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PXP > SEC Filings for PXP > Form 10-Q on 2-Aug-2012All Recent SEC Filings

Show all filings for PLAINS EXPLORATION & PRODUCTION CO

Form 10-Q for PLAINS EXPLORATION & PRODUCTION CO


2-Aug-2012

Quarterly Report


ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2011.

Company Overview

We are an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:

Onshore California;

Offshore California;

the Gulf Coast Region;

the Gulf of Mexico; and

the Rocky Mountains.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.

Our assets include 51.0 million shares of McMoRan common stock, approximately 31.6% of its common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk - Equity Price Risk.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use various derivative instruments to manage our exposure to commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our income statement as changes occur in the NYMEX and ICE price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.


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Recent Developments

Debt Offering and Redemptions

In April 2012, we issued $750 million of 6 1/8% Senior Notes at par. We received approximately $737.5 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes, including the redemption of $79.3 million aggregate principal amount of our 7 3/4% Senior Notes and $76.9 million aggregate principal amount of our 7% Senior Notes.

During the second quarter of 2012, we made payments totaling $80.8 million and $79.6 million to retire the 7 3/4% Senior Notes and the 7% Senior Notes, respectively. In connection with the retirement of the 7 3/4% Senior Notes and the 7% Senior Notes, we recorded $5.2 million of debt extinguishment costs.

Derivatives

During the second quarter of 2012, we entered into Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.594 per barrel. Additionally, we entered into natural gas swap contracts on 80,000 MMBtu per day for 2012 with an average price of $2.72 per MMBtu.

General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. The markets for oil and gas have historically been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC's full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the twelve-month average first-day-of-the-month reference prices as adjusted for location and quality differentials to determine a ceiling value of our properties. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have in place are not classified as hedges for accounting purposes. The rules require an impairment if our capitalized costs exceed the allowed "ceiling". At June 30, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 28%.


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Given the volatility of oil and gas prices, it is likely that our estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities. As of July 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas declined from $3.15 per MMBtu at June 30, 2012 to $3.02 per MMBtu and the comparable price for oil declined from $95.67 per Bbl at June 30, 2012 to $94.84 per Bbl.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock-based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, gathering and transportation costs and other costs necessary to operate our producing properties. DD&A for producing oil and gas properties is calculated using the units of production method based upon estimated proved reserves. For the purposes of computing DD&A, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

G&A consists primarily of salaries and related benefits of administrative personnel (including stock-based compensation), office rent, systems costs and other administrative costs.

Results Overview

For the six months ended June 30, 2012, we reported net income attributable to common stockholders of $140.9 million, or $1.07 per diluted share, compared to net income of $195.9 million, or $1.37 per diluted share, for the six months ended June 30, 2011. The decrease primarily reflects a loss on our investment in McMoRan measured at fair value, increased DD&A and lower gas revenues partially offset by higher oil revenues and a gain on mark-to-market derivative contracts. Significant transactions that affect comparisons between the periods include the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011.


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Results of Operations

The following table reflects the components of our oil and gas production and
sales prices and sets forth our operating revenues and costs and expenses on a
BOE basis:




                                      Three Months Ended               Six Months Ended
                                           June 30,                        June 30,
                                     2012            2011            2012            2011
Sales Volumes
Oil and liquids sales (MBbls)           5,440           4,416           9,959           8,382
Gas (MMcf)
Production                             21,398          27,405          42,692          51,635
Used as fuel                              346             534             774           1,055
Sales                                  21,052          26,871          41,918          50,580
MBOE
Production                              9,006           8,984          17,074          16,988
Sales                                   8,949           8,894          16,945          16,812
Daily Average Volumes
Oil and liquids sales (Bbls)           59,780          48,524          54,718          46,308
Gas (Mcf)
Production                            235,142         301,162         234,572         285,280
Used as fuel                            3,804           5,874           4,255           5,831
Sales                                 231,338         295,288         230,317         279,449
BOE
Production                             98,970          98,718          93,814          93,855
Sales                                  98,336          97,739          93,105          92,883
Unit Economics (in dollars)
Average Index Prices
ICE Brent Price per Bbl           $    108.73     $    116.89     $    113.57     $    111.20
NYMEX Price per Bbl                     93.35          102.34           98.15           98.50
NYMEX Price per Mcf                      2.22            4.32            2.47            4.20
Average Realized Sales Price
Before Derivative Transactions
Oil (per Bbl)                     $     95.50     $     90.42     $     99.11     $     87.23
Gas (per Mcf)                            2.18            4.23            2.37            4.16
Per BOE                                 63.19           57.68           64.12           56.01
Costs and Expenses per BOE
Production costs
Lease operating expenses          $      9.80     $      9.23     $     10.07     $      9.19
Steam gas costs                          1.09            1.90            1.23            1.94
Electricity                              1.20            1.17            1.31            1.20
Production and ad valorem taxes          2.13            1.90            1.87            1.69
Gathering and transportation             2.13            1.89            2.08            1.76
DD&A (oil and gas properties)           27.21           16.28           24.58           16.28

The following table reflects cash (payments) receipts made with respect to derivative contracts during the periods presented (in thousands):

                                 Three Months Ended                  Six Months Ended
                                      June 30,                           June 30,
                               2012             2011              2012              2011
 Oil derivatives            $  (7,191)       $  (15,018)       $  (13,047)       $  (30,659)
 Natural gas derivatives        15,732                 -            30,909               620

                            $    8,541       $  (15,018)       $    17,862       $  (30,039)


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Comparison of Three Months Ended June 30, 2012 to Three Months Ended June 30, 2011

Oil and gas revenues. Oil and gas revenues increased $52.5 million, to $565.5 million for 2012 from $513.0 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $120.2 million, to $519.5 million for 2012 from $399.3 million for 2011, reflecting higher sales volumes ($97.8 million) and higher average realized prices ($22.4 million). Oil sales volumes increased 11.3 MBbls per day to 59.8 MBbls per day in 2012 from 48.5 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 17.2 MBbls per day in 2012. Our average realized price for oil increased $5.08 per Bbl to $95.50 per Bbl for 2012 from $90.42 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $108.73 per Bbl compared to the average NYMEX index price of $102.34 per Bbl for 2011.

Gas revenues decreased $67.7 million, to $46.0 million in 2012 from $113.7 million in 2011, primarily reflecting lower average realized prices ($55.0 million) and lower sales volumes ($12.7 million). Our average realized price for gas was $2.18 per Mcf in 2012 compared to $4.23 per Mcf in 2011. Gas sales volumes decreased 64.0 MMcf per day to 231.3 MMcf per day in 2012 from
295.3 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 17.8 MMcf per day in 2012.

Lease operating expenses. Lease operating expenses increased $5.6 million, to $87.7 million in 2012 from $82.1 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties and repairs and maintenance primarily at our California properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs. Steam gas costs decreased $7.2 million, to $9.7 million in 2012 from $16.9 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.0 Bcf of natural gas at a cost of approximately $2.41 per MMBtu compared to 4.1 Bcf at a cost of approximately $4.13 per MMBtu in 2011.

Production and ad valorem taxes. Production and ad valorem taxes increased $2.2 million, to $19.1 million in 2012 from $16.9 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expense. Gathering and transportation expenses increased $2.2 million, to $19.0 million in 2012 from $16.8 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.


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Depreciation, depletion and amortization. DD&A expense increased $99.9 million, to $250.7 million in 2012 from $150.8 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($98.2 million). Our oil and gas unit of production rate increased to $27.21 per BOE in 2012 compared to $16.28 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense. Interest expense increased $15.8 million, to $53.0 million in 2012 from $37.2 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $15.2 million and $33.5 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

Gain (loss) on mark-to-market derivative contracts. The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $221.8 million gain related to mark-to-market derivative contracts in the second quarter of 2012, which was primarily associated with an increase in the fair value of our crude oil derivative contracts due to decreased forward prices. In the second quarter of 2011, we recognized a $18.9 million gain related to mark-to-market derivative contracts.

Gain (loss) on investment measured at fair value. At June 30, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as gain on investment measured at fair value in our income statement.

We recognized an $86.8 million gain in the second quarter of 2012 related to our McMoRan investment, which was primarily associated with an increase in McMoRan's stock price. In the second quarter of 2011, we recognized a $43.3 million gain related to our McMoRan investment.

Income taxes. For the three months ended June 30, 2012 and 2011, our income tax expense was approximately 40% and 41% of pre-tax income, respectively. The variance between these effective tax rates and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and
(ii) state income taxes.


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Comparison of Six Months Ended June 30, 2012 to Six Months Ended June 30, 2011

Oil and gas revenues. Oil and gas revenues increased $144.9 million, to $1.1 billion for 2012 from $941.6 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $255.9 million, to $987.0 million for 2012 from $731.1 million for 2011, reflecting higher sales volumes ($156.3 million) and higher average realized prices ($99.6 million). Oil sales volumes increased 8.4 MBbls per day to 54.7 MBbls per day in 2012 from 46.3 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 13.4 MBbls per day in 2012. Our average realized price for oil increased $11.88 per Bbl to $99.11 per Bbl for 2012 from $87.23 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $113.57 per Bbl compared to the average NYMEX index price of $98.50 per Bbl for 2011.

Gas revenues decreased $111.0 million, to $99.5 million in 2012 from $210.5 million in 2011, primarily reflecting lower average realized prices ($90.4 million) and lower sales volumes ($20.6 million). Our average realized price for gas was $2.37 per Mcf in 2012 compared to $4.16 per Mcf in 2011. Gas sales volumes decreased 49.1 MMcf per day to 230.3 MMcf per day in 2012 from
279.4 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 23.1 MMcf per day in 2012.

Lease operating expenses. Lease operating expenses increased $16.3 million, to $170.7 million in 2012 from $154.4 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties and higher well workovers and repairs and maintenance primarily at our California properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs. Steam gas costs decreased $11.8 million, to $20.8 million in 2012 from $32.6 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 8.0 Bcf of natural gas at a cost of approximately $2.59 per MMBtu compared to 8.1 Bcf at a cost of approximately $4.01 per MMBtu in 2011.

Production and ad valorem taxes. Production and ad valorem taxes increased $3.3 million, to $31.7 million in 2012 from $28.4 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expenses. Gathering and transportation expenses increased $5.7 million, to $35.3 million in 2012 from $29.6 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Haynesville Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.


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Depreciation, depletion and amortization. DD&A expense increased $143.1 million, to $428.4 million in 2012 from $285.3 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($141.0 million). Our oil and gas unit of production rate was $24.58 per BOE in 2012 compared to $16.28 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense. Interest expense increased $28.6 million, to $98.2 million in 2012 from $69.6 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $32.3 million and $64.6 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

Gain (loss) on mark-to-market derivative contracts. The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $112.7 million gain related to mark-to-market derivative contracts in the six months ended June 30, 2012, which was primarily associated with an increase in the fair value of our crude oil and natural gas derivative contracts due to decreased forward prices. In the six months ended June 30, 2011, we recognized a $32.1 million loss related to mark-to-market derivative contracts.

Gain (loss) on investment measured at fair value. At June 30, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain or loss on investment measured at fair value in our income statement.

We recognized a $49.2 million loss in the six months ended June 30, 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan's stock price. In the six months ended June 30, 2011, we recognized a $110.6 million gain related to our McMoRan investment.

Income taxes. For the six months ended June 30, 2012 and 2011, our income tax expense was approximately 41% of pre-tax income. The variance between these effective tax rates and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes.


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Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to these agreements. These situations may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. Volatility and disruption in the financial and credit markets may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers, including those counterparties who may have exposure to certain European sovereign debt. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.

Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. At June 30, 2012, we had approximately $1.1 billion available for future secured borrowings under our senior revolving credit facility, which had commitments and a borrowing base of $1.4 billion and approximately $2.3 billion, respectively. At June 30, 2012, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

Under the terms of our senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination and adjusted based on . . .

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