|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|||||||||||||||||||
|
|
Note 1. General, Description of Business and Basis of Presentation
General
The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2011 in our Annual report on Form 10-K, as amended. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at March 31, 2012, results of operations for the three months ended March 31, 2012 and 2011, changes in equity for the three months ended March 31, 2012 and cash flows for the three months ended March 31, 2012 and 2011.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Description of Business
Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.
Domestic includes natural gas development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico, North Dakota and Wyoming) and Appalachian (Marcellus Shale) regions of the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Williston, Green River and Appalachian Basins. Associated with our commodity production are sales and marketing activities that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.
International primarily consists of our ownership in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with concessions primarily in Argentina.
The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company”, previously comprised substantially all of the exploration and production reportable segment of The Williams Companies, Inc. In these notes, WPX Energy, Inc. is at times referred to in the first person as “WPX”, “we”, “us” or “our”. The Williams Companies, Inc. and its affiliates, including Williams Partners L.P. (“WPZ”) are at times referred to collectively as “Williams”.
Separation from Williams
On February 16, 2011, Williams announced that its board of directors had approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. As a result, WPX Energy, Inc. was formed to effect the separation. On November 30, 2011, the Board of Directors of Williams approved the spin-off of the Company. The spin-off was completed by way of a distribution on December 31, 2011.
Basis of Presentation
These financial statements are prepared on a consolidated basis. Prior to the separation from Williams, the financial statements were derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the entities contributed to us.
Discontinued operations
During the first quarter of 2012, our Board of Directors approved an agreement for the sale of our holdings in the Barnett Shale and the Arkoma Basin. As these assets are (1) currently held for sale; (2) expected to be eliminated from our ongoing operations; and (3) we do not expect to have any significant continuing involvement; we have reported the results of operations and financial position of Barnett and Arkoma operations as discontinued operations. The results of operations and financial position of our Arkoma operations were reported as discontinued operations during 2011 as we initiated a formal process to pursue the divestiture of those operations in the first quarter of 2011.
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
|
Note 2. Discontinued Operations
Summarized Results of Discontinued Operations
During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin for $306 million, subject to closing adjustments. The sales price is in excess of our net book value for these properties. The buyer provided $31 million in cash as a deposit at the signing of the agreement. The Barnett Shale properties include approximately 27,000 net acres, interests in 320 wells and 91 miles of pipeline. The Arkoma properties include approximately 66,000 net acres, interests in 525 wells and 115 miles of pipeline. As part of the sales agreement, we entered into certain derivative contracts on behalf of the purchaser. As of March, 31, 2012, the mark-to-market value of these derivatives was a net liability of less than $1 million.
Three months ended March 31, | ||||||||
2012 | 2011 | |||||||
(Millions) | ||||||||
Revenues |
$ | 20 | $ | 30 | ||||
|
|
|
|
|||||
Loss from discontinued operations before impairments and income taxes |
$ | (2 | ) | $ | (2 | ) | ||
Impairments |
— | (11 | ) | |||||
Benefit for income taxes |
— | 5 | ||||||
|
|
|
|
|||||
Loss from discontinued operations |
$ | (2 | ) | $ | (8 | ) | ||
|
|
|
|
Impairments in 2011 reflect write-downs to estimates of fair value less costs to sell the assets of our Arkoma Basin operations that were classified as held for sale as of March 31, 2011. This nonrecurring fair value measurement, which falls within Level 3 of the fair value hierarchy, utilized a probability-weighted discounted cash flow analysis that was based on internal cash flow models.
The assets of our discontinued operations are approximately 3 percent of our total assets as of March 31, 2012 and December 31, 2011, and are reported in other current assets and other noncurrent assets, respectively, on our Consolidated Balance Sheet. Liabilities of our discontinued operations are less than one percent of total liabilities for the same periods and are reported in accrued and other current liabilities and other noncurrent liabilities, respectively.
|
Note 4. Impairments and Exploration Expenses
Impairment of cost of acquired unproved reserves
As a result of continued declines in forward natural gas prices since year-end 2011, we performed an impairment assessment of our capitalized cost of acquired unproved reserves. Accordingly, we recorded a $37 million impairment of capitalized costs of acquired unproved reserves in the Powder River Basin and a $15 million impairment of capitalized costs of acquired unproved reserves in the Piceance Basin. Our impairment analyses included an assessment of discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (See Note 9).
Exploration expenses
Three months ended March 31, | ||||||||
2012 | 2011 | |||||||
(Millions) | ||||||||
Geologic and geophysical costs |
$ | 7 | $ | 2 | ||||
Dry hole costs |
1 | — | ||||||
Unproved leasehold property impairment, amortization and expiration |
11 | 10 | ||||||
|
|
|
|
|||||
Total exploration expense |
$ | 19 | $ | 12 | ||||
|
|
|
|
|
Note 5. Inventories
March 31, 2012 |
December 31, 2011 |
|||||||
(Millions) | ||||||||
Natural gas in underground storage |
$ | 20 | $ | 34 | ||||
Material, supplies and other |
41 | 39 | ||||||
|
|
|
|
|||||
$ | 61 | $ | 73 | |||||
|
|
|
|
Due to lower natural gas prices, we recognized a lower of cost or market adjustment to natural gas in underground storage of approximately $11 million at March 31, 2012. This adjustment is reflected in gas management expense on the consolidated statement of operations for the three months ended March 31, 2012.
|
Note 6. Debt and Banking Arrangements
In November 2011 we issued $1.5 billion in face value Senior Notes. The Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the Notes were approximately $1.481 billion after deducting the initial purchasers’ discounts and our offering expenses. We retained $500 million of the net proceeds from the issuance of the Notes and distributed the remainder of the net proceeds from the issuance of the Notes, approximately $981 million, to Williams.
As part of the new issuance, we entered into a registration rights agreement whereby we agreed to offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing, to use commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities until we have successfully registered the securities. On April 24, 2012, we filed a registration statement, however, the registration statement is not yet effective.
During 2011 we entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. At March 31, 2012 there was no outstanding balance under the Credit Facility Agreement.
Letters of Credit
In addition to the Notes and Credit Facility Agreement, WPX has entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At March 31, 2012 a total of $278 million in letters of credit have been issued.
Other
Apco has a loan agreement with a financial institution for a $10 million bank line of credit. This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business and incur additional debt. As of March 31, 2012, Apco has borrowed $8 million under this banking agreement.
|
Note 7. Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes:
Three months ended March 31, | ||||||||
2012 | 2011 | |||||||
(Millions) | ||||||||
Provision (benefit): |
||||||||
Current: |
||||||||
Federal |
$ | 10 | $ | 6 | ||||
State |
— | 1 | ||||||
Foreign |
3 | 2 | ||||||
|
|
|
|
|||||
13 | 9 | |||||||
|
|
|
|
|||||
Deferred: |
||||||||
Federal |
(35 | ) | (5 | ) | ||||
State |
(3 | ) | (1 | ) | ||||
|
|
|
|
|||||
(38 | ) | (6 | ) | |||||
|
|
|
|
|||||
Total provision (benefit) |
$ | (25 | ) | $ | 3 | |||
|
|
|
|
The effective income tax rate on the total benefit for the three months ended March 31, 2012, is greater than the federal statutory rate due primarily to state income taxes and an adjustment to the minimum tax credit that was allocated to us by Williams as part of the spin-off, partially offset by taxes on foreign operations.
The effective income tax rate on the total provision for the three months ended March 31, 2011, is less than the federal statutory rate due primarily to taxes on foreign operations, partially offset by state income taxes.
As of March 31, 2012, the amount of unrecognized tax benefits is insignificant. During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of our unrecognized tax benefit.
|
Note 8. Contingent Liabilities
Royalty litigation
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for proceeds received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class for certification resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim is whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate litigating the second reserved claim in 2013. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims.
In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint alleges failure to pay royalty on hydrocarbons including drip condensate, fraud and misstatement of value of gas and affiliated sales, breach of duty to market hydrocarbons, violation of the New Mexico Oil and Gas Proceeds Payment Act, bad faith breach of contract and unjust enrichment. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production and payments and future reporting. This matter has been removed to the United States District Court for New Mexico. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.
Other producers have been in litigation with a federal regulatory agency and discussions with a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to those matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (“ONRR”) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states though such guidelines are expected in the future. However, the timing of any such guidance is uncertain. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments, and the effect could be material to our results of operations. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions, which we believe have been consistent with the requirements. From January 2004 through December 2011, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $74 million.
The New Mexico State Land Office Commissioner has filed suit against us in Santa Fe County alleging that we have underpaid royalties due per the oil and gas leases with the State of New Mexico. In August 2011, the parties agreed to stay this matter pending the New Mexico Supreme Court’s resolution of a similar matter involving a different producer. At this time, we do not have a sufficient basis to calculate an estimated range of exposure related to this claim.
Environmental matters
The Environmental Protection Agency (“EPA”) and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and hydraulic fracturing and water standards. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
Matters related to Williams’ former power business
In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.
California energy crisis
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the Federal Energy Regulatory Commission (“FERC”). We have entered into settlements with the State of California (State Settlement), major California utilities (“Utilities Settlement”), and others that substantially resolved each of these issues with these parties.
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California energy crisis. With respect to these matters, amounts accrued are not material to our financial position.
Certain other issues also remain open at the FERC and for other nonsettling parties.
Reporting of natural gas-related information to trade publications
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, seeking unspecified amounts of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. Because of the uncertainty around pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.
Other Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
At March 31, 2012, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
In connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.
Summary
As of March 31, 2012 and December 31, 2011, the Company had accrued approximately $19 million and $23 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.
Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
|
Note 9. Fair Value Measurements
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.
March 31, 2012 | December 31, 2011 | |||||||||||||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
(Millions) | (Millions) | |||||||||||||||||||||||||||||||
Energy derivative assets |
$ | 33 | $ | 501 | $ | 4 | $ | 538 | $ | 55 | $ | 454 | $ | 7 | $ | 516 | ||||||||||||||||
Energy derivative liabilities |
$ | 23 | $ | 155 | $ | 5 | $ | 183 | $ | 41 | $ | 112 | $ | 6 | $ | 159 |
Energy derivatives include commodity based exchange-traded contracts and over-the-counter (“OTC”) contracts. Exchange-traded contracts include futures, swaps and options. OTC contracts include forwards, swaps, options and swaptions.
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
Forward, swap and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil swaps entered into, we granted crude oil swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Significant inputs into our Level 2 valuations include commodity prices, implied volatility by location and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring in the next 12 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at March 31, 2012, consist primarily of natural gas index transactions that are used to manage our physical requirements.
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the periods ended March 31, 2012 and 2011. During the period ended March 31, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange-traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.
The following table presents a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
Three months ended March 31, | ||||||||
2012 Net Energy Derivatives |
2011 Net Energy Derivatives |
|||||||
(Millions) | ||||||||
Beginning balance |
$ | 1 | $ | 1 | ||||
Realized and unrealized gains (losses): |
||||||||
Included in income (loss) from continuing operations |
1 | 5 | ||||||
Settlements |
(3 | ) | (2 | ) | ||||
Transfers out of Level 3 |
— | (3 | ) | |||||
|
|
|
|
|||||
Ending balance |
$ | (1 | ) | $ | 1 | |||
|
|
|
|
|||||
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at March 31 |
$ | (1 | ) | $ | 3 | |||
|
|
|
|
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statement of Operations.
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
Total losses for the three months ended March 31, |
||||||||
2012 | 2011 | |||||||
(Millions) | ||||||||
Impairments: |
||||||||
Costs of acquired unproved reserves (see Note 4) |
$ | 52 | (a) | $ | — | |||
|
|
|
|
(a) | Due to significant declines in forward natural gas prices, we assessed the carrying value of our natural gas costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows including potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. |
• |
$37 million of the impairment charge related to acquired unproved reserves in the Powder River Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively. |
• |
$15 million of the impairment charge related to acquired unproved reserves in the Piceance Basin. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively. |
|
Note 10. Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk
We use the following methods and assumptions for financial instruments that require fair value disclosure.
Cash and cash equivalents and restricted cash: The carrying amounts reported in the Consolidated Balance Sheet approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
Other: Includes margin deposits and customer margin deposits payable for which the amounts reported in the Consolidated Balance Sheet approximate fair value given the short-term status of the instruments.
Long-term debt: The fair value of our debt is determined on market rates and the prices of similar securities with similar terms and credit ratings.
Energy derivatives: Energy derivatives include futures, forwards, swaps, options and swaptions. These are carried at fair value in the Consolidated Balance Sheet. See Note 9 for a discussion of valuation of energy derivatives.
Carrying amounts and fair values of our financial instruments were as follows:
March 31, 2012 | December 31, 2011 | |||||||||||||||
Asset (Liability) |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
(Millions) | ||||||||||||||||
Cash and cash equivalents |
$ | 362 | $ | 362 | $ | 526 | $ | 526 | ||||||||
Restricted cash (current and noncurrent) |
29 | 29 | 29 | 29 | ||||||||||||
Other |
— | — | (7 | ) | (7 | ) | ||||||||||
Long-term debt (a) |
1,508 | 1,501 | 1,502 | 1,523 | ||||||||||||
Net energy derivatives: |
||||||||||||||||
Energy commodity cash flow hedges |
343 | 343 | 347 | 347 | ||||||||||||
Other energy derivatives |
12 | 12 | 10 | 10 |
(a) | Excludes capital leases. |
Energy Commodity Derivatives
Risk Management Activities
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas, natural gas liquids and crude oil attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
We produce, buy and sell natural gas, natural gas liquids and crude oil at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of natural gas, natural gas liquids and crude oil. We have also entered into basis swap agreements to reduce the locational price risk associated with our natural gas producing basins. Those agreements and contracts designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Our financial option contracts are purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions. Our designation of the hedging relationship and method of assessing effectiveness for these option contracts are generally such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings.
The following table sets forth the derivative volumes designated as hedges of production volumes as of March 31, 2012:
Commodity |
Period | Contract Type | Location | Notional Volume (BBtu/day) |
Weighted Average Price ($/MMBtu) |
|||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | Rockies | 135 | $ | 4.76 | ||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | San Juan | 110 | $ | 4.94 | ||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | MidCon | 65 | $ | 4.74 | ||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | SoCal | 33 | $ | 5.14 | ||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | Northeast | 143 | $ | 5.54 | ||||||||
Natural Gas |
2013 | Location Swaps | Northeast | 5 | $ | 6.48 |
Commodity |
Period | Contract Type | Location | Notional Volume (Bbls/day) |
Weighted Average Price ($/Bbl) |
|||||||||||||
Crude Oil |
Apr – Dec 2012 | Business Day Avg Swaps | WTI | 7,556 | $ | 97.56 |
The following table sets forth the derivative volumes not designated as hedges of production volumes as of March 31, 2012:
Commodity |
Period | Contract Type | Location | Notional Volume (BBtu/day) |
Weighted Average Price ($/MMBtu) |
|||||||||||||||
Natural Gas |
Apr – Dec 2012 | Location Swaps | MidCon | 23 | $ | 4.80 |
Commodity |
Period | Contract Type | Location | Notional Volume (Bbls/day) |
Weighted Average Price ($/Bbl) |
|||||||||
Crude Oil |
Apr – Dec 2012 | Business Day Avg Swaps | WTI | 331 | $ | 108.00 | ||||||||
Crude Oil |
Apr – Dec 2012 | Swaption | WTI | 778 | $ | 108.00 | ||||||||
Crude Oil |
Apr – Dec 2012 | Costless Collar | WTI | 2,000 | $ | 85.00/$106.30 | ||||||||
Crude Oil |
2013 | Business Day Avg Swaps | WTI | 6,000 | $ | 97.28 |
Commodity |
Period | Contract Type | Location | Notional Volume (Bbls/day) |
Weighted Average Price ($Bbl) |
|||||||||||||||
Natural Gas Liquids |
Apr – Dec 2012 | Swaps | Mont Belvieu | 4,000 | $ | 50.74 |
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk associated with these contracts. Derivatives for transportation and storage contracts have not been designated as hedging instruments, despite economically hedging the expected cash flows generated by those agreements.
We also enter into energy commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties and affiliated entities. These legacy natural gas contracts include substantially offsetting positions and have had an insignificant net impact on earnings.
The following table depicts the notional amounts of the net long (short) positions which do not represent hedges of our production in our commodity derivatives portfolio as of March 31, 2012. Natural gas is presented in millions of British Thermal Units (“MMBtu”). All of the Central hub risk realizes by March 31, 2013 and 83% of the basis risk realizes by 2013. The net index position includes contracts for the future sale of physical natural gas related to our production. Offsetting these sales are contracts for the future production of physical natural gas related to WPZ’s natural gas shrink requirements. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at March 31, 2012.
Derivative Notional Volumes |
Unit of Measure |
Central Hub Risk (a) |
Basis Risk (b) |
Index Risk (c) |
||||||||||||
Not Designated as Hedging Instruments |
||||||||||||||||
Risk Management |
MMBtu | (14,137,000 | ) | (11,588,310 | ) | (59,196,902 | ) | |||||||||
Other |
MMBtu | 50,000 | (1,070,000 | ) |
(a) | Includes physical and financial derivative transactions that settle against the Henry Hub price. |
(b) | Includes physical and financial derivative transactions priced off the difference in value between the Central Hub and another specific delivery point. |
(c) | Includes physical derivative transactions at an unknown future price, including purchases of 45,114,058 MMBtu primarily on behalf of WPZ and sales of 104,310,960 MMBtu. |
Fair values and gains (losses)
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Consolidated Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
March 31, 2012 | December 31, 2011 | |||||||||||||||
Assets | Liabilities | Assets | Liabilities | |||||||||||||
(Millions) | ||||||||||||||||
Designated as hedging instruments |
$ | 363 | $ | 20 | $ | 360 | $ | 13 | ||||||||
Not designated as hedging instruments: |
||||||||||||||||
Legacy natural gas contracts from former power business |
117 | 117 | 93 | 92 | ||||||||||||
All other |
58 | 46 | 63 | 54 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives not designated as hedging instruments |
175 | 163 | 156 | 146 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total derivatives |
$ | 538 | $ | 183 | $ | 516 | $ | 159 | ||||||||
|
|
|
|
|
|
|
|
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (“AOCI”) or revenues.
Three months ended March 31, |
||||||||||
2012 | 2011 | Classification | ||||||||
(Millions) | ||||||||||
Net gain (loss) recognized in other comprehensive income (loss) (effective portion) |
$ | 102 | $ | (20 | ) | AOCI | ||||
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a) |
$ | 106 | $ | 75 | Revenues | |||||
Loss recognized in income (ineffective portion) |
$ | (1 | ) | $ | (1 | ) | Revenues |
(a) | Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in natural gas sales and oil and condensate sales. |
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.
Three months ended March 31, |
||||||||
2012 | 2011 | |||||||
(Millions) | ||||||||
Revenues |
$ | 14 | $ | 3 | ||||
Expenses |
— | — | ||||||
|
|
|
|
|||||
Net gain |
$ | 14 | $ | 3 | ||||
|
|
|
|
The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities.
Credit-risk-related features
Certain of our derivative contracts contain credit-risk-related provisions that would require us, under certain events, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investment Services. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.
As of March 31, 2012, we had a net derivative liability position of $31 million, which includes a liability credit reserve for our own nonperformance risk of less than $1 million. The collateral that we would be required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts were triggered, was $15 million.
Cash flow hedges
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. During March 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in mark to market gains and losses and hedge ineffectiveness on the consolidated statement of operations for the three months ended March 31, 2012. As of March 31, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to twelve months. Based on recorded values at March 31, 2012, $218 million of net gains (net of income tax provision of $126 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of March 31, 2012. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
Concentration of Credit Risk
Derivative assets and liabilities
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2012 and 2011 we did not incur any significant losses due to counterparty bankruptcy filings.
The gross credit exposure from our derivative contracts as of March 31, 2012, is summarized as follows.
Counterparty Type |
Investment Grade (a) |
Total | ||||||
(Millions) | ||||||||
Gas and electric utilities and integrated oil and gas companies |
$ | 1 | $ | 1 | ||||
Energy marketers and traders |
— | 78 | ||||||
Financial institutions |
459 | 459 | ||||||
|
|
|
|
|||||
$ | 460 | 538 | ||||||
|
|
|
|
|||||
Credit reserves |
— | |||||||
|
|
|||||||
Gross credit exposure from derivatives |
$ | 538 | ||||||
|
|
(a) | We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of March 31, 2012, excluding collateral support discussed below, is summarized as follows.
Counterparty Type |
Investment Grade (a) |
Total | ||||||
(Millions) | ||||||||
Gas and electric utilities |
$ | — | $ | — | ||||
Energy marketers and traders |
— | 2 | ||||||
Financial institutions |
384 | 384 | ||||||
|
|
|
|
|||||
$ | 384 | 386 | ||||||
|
|
|
|
|||||
Credit reserves |
— | |||||||
|
|
|||||||
Net credit exposure from derivatives |
$ | 386 | ||||||
|
|
(a) | We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade. |
Our eight largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our new marginless hedging agreements with key banks, we nor the participating financial institutions are required to provide collateral support related to hedging activities.
At March 31, 2012, we did not hold collateral support, either in the form of cash or letters of credit, related to our other derivative positions.
|
Note 11. Segment Disclosures
Our reporting segments are domestic and international (See Note 1).
Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.
The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statement of Operations.
For the three months ended March 31, 2012 | Domestic | International | Total | |||||||||
(Millions) | ||||||||||||
Total revenues |
$ | 879 | $ | 31 | $ | 910 | ||||||
|
|
|
|
|
|
|||||||
Costs and expenses: |
||||||||||||
Lease and facility operating |
$ | 61 | $ | 6 | $ | 67 | ||||||
Gathering, processing and transportation |
135 | — | 135 | |||||||||
Taxes other than income |
25 | 5 | 30 | |||||||||
Gas management, including charges for unutilized pipeline capacity |
355 | — | 355 | |||||||||
Exploration |
14 | 5 | 19 | |||||||||
Depreciation, depletion and amortization |
222 | 6 | 228 | |||||||||
Impairment of costs of acquired unproved reserves |
52 | — | 52 | |||||||||
General and administrative |
65 | 3 | 68 | |||||||||
Other—net |
5 | — | 5 | |||||||||
|
|
|
|
|
|
|||||||
Total costs and expenses |
$ | 934 | $ | 25 | $ | 959 | ||||||
|
|
|
|
|
|
|||||||
Operating income (loss) |
$ | (55 | ) | $ | 6 | $ | (49 | ) | ||||
Interest expense |
(26 | ) | — | (26 | ) | |||||||
Interest capitalized |
2 | — | 2 | |||||||||
Investment income and other |
2 | 8 | 10 | |||||||||
|
|
|
|
|
|
|||||||
Income (loss) from continuing operations before income taxes |
$ | (77 | ) | $ | 14 | $ | (63 | ) | ||||
|
|
|
|
|
|
|||||||
For the three months ended March 31, 2011 | ||||||||||||
Total revenues |
$ | 934 | $ | 24 | $ | 958 | ||||||
|
|
|
|
|
|
|||||||
Costs and expenses: |
||||||||||||
Lease and facility operating |
$ | 58 | $ | 5 | $ | 63 | ||||||
Gathering, processing and transportation |
112 | — | 112 | |||||||||
Taxes other than income |
27 | 3 | 30 | |||||||||
Gas management, including charges for unutilized pipeline capacity |
417 | — | 417 | |||||||||
Exploration |
11 | 1 | 12 | |||||||||
Depreciation, depletion and amortization |
202 | 5 | 207 | |||||||||
General and administrative |
64 | 3 | 67 | |||||||||
Other—net |
— | 1 | 1 | |||||||||
|
|
|
|
|
|
|||||||
Total costs and expenses |
$ | 891 | $ | 18 | $ | 909 | ||||||
|
|
|
|
|
|
|||||||
Operating income |
$ | 43 | $ | 6 | $ | 49 | ||||||
Interest expense |
(49 | ) | — | (49 | ) | |||||||
Interest capitalized |
4 | — | 4 | |||||||||
Investment income and other |
1 | 5 | 6 | |||||||||
|
|
|
|
|
|
|||||||
Income (loss) from continuing operations before income taxes |
$ | (1 | ) | $ | 11 | $ | 10 | |||||
|
|
|
|
|
|
|||||||
Total assets |
||||||||||||
Total assets as of March 31, 2012 |
$ | 9,957 | $ | 312 | $ | 10,269 | ||||||
|
|
|
|
|
|
|||||||
Total assets as of December 31, 2011 |
$ | 10,144 | $ | 288 | $ | 10,432 | ||||||
|
|
|
|
|
|