental guarantee to us. We anticipate that if we reach an agreement on the matters described above (other than those related to ICMS taxes), the power purchaser will reaffirm its responsibility for any amounts related to this ICMS tax matter.
27
Table of Contents
Investment in Bolivia and Argentina.We own an 8 percent interest in the Bolivia-to-Brazil pipeline and a 22 percent interest in the Argentina-to-Chile pipeline. As of March 31, 2009, our total investment and guarantees related to these pipeline projects was approximately $164 million. Discussions with a group of our partners regarding the sale of our interest in the Argentina-to-Chile pipeline to them have continued to progress and we expect to complete the sale in mid-2009. We continue to monitor and evaluate the potential impact that regional and political events in Bolivia and Argentina could have on our investments in these pipeline projects, as further discussed in our 2008 Annual Report on Form 10-K. As new information becomes available or future material developments arise, we may be required to record an impairment of our investments.
28
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our 2008 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.
Overview and Outlook
During the quarter ended March 31, 2009, our pipeline operations continued to provide a strong base of earnings and operating cash flow. In our pipeline business, approximately three-fourths of the revenues are collected in the form of demand or reservation charges which are not dependent upon commodity prices or throughput levels. We remain focused on implementing the nearly $8 billion backlog of committed pipeline growth projects, with several of those projects expected to commence service in 2009.
In our exploration and production business, we continued to generate significant positive operating cash flow during the quarter despite a low commodity price environment, principally as a result of derivatives we have in place related to our 2009 production. As of March 31, 2009, we had 120 TBtu of natural gas hedges with an average floor price of $9.02 per MMBtu and an average ceiling price of $14.35 per MMBtu and 1,348 MBbls of crude oil swaps at $45 per barrel on our remaining anticipated 2009 production. However, lower natural gas prices at the end of the first quarter of 2009 resulted in approximately $2.1 billion of non-cash ceiling test charges, primarily in our domestic full cost pool, which significantly impacted our overall first quarter 2009 results. The ceiling test charges did not consider the value of our financial derivative contracts which was $573 million as of March 31, 2009. If commodity prices decrease further and we do not experience anticipated further reductions in oilfield service costs, we may be required to record additional non-cash ceiling test charges in the future.
In both of our core businesses, we have implemented various cost saving measures to reduce our capital, operating, and general and administrative costs. These measures include reducing drilling activity in our exploration and production business until we experience further expected reductions in oilfield service costs, realizing cost reductions in our capital and maintenance programs by renegotiating contracts with contractors, suppliers and service providers, and deferring and eliminating various discretionary costs.
The volatility in the financial markets, the energy industry and the global economy is expected to continue for the remainder of 2009 and possibly beyond. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital, and may require us to further adjust our current financing and business plans. Additionally, commodity prices for natural gas and oil have been and are expected to remain volatile, and although we have attempted to mitigate the effects of these reductions in commodity prices by entering into derivative contracts on our natural gas and oil production, we still have a portion of our production subject to the current lower commodity price environment as further described below. Finally, while the impacts are difficult to quantify, a continued downward trend in the global economy could have adverse impacts on natural gas consumption and demand over time. All of these factors may impact our outlook for the remainder of 2009 and beyond.
As of March 31, 2009, we had approximately $3.3 billion of available liquidity (seeLiquidity and Capital Resources)and have designed our 2009 plans to address the impacts of current volatility in the global financial markets. Based on our activities to date, we do not anticipate a need to further access the capital markets to meet our 2009 debt maturities or fund our 2009 capital program, regardless of whether we are successful in obtaining equity partners on any of our capital projects. When prudent, however, we will continue to be opportunistic in building liquidity to meet our long-term capital needs. There are no assurances, however, that we will be able to access the financial markets to fund our long-term capital needs. Our 2009 plans are also designed to retain our long-term growth potential, including our committed pipeline project backlog and our core domestic and international drilling programs, as well as our natural gas and oil resource positions. In light of the current volatility of the financial markets, the energy industry and the global economy, it is possible additional adjustments to our plan and outlook will be required which could impact our financial and operating performance.
29
Table of Contents
Currently, these plans include:
• | Capital Expenditures.Planned 2009 capital expenditures between approximately $2.7 billion to $3.0 billion, with $1.7 billion of capital being spent in our pipeline business and $0.9 billion to $1.2 billion in our exploration and production business. Our $1.7 billion of planned pipeline capital reflects equity partnering on one or more of our expansion projects. In our exploration and production business, although it will also impact our near-term growth profile in this business, the objective of reductions in our capital program is to retain substantially all of our existing natural gas and oil resource positions for future exploration and production when commodity prices and oilfield service costs return to more favorable levels. | ||
• | Asset Sales.We have sold or are evaluating the sale of several non-core assets generating cash proceeds of approximately $0.4 billion in 2009, of which approximately $0.2 billion have already been completed. | ||
• | Other Liquidity Sources.We will continue to be opportunistic in generating additional liquidity, which may include additional asset sales or partnering opportunities on expansion projects. To the extent these opportunities are delayed or cannot be completed, there is a further decline in commodity prices or we experience other major disruptions in the financial markets, we could also pursue other alternatives, including additional reductions in our discretionary capital program, further reductions in operating and general and administrative expenses, additional secured financing arrangements, seeking additional partners for one or more of our other growth projects or selling additional non-core assets. |
Our plans were determined based on a number of factors, the most significant of which are described below and in further detail in our 2008 Annual Report on Form 10-K:
• | Debt Capital Structure.Our debt capital structure is 82 percent fixed interest rates and 18 percent floating interest rates. Accordingly, we believe we have lessened exposure to market changes in interest rates on our existing debt which impact our interest costs. | ||
• | Revenue and Price Sensitivities. As previously discussed, we have mitigated our sensitivity to commodity prices with approximately three-fourths of our pipeline revenues collected in the form of demand or reservation charges and derivative contracts in our exploration and production business. As noted above, we have significant derivative contracts in place for our 2009 natural gas and oil production. We have also entered into derivative contracts on a substantial portion of our anticipated 2010 natural gas production and a portion of our 2011 natural gas production to mitigate exposure to low commodity prices; however, we continue to have some commodity price exposure in 2010 and beyond. Finally, in the event of lower oil or natural gas prices, we currently have unencumbered exploration and production properties and reserves that we could pledge as collateral to maintain our current available borrowing base under the revolving credit facilities at our exploration and production subsidiary. | ||
• | Counterparty Risk.We continue to monitor the financial situation of our major lenders, derivative counterparties, customers, joint interest partners, vendors and suppliers, and enforce our contractual rights with regard to obtaining collateral or providing credit. | ||
• | Lending Institutions.As of March 31, 2009, we have determined the potential exposure to a loss of available capacity under our credit agreements, due to our assessment of our lenders’ ability to fund, to be approximately $30 million from El Paso’s $1.5 billion revolving credit facility, approximately $2 million from EPEP’s $1.0 billion revolving credit facility, and approximately $15 million under EPB’s $750 million credit facility. |
30
Table of Contents
Segment Results
We have two core operating business segments, Pipelines and Exploration and Production. We also have a Marketing segment that markets our natural gas and oil production and manages our legacy trading activities and a Power segment that has interests in power and pipeline assets in South America and Asia. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses, contracts and assets all of which are immaterial.
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business segments, which consist of both consolidated businesses and investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for items such as (i) interest and debt expense, (ii) income taxes and (iii) net income attributable to noncontrolling interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows.
Below is a reconciliation of our EBIT (by segment) to our consolidated net income (loss) for the quarters ended March 31:
2009 | 2008 | |||||||
(In millions) | ||||||||
Segment | ||||||||
Pipelines | $ | 396 | $ | 381 | ||||
Exploration and Production | (1,685 | ) | 242 | |||||
Marketing | 52 | (60 | ) | |||||
Power | 4 | (2 | ) | |||||
Segment EBIT | (1,233 | ) | 561 | |||||
Corporate and other | (7 | ) | 39 | |||||
Consolidated EBIT | (1,240 | ) | 600 | |||||
Interest and debt expense | (255 | ) | (233 | ) | ||||
Income taxes | 526 | (148 | ) | |||||
Net income (loss) attributable to El Paso Corporation | (969 | ) | 219 | |||||
Net income attributable to noncontrolling interests | 12 | 9 | ||||||
Net income (loss) | $ | (957 | ) | $ | 228 | |||
31
Table of Contents
Pipelines Segment
Overview and Operating Results.During the first quarter of 2009, we continued to deliver strong operational and financial performance across all pipelines. Our first quarter 2009 EBIT increased four percent from the first quarter 2008 or eight percent when excluding the impact of the Calpine settlement and asset impairments in 2008. In the first quarter of 2009, we benefited from several expansion projects placed in service in 2008. Below are the operating results for our Pipelines segment as well as a discussion of factors impacting EBIT for the quarters ended March 31, 2009 and 2008, or that could potentially impact EBIT in future periods.
2009 | 2008 | |||||||
(In millions, | ||||||||
except for volumes) | ||||||||
Operating revenues | $ | 733 | $ | 720 | ||||
Operating expenses | (366 | ) | (363 | ) | ||||
Operating income | 367 | 357 | ||||||
Other income, net | 41 | 33 | ||||||
EBIT before adjustment for noncontrolling interests | 408 | 390 | ||||||
Net income attributable to noncontrolling interests | (12 | ) | (9 | ) | ||||
EBIT | $ | 396 | $ | 381 | ||||
Throughput volumes (BBtu/d)(1) | 19,704 | 19,321 | ||||||
(1) | Throughput volumes include our proportionate share of unconsolidated affiliates and exclude intrasegment activities. |
Variance | ||||||||||||||||
Operating Revenue | Operating Expense | Other | EBIT Impact | |||||||||||||
Favorable/(Unfavorable) | ||||||||||||||||
(In millions) | ||||||||||||||||
Expansions | $ | 19 | $ | (5 | ) | $ | 8 | $ | 22 | |||||||
Reservation and usage revenues | 27 | — | — | 27 | ||||||||||||
Gas not used in operations and revaluations | 1 | (6 | ) | — | (5 | ) | ||||||||||
Calpine bankruptcy settlement | (29 | ) | — | — | (29 | ) | ||||||||||
Loss on long-lived assets | — | 16 | — | 16 | ||||||||||||
Hurricanes | — | (4 | ) | — | (4 | ) | ||||||||||
Net income attributable to noncontrolling interests | — | — | (3 | ) | (3 | ) | ||||||||||
Other(1) | (5 | ) | (4 | ) | — | (9 | ) | |||||||||
Total impact on EBIT | $ | 13 | $ | (3 | ) | $ | 5 | $ | 15 | |||||||
(1) | Consists of individually insignificant items on several of our pipeline systems. |
Expansions.During the first quarter of 2009, we benefited from increased reservation revenues and throughput volumes due to projects placed in service throughout 2008 including the Kanda lateral project, Phase I of the Southeast Supply Header project, the Medicine Bow expansion and the High Plains Pipeline.
We continue to make progress on our nearly $8 billion backlog of expansion projects, spending $0.2 billion during the quarter ended March 31, 2009 and approximately $1.5 billion inception-to-date on these projects. These projects are substantially fully contracted with customers and will be placed in service over the next five years. In addition, financings have been completed to fund our $1.3 billion expansion capital plan in 2009 and a substantial portion of the capital needs for the Gulf LNG and FGT Phase VIII projects. Over the next twelve months,we expect six projects to be placed in-service representing $1.1 billion of the expansion backlog.
During the first quarter of 2009, we agreed with our customer to defer the anticipated in-service date for our Raton 2010 project from June 2010 to December 2010. For a further discussion of our expansion projects, see our 2008 Annual Report on Form 10-K.
32
Table of Contents
Reservation and Usage Revenues.During the quarter ended March 31, 2009, our EBIT was favorably impacted by (i) increased reservation and other service revenues on our EPNG system primarily due to higher contracted capacity to California customers and an increase in EPNG’s tariff rates effective January 1, 2009, subject to refund, (ii) increased revenues for the off-system and mainline capacity on our Rocky Mountain region systems primarily due to renegotiated contract terms and new contracts and (iii) higher realized rates in the northern region and additional capacity sales in the southern region of our TGP system. For a further discussion of our EPNG rate case, seeOther Regulatory Mattersbelow.
Gas Not Used in Operations and Revaluations.During 2008, CIG and WIC implemented FERC-approved fuel and related gas cost recovery mechanisms designed to reduce earnings volatility resulting from these items over time which favorably impacted our EBIT in the first quarter of 2008. Partially offsetting this impact were higher average prices realized on operational sales of gas not used in our TGP system during the quarter ended March 31, 2009.
Calpine Bankruptcy Settlement.During the first quarter of 2008, we received a partial distribution under Calpine’s approved plan of reorganization and recorded revenue of $29 million.
Loss on Long-Lived Assets.During the first quarter of 2008, we recorded impairments of $16 million primarily related to our decision not to proceed with the Essex-Middlesex Lateral project due to its prolonged permitting process and changing market conditions.
Hurricanes.We continue to repair damages to sections of our Gulf Coast and offshore pipeline facilities due to Hurricanes Ike and Gustav which occurred in 2008. For the quarter ended March 31, 2009, our EBIT was unfavorably impacted by repair costs that will not be recoverable from insurance due to losses not exceeding self-retention levels. SeeLiquidity and Capital Resources for a further discussion of these hurricanes.
Noncontrolling Interests.During the quarter ended March 31, 2009, our net income attributable to noncontrolling interests increased as compared to the same period in 2008 due to the additional contribution of interests in CIG and SNG to our majority-owned master limited partnership during September 2008.
Other Regulatory Matters.Our pipeline systems periodically file for changes in their rates, which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, while certain of our pipelines are expected to continue operating under their existing rates, other pipelines have projected upcoming rate actions with anticipated effective dates in late 2009 through 2011.
In June 2008, EPNG filed a rate case with the FERC as required under the settlement of its previous rate case. The filing proposed an increase in its base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of EPNG’s proposals in the technical conference proceeding.
In March 2009, SNG filed a rate case with the FERC as permitted under the settlement of its previous rate case. The filing proposed an increase in SNG’s base tariff rates. In April 2009, the FERC issued an order accepting the proposed rates effective September 1, 2009, subject to refund and the outcome of a hearing and a technical conference on certain tariff proposals. The FERC appointed an administrative law judge who will decide the rate case issues should SNG be unable to reach a settlement with its customers.
33
Table of Contents
Exploration and Production Segment
Overview and Strategy
Our Exploration and Production segment conducts our natural gas and oil exploration and production activities. The profitability and performance of this segment are driven by the ability to locate and develop economic natural gas and oil reserves and extract those reserves at the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management. Our strategy focuses on building and applying competencies in assets with repeatable programs, executing to improve capital and expense efficiency, and maximizing returns by adding assets and inventory that match our competencies and divesting assets that do not. For a further discussion of our business strategy in our production business, see our 2008 Annual Report on Form 10-K.
Our domestic natural gas and oil reserve portfolio blends lower decline rate, typically longer lived assets in our Central and Western regions, with steeper decline rate, shorter lived assets in our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions. In April 2009, we made a decision to reorganize our domestic exploration and production operations by combining our Texas Gulf Coast and Gulf of Mexico and south Louisiana regions which was effective May 1, 2009.
During the first quarter of 2009, we sold domestic non-core natural gas producing properties in our Western and Central regions for approximately $93 million.
�� Internationally, our portfolio consists of producing fields along with projects in several exploration and development areas of interest in offshore Brazil and exploration projects in Egypt. Success of our international programs in Brazil and Egypt will require effective project management, strong partner relations and obtaining approvals from regulatory agencies, although current economic conditions may dictate the timing of our spending. In Egypt, in the first quarter of 2009 we exchanged a 40 percent working interest in our South Mariut block for an equal working interest in the Tanta block. In addition, we successfully bid to farm-in a 50 percent working interest in the South Alamein block located in the Western Desert and are awaiting final government approval. CEPSA Egypt S.A. B.V., the operator of the block, spud the first exploratory well on the block in February 2009. These transactions expand our acreage position and diversify our portfolio in Egypt.
During the first quarter of 2009, the industry experienced continued reductions in the market price of natural gas from already reduced levels at December 31, 2008. Furthermore, while service and equipment costs have declined, they have not declined commensurate with the reduction in commodity prices. Accordingly, we recorded non-cash ceiling test charges of approximately $2.1 billion in the first quarter of 2009 as described further inOperating Results and Variance Analysisbelow.Low commodity prices and high service, equipment and material costs have continued to challenge our economic assumptions on development and exploration in 2009. Coupled with unprecedented challenges in the credit markets, these events resulted in us reducing capital spending in late 2008 and our anticipated capital program in 2009 as previously disclosed in our 2008 Annual Report on Form 10-K. Based on these lower spending levels, we expect our 2009 production volumes to be down from two percent to ten percent compared to 2008.
Significant Operational Factors Affecting the Quarter Ended March 31, 2009
Production.Our average daily production for the three months ended March 31, 2009 was 731 MMcfe/d (which does not include 72 MMcfe/d from our share of production from our equity investment in Four Star). Below is an analysis of our production volumes by region for the quarters ended March 31:
2009 | 2008 | |||||||
MMcfe/d | ||||||||
United States | ||||||||
Central | 245 | 241 | ||||||
Western | 164 | 149 | ||||||
Texas Gulf Coast | 203 | 236 | ||||||
Gulf of Mexico and south Louisiana | 110 | 173 | ||||||
International | ||||||||
Brazil | 9 | 12 | ||||||
Total Consolidated | 731 | 811 | ||||||
Four Star | 72 | 75 | ||||||
34
Table of Contents
In the first quarter of 2009, production volumes increased in our Central and Western regions. Central region production volumes increased as a result of our successful Arklatex drilling programs including the Haynesville Shale, while our Western region production volumes increased in both the Rockies and the Raton Basin. In our Texas Gulf Coast region, production volumes decreased primarily due to sales of assets in 2008 and 2009, while Gulf of Mexico and south Louisiana region production volumes decreased due to the impacts of asset sales and ongoing impacts of Hurricanes Ike and Gustav. In Brazil, our production volumes decreased primarily due to natural production declines.
2009 Drilling Results
Our drilling results for the quarter ended March 31, 2009 by region are as follows:
Central.We achieved a 100 percent success rate on 46 gross wells drilled.
Western.We achieved a 100 percent success rate on two gross wells drilled.
Texas Gulf Coast.We achieved a 100 percent success rate on 13 gross wells drilled.
Gulf of Mexico and south Louisiana.We achieved a 50 percent success rate on two gross wells drilled.
Brazil.Our drilling operations in Brazil are primarily in the Camamu and Espirito Santo Basins.
• | Camamu Basin.During the first quarter of 2009, we continued the process of obtaining regulatory and environmental approvals that are required to enter the next phase of development in the Pinauna Field. The timing of the Pinauna Field development will be dependent on the receipt of these approvals and either the recovery of commodity prices or cost reductions that reflect the current low commodity price environment. | ||
In the BM-CAL-6 block, following the drilling of an unsuccessful exploratory well in 2008 and further evaluation, we have decided to relinquish our interest in this block. In the BM-CAL-5 block, we continue to evaluate the results and appraisal options on a well where hydrocarbons were discovered in 2008 and plan to participate in drilling a second exploratory well to evaluate another prospect in the block during the second quarter of 2009. | |||
• | Espirito Santo Basin.We continue to execute the plan of development for the Camarupim Field which includes drilling four horizontal natural gas wells. As of March 31, 2009, one well has been drilled and tested and three additional wells have been spud and are nearing completion. Petrobras, the operator, estimates it will complete all drilling operations and begin production from the field in late June or early July 2009. | ||
In 2008, we also participated with Petrobras in drilling an exploratory well in the ES-5 block in the Espirito Santo Basin in which we own a 35 percent working interest. Hydrocarbons were found in the well and we are now evaluating the results. During the second quarter of 2009, we plan to participate with Petrobras in drilling another exploratory well to evaluate an additional prospect in the ES-5 block. |
During the first quarter of 2009, we added approximately 58 Bcfe of Brazilian reserves. As of March 31, 2009, we have total capitalized costs of approximately $261 million in Brazil, of which $167 million are unevaluated capitalized costs.
Egypt.In early April 2009, we completed drilling an exploratory well in the South Mariut block that was unsuccessful. We plan to drill two to three additional exploratory wells in this block during 2009. As of March 31, 2009, we have total capitalized costs of approximately $26 million in Egypt, all of which are unevaluated capitalized costs.
35
Table of Contents
Cash Operating Costs.We monitor cash operating costs required to produce our natural gas and oil production volumes. These costs are calculated on a per Mcfe basis and include total operating expenses less depreciation, depletion and amortization expense, ceiling test or impairment charges, transportation costs and cost of products.
During the quarter ended March 31, 2009, overall cash operating costs decreased compared with the same period in 2008. However, cash operating costs per unit increased to $2.00/Mcfe as compared to $1.92/Mcfe during the same period in 2008 primarily due to lower production volumes in 2009 versus 2008.
Capital Expenditures.Our total natural gas and oil capital expenditures were $321 million during the quarter ended March 31, 2009, of which $246 million were domestic capital expenditures.
Outlook for 2009
For the full year 2009, we expect the following on a worldwide basis:
• | Capital expenditures, excluding acquisitions, of $0.9 billion to $1.2 billion. Of this total, we expect to spend $0.7 billion to $1.0 billion on our domestic program and approximately $250 million in Brazil and Egypt. Brazil capital expenditures include the costs to complete development of our Camarupim project in late June or early July 2009. | ||
• | Average daily production volumes for the year of approximately 665 MMcfe/d to 730 MMcfe/d, which does not include approximately 65 MMcfe/d to 70 MMcfe/d from our equity investment in Four Star. Production volumes from our Brazil operations are expected to increase from an average of about 11 MMcfe/d in 2008 to between 30 MMcfe/d and 40 MMcfe/d in 2009, with production volumes from the Camarupim Field expected to commence in late June or early July 2009. | ||
• | Average cash operating costs which include production costs, general and administrative expenses and other expenses of approximately $2.05/Mcfe to $2.35/Mcfe for the year. | ||
• | Depreciation, depletion and amortization rate of between $1.70/Mcfe and $1.90/Mcfe, which includes the impact of our first quarter 2009 ceiling test charges. |
Price Risk Management Activities
We enter into derivative contracts on our natural gas and oil production to stabilize cash flows, reduce the risk and financial impact of downward commodity price movements on commodity sales and to protect the economic assumptions associated with our capital investment programs. Because this strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. Adjustments to our strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company.
36
Table of Contents
During the first quarter of 2009, we settled all of our existing 2009 fixed price oil swaps for approximately $186 million in cash and entered into new fixed price oil swaps on 1,500 MBbls of our remaining anticipated 2009 oil production at an average price of $45.00 per barrel. We also entered into additional natural gas option and basis swap contracts on our 2009 and 2010 production. During the first quarter of 2009, we paid $63 million in premiums to enter into financial derivative contracts related to our 2010 natural gas production. The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under our derivative contracts as of March 31, 2009.
Fixed Price | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Swaps(1) | Floors(1) | Ceilings(1) | Basis Swaps(1)(2) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Western | Central | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Texas Gulf Coast | Raton | Rockies | Mid-Continent | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Average | Average | Average | Average | Average | Average | Average | ||||||||||||||||||||||||||||||||||||||||||||||||||
Volumes | Price | Volumes | Price | Volumes | Price | Volumes | Price | Volumes | Price | Volumes | Price | Volumes | Price | |||||||||||||||||||||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 6 | $ | 7.40 | 114 | $ | 9.11 | 89 | $ | 14.83 | 43 | $ | (0.34 | ) | 18 | $ | (0.96 | ) | 10 | $ | (2.01 | ) | 7 | $ | (1.04 | ) | |||||||||||||||||||||||||||||||
2010 | 25 | $ | 6.61 | 42 | $ | 7.00 | 20 | $ | 9.45 | 47 | $ | (0.40 | ) | 11 | $ | (0.80 | ) | 9 | $ | (1.93 | ) | 9 | $ | (0.74 | ) | |||||||||||||||||||||||||||||||
2011-2012 | 7 | $ | 3.88 | — | — | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
Oil | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 1,348 | $ | 45.00 | — | — | — | — | — | — | — | — | — | — | — | — |
(1) | Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil. | |
(2) | Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences. |
Since March 31, 2009 and through May 7, 2009, we paid approximately $110 million in premiums to enter into additional financial derivative contracts related to our 2010 and 2011 production as follows:
Fixed Price | ||||||||||||||||||||||||||||||||
Swaps(1) | Floors(1) | Ceilings(1) | Basis Swaps(1)(2) | |||||||||||||||||||||||||||||
Average | Average | Average | Average | |||||||||||||||||||||||||||||
Volumes | Price | Volumes | Price | Volumes | Price | Volumes | Price | |||||||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||||
2010 | 27 | $ | 5.80 | 81 | $ | 6.25 | 41 | $ | 7.50 | 9 | $ | 0.75 | ||||||||||||||||||||
2011 | 11 | $ | 6.88 | 110 | $ | 6.00 | 110 | $ | 9.00 | — | $ | — |
(1) | Volumes presented are TBtu for natural gas. Prices presented are per MMBtu of natural gas. | |
(2) | Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences. |
Internationally, our gas sales agreement for our production from the Camarupim field in Brazil provides for a price that is adjusted quarterly based on a basket of fuel oil prices. In May 2009, we entered into fuel oil swaps which will effectively lock in a price of about $4.00 per Mcf on about 6 Bcf of projected natural gas production in 2010.
37
Table of Contents
Operating Results and Variance Analysis
The information below provides the financial results and an analysis of significant variances in these results during the quarter ended March 31:
Quarter Ended | ||||||||
March 31, | ||||||||
2009 | 2008 | |||||||
(In millions) | ||||||||
Physical sales: | ||||||||
Natural gas | $ | 252 | $ | 476 | ||||
Oil, condensate and NGL | 46 | 166 | ||||||
Total physical sales | 298 | 642 | ||||||
Realized and unrealized gains (losses) on financial derivatives(1) | 394 | (50 | ) | |||||
Other revenues | 8 | 11 | ||||||
Total operating revenues | 700 | 603 | ||||||
Operating expenses: | ||||||||
Cost of products | 5 | 5 | ||||||
Transportation costs | 20 | 19 | ||||||
Production costs | 78 | 91 | ||||||
Depreciation, depletion and amortization | 150 | 212 | ||||||
General and administrative expenses | 50 | 47 | ||||||
Ceiling test charges | 2,068 | — | ||||||
Other | 4 | 3 | ||||||
Total operating expenses | 2,375 | 377 | ||||||
Operating income (loss) | (1,675 | ) | 226 | |||||
Other income (expense)(2) | (10 | ) | 16 | |||||
EBIT | $ | (1,685 | ) | $ | 242 | |||
(1) | Includes $128 million and $(15) million in 2009 and 2008, of amounts reclassified from accumulated other comprehensive income associated with accounting hedges. | |
(2) | Other income (expense) includes equity earnings (losses) from our investment in Four Star. |
38
Table of Contents
The table below provides additional detail of our consolidated volumes, prices, and costs per unit as well as volumetric data related to our investment in Four Star. In the table below, we present (i) average realized prices based on physical sales of natural gas and oil, condensate and NGL as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements. Our average realized prices, including financial derivative settlements, reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur; however, these prices do not reflect the impact of any associated premiums paid to enter into certain of our derivative contracts.
Quarter Ended March 31, | ||||||||||||
Percent | ||||||||||||
2009 | 2008 | Variance | ||||||||||
Consolidated volumes, prices and costs per unit: | ||||||||||||
Natural gas | ||||||||||||
Volumes (MMcf) | 56,862 | 61,810 | (8 | )% | ||||||||
Average realized price on physical sales ($/Mcf) | $ | 4.43 | $ | 7.72 | (43 | )% | ||||||
Average realized price, including financial derivative settlements ($/Mcf) (1) | $ | 8.52 | $ | 7.60 | 12 | % | ||||||
Average transportation costs ($/Mcf) | $ | 0.34 | $ | 0.28 | 21 | % | ||||||
Oil, condensate and NGL | ||||||||||||
Volumes (MBbls) | 1,477 | 1,992 | (26 | )% | ||||||||
Average realized price on physical sales ($/Bbl) | $ | 31.29 | $ | 83.06 | (62 | )% | ||||||
Average realized price, including financial derivative settlements ($/Bbl) (1) (2) | $ | 70.14 | $ | 80.14 | (12 | )% | ||||||
Average transportation costs ($/Bbl) | $ | 0.93 | $ | 0.71 | 31 | % | ||||||
Total equivalent volumes | ||||||||||||
MMcfe | 65,700 | 73,762 | (11 | )% | ||||||||
MMcfe/d | 731 | 811 | (10 | )% | ||||||||
Production costs and other cash operating costs ($/Mcfe) | ||||||||||||
Average lease operating expenses | $ | 0.89 | $ | 0.82 | 9 | % | ||||||
Average production taxes(3) | 0.29 | 0.42 | (31 | )% | ||||||||
Total production costs | $ | 1.18 | $ | 1.24 | (5 | )% | ||||||
Average general and administrative expenses | 0.76 | 0.64 | 19 | % | ||||||||
Average taxes, other than production and income taxes | 0.06 | 0.04 | 50 | % | ||||||||
Total cash operating costs | $ | 2.00 | $ | 1.92 | 4 | % | ||||||
Depreciation, depletion and amortization ($/Mcfe) | $ | 2.28 | $ | 2.87 | (21 | )% | ||||||
Unconsolidated affiliate volumes (Four Star): | ||||||||||||
Natural gas (MMcf) | 4,860 | 5,121 | ||||||||||
Oil, condensate and NGL (MBbls) | 276 | 285 | ||||||||||
Total equivalent volumes | ||||||||||||
MMcfe | 6,516 | 6,832 | ||||||||||
MMcfe/d | 72 | 75 |
(1) | Premiums related to natural gas derivatives settled during the quarter ended March 31, 2008 were $5 million. Had we included these premiums in our natural gas average realized price in 2008, our realized price, including financial derivative settlements, would have decreased by $0.08/Mcf. We had no premiums related to natural gas derivatives settled during the quarter ended March 31, 2009 or related to oil derivatives settled during the quarters ended March 31, 2009 and 2008. | |
(2) | Does not include approximately $149 million received in the first quarter of 2009 related to the early settlement of oil derivative contracts originally scheduled to settle April through December of 2009. These amounts will be included in our average realized price over the remainder of the year based on when the contracted settlements were originally scheduled to occur. | |
(3) | Production taxes include ad valorem and severance taxes. |
39
Table of Contents
Quarter Ended March 31, 2009 Compared to Quarter Ended March 31, 2008
Our EBIT for the quarter ended March 31, 2009 decreased $1.9 billion as compared to the same period in 2008. The table below shows the significant variances in our financial results for the quarter ended March 31, 2009 as compared to the same period in 2008:
Variance | ||||||||||||||||
Operating | Operating | |||||||||||||||
Revenue | Expense | Other | EBIT | |||||||||||||
Favorable/(Unfavorable) | ||||||||||||||||
(In millions) | ||||||||||||||||
Physical sales | ||||||||||||||||
Natural gas | ||||||||||||||||
Lower realized prices in 2009 | $ | (187 | ) | $ | — | $ | — | $ | (187 | ) | ||||||
Lower volumes in 2009 | (37 | ) | — | — | (37 | ) | ||||||||||
Oil, condensate and NGL | ||||||||||||||||
Lower realized prices in 2009 | (77 | ) | — | — | (77 | ) | ||||||||||
Lower volumes in 2009 | (43 | ) | — | — | (43 | ) | ||||||||||
Realized and unrealized gains/(losses) on financial derivatives | 444 | — | — | 444 | ||||||||||||
Other Revenues | ||||||||||||||||
Other | (3 | ) | — | — | (3 | ) | ||||||||||
Depreciation, Depletion and Amortization Expense | ||||||||||||||||
Lower depletion rate in 2009 | — | 40 | — | 40 | ||||||||||||
Lower production volumes in 2009 | — | 22 | — | 22 | ||||||||||||
Production Costs | ||||||||||||||||
Lower lease operating expenses in 2009 | — | 2 | — | 2 | ||||||||||||
Lower production taxes in 2009 | — | 11 | — | 11 | ||||||||||||
Ceiling Test Charges | — | (2,068 | ) | — | (2,068 | ) | ||||||||||
Other | ||||||||||||||||
Earnings from investment in Four Star | — | — | (20 | ) | (20 | ) | ||||||||||
Other | — | (5 | ) | (6 | ) | (11 | ) | |||||||||
Total Variances | $ | 97 | $ | (1,998 | ) | $ | (26 | ) | $ | (1,927 | ) | |||||
Physical sales.Physical sales represent accrual-based commodity sales transactions with customers. During the first quarter of 2009, natural gas, oil, condensate and NGL revenues decreased as compared to the same period in 2008 due to lower commodity prices and lower production volumes.
Realized and unrealized gains/(losses) on financial derivatives.During the first quarter of 2009, we recognized gains of $394 million compared to losses of $50 million during the same period in 2008 due to lower natural gas and oil prices in 2009 relative to commodity prices contained in our derivative contracts.
Depreciation, depletion and amortization expense.During the first quarter of 2009, our depreciation, depletion and amortization expense decreased as a result of a lower depletion rate and lower production volumes. The lower depletion rate is primarily a result of the impact of the ceiling test charges recorded in December of 2008.
Production costs.Our production costs decreased during the first quarter of 2009 as compared to the same period in 2008 primarily due to lower production taxes as a result of lower natural gas and oil revenues.
Ceiling test charges.We are required to conduct impairment tests of our capitalized costs in each of our full cost pools. As of March 31, 2009, natural gas prices had declined to $3.63 per MMBtu, while oil prices were at $49.66 per barrel. The decrease in natural gas prices resulted in downward price-related reserve revisions of approximately 400 Bcfe (primarily in our Arklatex, Raton and Mid-Continent areas), and non-cash ceiling test charges of approximately $2.1 billion ($2.0 billion in our domestic full cost pool and $28 million in our Brazilian full cost pool). We also recorded a $9 million charge in Egypt related to a dry hole drilled in the South Mariut block.
Other.Our equity earnings from Four Star decreased by $20 million during the first quarter of 2009 as compared to the same period in 2008 primarily due to lower commodity prices.
40
Table of Contents
Marketing Segment
Overview.Our Marketing segment’s primary focus is to market our Exploration and Production segment’s natural gas and oil production, manage El Paso’s overall price risk, and manage our remaining legacy contracts that were entered into prior to the deterioration of the energy trading environment in 2002. To the extent it is economical and prudent, we will continue to seek opportunities to reduce the impact of remaining legacy contracts on our future operating results through contract liquidations.
The primary remaining exposure to our operating results relates to changes in the fair value of our legacy PJM power contracts primarily related to changes in power prices at locations within the PJM region. In addition to the PJM power contracts, our legacy contracts include natural gas derivative contracts which are marked-to-market in our operating results as well as transportation-related natural gas and long-term natural gas supply contracts which are accrual-based contracts that impact our revenues as delivery or service under the contracts occurs. All of our remaining contracts are subject to counterparty credit and non-performance risk while each of our mark-to-market contracts is also subject to interest rate exposure. For a further discussion of our remaining contracts, see below and our 2008 Annual Report on Form 10-K.
Operating Results.During the quarter ended March 31, 2009, we generated EBIT of $52 million primarily driven by mark-to-market gains of approximately $52 million related to the application of the provisions of EITF Issue No. 08-5 on our derivative liabilities that have non-cash collateral associated with them, such as letters of credit. For a further description of our adoption of this standard, see Item 1, Financial Statements, Note 1. Below is further information about our overall operating results during each of the quarters ended March 31:
2009 | 2008 | |||||||
(In millions) | ||||||||
Revenue by Significant Contract Type: | ||||||||
Production-Related Natural Gas and Oil Derivative Contracts: | ||||||||
Changes in fair value of options and swaps | $ | — | $ | (21 | ) | |||
Contracts Related to Legacy Trading Operations: | ||||||||
Changes in fair value of power contracts | 34 | (41 | ) | |||||
Natural gas transportation-related contracts: | ||||||||
Demand charges | (9 | ) | (9 | ) | ||||
Settlements, net of termination payments | 7 | 14 | ||||||
Changes in fair value of other natural gas derivative contracts | 21 | — | ||||||
Total revenues | 53 | (57 | ) | |||||
Operating expenses | (1 | ) | (3 | ) | ||||
Operating income (loss) and EBIT | $ | 52 | $ | (60 | ) | |||
Production-related Natural Gas and Oil Derivative Contracts. Prior to January 1, 2009, we held production-related natural gas and oil derivative contracts. During the quarter ended March 31, 2008, increases in commodity prices reduced the fair value of these contracts resulting in losses.
41
Table of Contents
Contracts Related to Legacy Trading Operations
Power contracts.Our primary remaining exposure in our power portfolio consists of changes in locational power price differences in the PJM region, changes in counterparty credit risk, and changes in interest rates. Prior to agreements entered into through 2008, we were also exposed to changes in installed capacity prices and commodity prices. Power prices in the PJM region are highly volatile due to changes in fuel prices and transmission congestion at certain locations in the region, and future changes in locational prices could continue to significantly impact the fair value of our power contracts.
In the first quarter of 2009, we recognized a mark-to-market gain of $34 million on these contracts which included a $33 million gain related to the application of EITF Issue No. 08-5 on certain of our derivative liabilities, as further described in Item 1, Financial Statements, Note 1. In the first quarter of 2008, we recognized a mark-to-market loss of $41 million resulting from changes in locational PJM power prices and interest rates, and from executing a capacity purchase agreement with a counterparty to economically hedge our remaining capacity exposure.
Natural gas transportation-related contracts.As of March 31, 2009, our transportation contracts provide us with approximately 0.6 Bcf/d of pipeline capacity. For the remainder of 2009, we anticipate demand charges related to this capacity of approximately $32 million which we expect to decline to an average of $22 million annually from 2010 through 2013. The profitability of these contracts is dependent upon the recovery of demand charges as well as our ability to use or remarket the contracted pipeline capacity, which is impacted by a number of factors including differences in natural gas prices at contractual receipt and delivery locations, the working capital needed to use this capacity, and the capacity required to meet our long-term obligations. Our transportation contracts are accounted for on an accrual basis and impact our revenues as delivery or service under the contracts occurs.
Other natural gas derivative contracts.In addition to our natural gas transportation contracts, we have other contracts with third parties that require us to purchase or deliver natural gas primarily at market prices. While we have substantially offset all of the fixed price exposure in these contracts, they are still subject to changes in fair value due to changes in the interest rates and counterparty credit risk used to value these contracts. The mark-to-market gain of $21 million recognized during the first quarter of 2009 includes a $19 million gain related to the application of EITF Issue No. 08-5 on certain of our derivative liabilities, as further described in Item 1, Financial Statements, Note 1.
42
Table of Contents
Power Segment
Overview.As of March 31, 2009, our remaining investment, guarantees and letters of credit related to projects in this segment totaled approximately $296 million which consisted of approximately $280 million in equity investments and notes and accounts receivable and approximately $16 million in financial guarantees and letters of credit, as follows (in millions):
Area | ||||
South America | ||||
Porto Velho — note receivable from buyer | $ | 78 | ||
Manaus & Rio Negro | 42 | |||
Bolivia-to-Brazil Pipeline | 135 | |||
Argentina-to-Chile Pipeline | 29 | |||
Asia | 12 | |||
Total | $ | 296 | ||
During the first quarter of 2008, we transferred the ownership of our Manaus and Rio Negro power plants in Brazil to the plants’ power purchaser. While we no longer own the Manaus and Rio Negro power plants, we still have exposure relating to outstanding receivables due from the power purchaser. In February 2009, we also completed the sale of our investment in Porto Velho for total consideration of $179 million. The sale of our investment in the Argentina-to-Chile pipeline is expected to be completed in mid-2009. Until the sale of our remaining international investments is completed, related receivables are collected or matters further discussed in Item 1, Financial Statements, Note 13 are resolved, any changes in regional political and economic conditions could negatively impact the anticipated proceeds we may receive, which could result in impairments of our remaining assets and investments.
Operating Results.For the quarter ended March 31, 2009, our Power segment generated EBIT of $4 million compared to an EBIT loss of $2 million in the first quarter of 2008. Our 2009 EBIT primarily relates to equity earnings from our Bolivia-to-Brazil and Argentina-to-Chile pipeline investments. For a discussion of developments and other matters that could impact our remaining assets and investments, see Item 1, Financial Statements, Note 13.
Corporate and Other Expenses, Net
Our corporate activities include our general and administrative functions as well as a number of miscellaneous businesses, which do not qualify as operating segments and are not material to our current year results. The following is a summary of significant items impacting the EBIT in our corporate activities for the quarters ended March 31:
2009 | 2008 | |||||||
(In millions) | ||||||||
Change in litigation, insurance and other reserves | $ | (3 | ) | $ | 11 | |||
Foreign currency fluctuations on Euro-denominated debt | — | (6 | ) | |||||
Gain on disposition of a portion of our telecommunications business | — | 18 | ||||||
Other | (4 | ) | 16 | |||||
Total EBIT | $ | (7 | ) | $ | 39 | |||
Litigation, Insurance, and Other Reserves.We have a number of pending litigation matters and reserves related to our historical business operations that also affect our corporate results. Adverse rulings or unfavorable outcomes or settlements against us related to these matters have impacted and may continue to impact our future results.
43
Table of Contents
In March 2008, we received a summary judgment from a trial court on our Case Corporation indemnification dispute. As a result of the judgment, we adjusted our existing indemnification accrual using current actuarial assumptions and reclassified amounts accrued as a postretirement benefit obligation. This resulted in a $65 million reduction in operation and maintenance expense. See Item I, Financial Statements, Notes 9 and 10 for a further discussion of this matter.
During the first quarter of 2008, we recorded additional mark-to-market losses of approximately $43 million on an indemnification associated with the sale of a legacy ammonia facility. These losses were based on significant increases in ammonia prices during the first quarter of 2008 compared to relatively flat prices in the first quarter of 2009. Changes in ammonia prices may continue to impact this contract, which could result in additional future losses.
Interest and Debt Expense
Our interest and debt expense was $255 million and $233 million for the quarters ended March 31, 2009 and 2008. This increase was primarily due to higher average debt balances in 2009 when compared to 2008.
Income Taxes
Quarter Ended March 31, | ||||||||
2009 | 2008 | |||||||
(In millions, except for rates) | ||||||||
Income taxes | $ | (526 | ) | $ | 148 | |||
Effective tax rate | 35 | % | 39 | % |
For a discussion of our effective tax rates and other matters impacting our income taxes, see Item 1, Financial Statements, Note 4.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Item I, Financial Statements, Note 9, which is incorporated herein by reference.
44
Table of Contents
Liquidity and Capital Resources
Over the past several years, our focus has been on expanding our core pipeline and exploration and production businesses to provide for long-term growth and value. During this period, we also strengthened our balance sheet primarily through managing our overall debt obligations. Our primary sources of cash are cash flow from operations and amounts available to us under our revolving credit facilities. As conditions warrant, we may also generate funds through capital market activities and asset sales. Our primary uses of cash are funding the capital expenditure programs of our pipeline and exploration and production operations, meeting operating needs and repaying debt when due or repurchasing debt when conditions warrant. In the first quarter of 2009, we continued to generate significant positive operating cash flows from both our core pipeline and production operations which we expect to continue for the remainder of 2009.
In response to the significant volatility and instability in the global financial markets that began in 2008, we have taken several actions to address our liquidity needs including a reduction in our capital program for 2009, selling certain non-core assets (as further discussed below), issuing debt to fund our 2009 debt maturities and fund our 2009 capital program, and advancing our plans to partner on certain expansion projects. Discussed below are (i) our available liquidity and liquidity outlook for the remainder of 2009 as well as (ii) an overview of cash flow activities for the first quarter of 2009.
Available Liquidity and Liquidity Outlook for 2009.At March 31, 2009, we had approximately $3.3 billion of available liquidity, consisting of $1.8 billion of cash and approximately $1.5 billion of capacity available to us under our various credit facilities, exclusive of $160 million available to EPB under its revolving credit facility. Traditionally, we have pursued additional bank financings, project financings or debt capital markets transactions to supplement our available cash and credit facilities which we have used to fund the capital expenditure programs of our core businesses, meet operating needs and repay debt maturities.
Our cash capital expenditures for the quarter ended March 31, 2009, and the amount of cash we expect to spend for the remainder of 2009 to grow and maintain our businesses are as follows:
Quarter Ended | 2009 | |||||||||||
March 31, 2009 | Remaining | Total | ||||||||||
(In billions) | ||||||||||||
Pipelines | ||||||||||||
Maintenance | $ | 0.1 | $ | 0.3 | $ | 0.4 | ||||||
Growth | 0.3 | 1.0 | 1.3 | |||||||||
Exploration and Production(1) | 0.4 | 0.8 | 1.2 | |||||||||
Other | — | 0.1 | 0.1 | |||||||||
$ | 0.8 | $ | 2.2 | $ | 3.0 | |||||||
(1) | For 2009, our planned cash capital expenditures, excluding acquisitions, are expected to range from $0.9 billion to $1.2 billion. |
As part of our efforts to meet our projected liquidity needs, which include our 2009 capital program and debt maturities in May 2009, we have successfully generated additional liquidity of approximately $1.9 billion since November 2008. Of this amount, we generated $1.2 billion in proceeds through public debt offerings (approximately $1 billion of El Paso notes and $250 million of TGP notes), obtained a 364-day $300 million secured revolving credit facility collateralized by certain proved oil and gas reserves of a production subsidiary, entered into an additional $150 million letter of credit facility and issued $135 million of debt through our subsidiary that owns our Elba Island LNG facility. We also completed the sale of $0.2 billion of non-core assets (primarily in our Exploration and Production and Power segments) and are evaluating the sale of an additional $0.2 billion.
45
Table of Contents
We believe our actions taken over the last several months provide sufficient liquidity to meet our operating needs, repay our $0.9 billion of remaining 2009 debt maturities and fund our 2009 capital program, regardless of whether we are successful in obtaining equity partners on any of our capital projects. When prudent, however, we will continue to be opportunistic in building liquidity to meet our long-term capital needs. There are no assurances, however , that we will be able to access the financial markets to fund our long-term captial needs. To the extent the financial markets are restricted, there is a further decline in commodity prices from current levels, or any of our announced actions are not sufficient, it is possible that additional adjustments to our plan and outlook will be required which could impact our financial and operating performance. These alternatives or adjustments to our plan could include additional reductions in our discretionary capital program, further reductions in operating and general and administrative expenses, secured financing arrangements, seeking partners for one or more of our other growth projects and the sale of additional non-core assets which could impact our financial and operating performance.
Additional Factors That Could Impact Our Future Liquidity.Listed below are two additional factors that could impact our liquidity.
Price Risk Management Activities and Margining Requirements. We currently post letters of credit for the required margin on certain derivative contracts in our Marketing segment. Depending on changes in commodity prices or interest rates, we could be required to post additional margin or may recover margin earlier than anticipated. A 10 percent change in natural gas and power prices would not have had a significant impact on the margin requirements of our derivative contracts as of March 31, 2009. Additionally, we are exposed to (and have adjusted the fair value of these contracts for) the risk that the counterparties to our derivative contracts may not be able to perform or post the necessary collateral with us. We have assessed this counterparty credit and non-performance risk given the recent instability in the credit markets and determined that our exposure is primarily limited to five financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.
Hurricanes Ike and Gustav.During 2008, our pipeline and exploration and production facilities were damaged by Hurricanes Ike and Gustav. We assessed the damages resulting from these hurricanes and the corresponding impact on estimated costs to repair and abandon impacted facilities. Although our estimates may change in the future, our current planned pipeline capital expenditures include hurricane-related expenditures of approximately $146 million, a majority of which we expect will be spent in 2009 and 2010. None of these amounts are recoverable from insurance due to the losses not exceeding our self-retention levels for these events.
46
Table of Contents
Overview of Cash Flow Activities.During the first quarter of 2009, we generated positive operating cash flow of approximately $0.8 billion primarily as a result of cash provided by our pipeline and exploration and production operations. In addition, we generated $0.2 billion in proceeds from the sale of our interest in the Porto Velho power generation facility in Brazil and the sale of two non-core natural gas producing properties. We also generated $0.8 billion in proceeds in conjunction with the issuance of $0.7 billion of unsecured notes and completion of our Elba LNG facility financing of $135 million. We utilized a portion of these amounts to fund maintenance and growth projects in our pipeline and exploration and production operations, pay down debt, and pay dividends, among other items. For the quarter ended March 31, 2009, our cash flows from continuing operations are summarized as follows:
2009 | ||||
(In billions) | ||||
Cash Flow from Operations | ||||
Continuing operating activities | ||||
Net loss | $ | (1.0 | ) | |
Ceiling test charges | 2.1 | |||
Other income adjustments | (0.3 | ) | ||
Total cash flow from operations | $ | 0.8 | ||
Other Cash Inflows | ||||
Continuing investing activities | ||||
Net proceeds from the sale of assets and investments | $ | 0.2 | ||
Other | 0.1 | |||
0.3 | ||||
Continuing financing activities | ||||
Net proceeds from the issuance of long-term debt | 0.8 | |||
Total other cash inflows | $ | 1.1 | ||
Cash Outflows | ||||
Continuing investing activities | ||||
Capital expenditures | $ | 0.8 | ||
Continuing financing activities | ||||
Payments to retire long-term debt and other financing obligations | 0.2 | |||
Dividends and other | 0.1 | |||
0.3 | ||||
Total cash outflows | $ | 1.1 | ||
Net change in cash | $ | 0.8 | ||
47
Table of Contents
Contractual Obligations
The following information provides updates to our contractual obligations, and should be read in conjunction with the information disclosed in our 2008 Annual Report on Form 10-K.
Commodity-Based Derivative Contracts
We use derivative financial instruments in our Exploration and Production and Marketing segments to manage the price risk of commodities. Our commodity-based derivative contracts are not currently designated as accounting hedges and include options, swaps and other natural gas and power purchase and supply contracts that are not traded on active exchanges. The following table details the fair value of our commodity-based derivative contracts by year of maturity as of March 31, 2009:
Maturity | Maturity | Maturity | Maturity | Total | ||||||||||||||||
Less Than | 1 to 3 | 4 to 5 | 6 to 10 | Fair | ||||||||||||||||
1 Year | Years | Years | Years | Value | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Assets | $ | 601 | $ | 153 | $ | 18 | $ | 14 | $ | 786 | ||||||||||
Liabilities | (189 | ) | (368 | ) | (160 | ) | (105 | ) | (822 | ) | ||||||||||
Total commodity-based derivatives | $ | 412 | $ | (215 | ) | $ | (142 | ) | $ | (91 | ) | $ | (36 | ) | ||||||
The following is a reconciliation of our commodity-based derivatives for the quarter ended March 31, 2009:
Commodity- | ||||
Based | ||||
Derivatives | ||||
(In millions) | ||||
Fair value of contracts outstanding at January 1, 2009 | $ | (25 | ) | |
Fair value of contract settlements during the period(1) | (395 | ) | ||
Changes in fair value of contracts during the period | 321 | |||
Premiums paid during the period | 63 | |||
Net changes in contracts outstanding during the period | (11 | ) | ||
Fair value of contracts outstanding at March 31, 2009 | $ | (36 | ) | |
(1) | Includes amounts received related to the early settlement of production-related oil derivative contracts prior to their scheduled maturity. |
48
Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk
This information updates, and you should read it in conjunction with the information disclosed in our 2008 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2008 Annual Report on Form 10-K, except as presented below:
Commodity Price Risk
Production-Related Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These contracts impact our earnings as the fair value of these derivatives changes. Our production-related derivatives do not mitigate all of the commodity price risks of our forecasted sales of natural gas and oil production and, as a result, we are subject to commodity price risks on the remaining forecasted natural gas and oil production.
Other Commodity-Based Derivatives.In our Marketing segment, we have long-term natural gas and power derivative contracts which include forwards, swaps, options and futures that we either intend to manage until their expiration or seek opportunities to liquidate to the extent it is economical and prudent. We utilize a sensitivity analysis to manage the commodity price risk associated with our other commodity-based derivative contracts.
Sensitivity Analysis.The table below presents the hypothetical sensitivity of our production-related derivatives and our other commodity-based derivatives to changes in fair values arising from immediate selected potential changes in the market prices (primarily natural gas, oil and power prices and basis differentials) used to value these contracts. This table reflects the sensitivities of the derivative contracts only and does not include any underlying hedged commodities.
Change in Market Price | ||||||||||||||||||||
10 Percent Increase | 10 Percent Decrease | |||||||||||||||||||
Fair Value | Fair Value | Change | Fair Value | Change | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Production-related derivatives — net assets | ||||||||||||||||||||
March 31, 2009 | $ | 573 | $ | 497 | $ | (76 | ) | $ | 652 | $ | 79 | |||||||||
December 31, 2008 | $ | 682 | $ | 582 | $ | (100 | ) | $ | 785 | $ | 103 | |||||||||
Other commodity-based derivatives — net liabilities | ||||||||||||||||||||
March 31, 2009 | $ | (609 | ) | $ | (620 | ) | $ | (11 | ) | $ | (598 | ) | $ | 11 | ||||||
December 31, 2008 | $ | (707 | ) | $ | (719 | ) | $ | (12 | ) | $ | (695 | ) | $ | 12 |
49
Table of Contents
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of March 31, 2009, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and our CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our CEO and CFO have concluded that our disclosure controls and procedures are effective at a reasonable level of assurance at March 31, 2009.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the first quarter of 2009.
50
Table of Contents
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
See Part I, Item 1, Financial Statements, Note 9, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our 2008 Annual Report on Form 10-K filed with the SEC.
Latigo Natural Gas Storage. In April 2009, the Colorado Department of Public Health and Environment (CDPHE) issued a Compliance Advisory alleging various violations related to the operation of an evaporation pond at the Latigo underground natural gas storage field including failure to account for, and adequately permit, methanol emissions. CIG will be meeting with the CDPHE to discuss the Compliance Advisory and address their concerns.
Item 1A. Risk Factors
CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:
• | earnings per share; | ||
• | capital and other expenditures; | ||
• | dividends; | ||
• | financing plans; | ||
• | capital structure; | ||
• | liquidity and cash flow; | ||
• | pending legal proceedings, claims and governmental proceedings, including environmental matters; | ||
• | future economic and operating performance; | ||
• | operating income; | ||
• | management’s plans; and | ||
• | goals and objectives for future operations. |
Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2008 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. There have been no material changes in our risk factors since that report.
51
Table of Contents
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
Item 6. Exhibits
The Exhibit Index is incorporated herein by reference.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
• | 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 if those statements prove to be inaccurate; | ||
• | may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement; | ||
• | may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and | ||
• | were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments. |
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
52
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, El Paso Corporation has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EL PASO CORPORATION | ||||
Date: May 11, 2009 | /s/ D. Mark Leland | |||
Executive Vice President and Chief Financial Officer | ||||
(Principal Financial Officer) | ||||
Date: May 11, 2009 | /s/ John R. Sult | |||
Senior Vice President and Controller | ||||
(Principal Accounting Officer) |
53
Table of Contents
EL PASO CORPORATION
EXHIBIT INDEX
EXHIBIT INDEX
Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
Exhibit | ||
Number | Description | |
4 | Fifteenth Supplemental Indenture, dated as of February 9, 2009 between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.I to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009). | |
*12 | Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. | |
*31.A | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*31.B | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*32.A | Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
*32.B | Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
54